# Gt"'l® Unned States EnvifonmentalProtection Agency 

# _oEPA Research and ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::uDeveIo

# pm e n

# t**=========-1\~Au** URAL GAS INDUSTRY Volume 8: Equipment Leaks 

# Prepared for
Energy Information Administration (U.S. DOE)


# Prepared 

# by National Risk Management --------Research Laboratory Research Triangle Park, NC 27711 GRI-94/ 0257.25 EPA· 600/R-96-0BOh

ne 1996



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### FOREWORD The U.S. Environmental Protection 

### Agency is charged by Congress with protecting the Nation's land. air. anC water resources. Under a mandate of national environmental laws, the Agency strives to formulate and implement actions leading to a compatible

**balar.~e** 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

### ble-ms today and building a science knowledge base necessary to manage our ecological resources wisely, understand how pollutants affect our health. and pre

### vent or reduce environmental risks in 

### the future. The National Risk Management Research Laboratory is the Agency's center for investigation of 

### technological and management approaches for reducing risks from threats to human health and the environment. The focus of the Laboratory's research program is on methods for the prevention and control of pollution 

### to air, land. water. and subsurface resources; protection of water quality in public water systems; remediation of contaminated sites and groundwater: and prevention and control of indoor air pollution. The goal of this research effort is to catalyze development and implementation of innovative. cost-effective environmental technologies; develop scientific and engineering information needed by EPA to support regulatory and policy decisions; and provide technical support and infOr

### mation transfer to ensure effective implementation of environmental regulations and strategies. This publication has been produced as part of the Laboratory1

### s strategic longterm research plan. It 

### is published and made available by EPA's Office of Research and Develo?ment 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 peerand administratively reviewed bythe U.S. Environmental Protection Agency, and approved for publication. Mention of trade names or commercial products does notconstitute endorsementorrecommendation foruse. This document isavailableto the public through the National Technical Information Service, Springfield, Virginia 22161.

### METHANE EMISSIONS FROM THE NATURAL GAS INDUSTRY, VOLUMES: EQmPMENTLEAKS FINAL REPORT

Prepared by: Kirk 

### E. Hummel Lisa M. Campbell 

### Matthew R. Harrison Radian International LLC

8501 N. Mopac Blvd. P.O. Box 20!088 Austin, TX 78720-!088

DCN: 95-263-081-12 For 

### GRI Project Manager: Robert A. 

### Lott GAS RESEARCH INSTITUTE

Contract No. 5091-251-2171 8600 West Bryn Mawr Ave. Chicago, IL 6063I 

### and 

# CRI-9t.f/o;;s7.

# ;zsEPA-6ooiR- S6-C8Ch June 

### 1996



### EPA Project Manager: David A. Kirchgessner U.S. ENVIRONMENTAL PROTECTION AGENCY Contract No. 68-Dl-0031 

### National Risk Management Research Laboratory Research Triangle Park, NC 27711

### DISCLAIMER LEGAL NOTICE: This report was prepared by Radian International LLC as an account ofwork sponsored by Gas Research Institute (GRI) and the U.S. Environmental Protection Agency (EPA). Neither EPA, GRI, Members ofGR!, nor any person acting on behalfof either:

a. Makes any warranty or representation, express or implied, with 

### respect to the accuracy, completeness, or usefulness ofthe infonnation contained in this report, or that the use 

### ofany apparatus, method, or process disclosed in this report may not infringe privately owned rights; or b. Asswnes any liability with respect to the use of, or for damages resulting from the 

### use of, any infonnation, apparatus, method, or process disclosed in this report. NOTE: EPA's Office ofResearch and Development quality assurance/quality control 

### (QNQC) requirements are applicable to some ofthe count data generated 

### by this project. Emission data and additional count 

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

### EPAIORD's QA!QC policies. In all cases, data and results were reviewed by 

### the panel ofexperts listed in Appendix D ofVolume 2.

IITitle
Contractor
Principal Investigators Report Period Objective

Technical Perspective



### Results 

### RESEARCH SUMMARY Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks Final Report Radian International LLC GRI Contract Number 5091-251-2171 EPA Contract Number 68-D1-0031 Kirk E. Hummel Lisa 

### M. Campbell Matthew R. Harrison March 1991 -June 1996 Final Report This report describes the approach used to quantify the annual methane emission from equipment leaks using the component method. 

### It includes equipment leaks from .gas production, gas processing, transmission, storage, and customer meters. The increased use ofnatural gas has been suggested as a strategy for reducing the potential for global warming. During combustion, natural gas generates less carbon dioxide (C02) per unit ofenergy produced than 

### either coal or oil. On the basis ofthe amount ofC02 

### emitted, the potential for global warming could be reduced by substituting natural gas for coal or oil. However, since natural 

### gas is primarily methane, a potent greenhouse gas, losses ofnatural gas during production, 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 (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 determine the relative impact on global warming ofnatural gas versus coal and oil. The national annual emissions from equipment leaks are: 17.4 Bscffor production; 24.4 Bscf for gas processing; 50.7 Bscf for transmission; 16.8 Bscf for gas storage; and 5.8 Bscffor customer meters.

111

### Technical Approach Based on data from the entire program, methane emissions from natural 

### gas **operation~** 

### are estimated to be 314 

### ± 105 Bscf for the 1992 base year. This is about 1.4 

### ± 0.5% ofgross natural gas production. This study also showed that the percentage ofmethane emitted for an incremental increase in natural gas sales would be significantly lower than the baseline case. The project reached 

### it accuracy goals and provided an accurate methane 

### emissions estimate that 

### can be used in fuel switching analyses. In the component method for estimating emissions from equipment leaks, 

### an average emission factor is determined for each ofthe basic components, such as valves, flanges, seals, and other connectors that comprise a facility. The component emission factor, determined from measured data, is combined with the average number ofcomponents comprising the facility to estimate average facility emissions. The average facility emissions are extrapolated 

### to a national estimate by the number offacilities within the gas industry. Two approaches were used to quantify component emission factors for each segment ofthe industry. The first approach. based on EPA's protocol for fugitive emissions estimation, involves screening components using a portable instrument to detect total hydrocarbon leaks. The corresponding screening value for a component is then converted to an emission rate by using a correlation equation developed from data collected using an enclosure method. The EPA protocol approach was used to quantify component emission factors for onshore production (excluding the Atlantic and Great Lakes region), offshore production, and gas processing. The second approach used to 

### quantify emissions from equipment components is a modification ofthe EPA protocol using the GRI HiFlownr (trademark ofGas Research Institute) sampler or a direct flow measurement to replace the data collected using an enclosure method. The 

### GRI Hi-Flow sampler is a newly developed device which allows the leak rate ofa component to be measured directly. The GRI Hi-Flow sampler approach was used to 

### quantifY component emission factors foi" onshore production in the Atlantic and Great Lakes region, gas transmission and storage facilities, and customer meter sets. Component counts for all segments were estimated based on data collected during the measurement programs, site visits, and site surveys.

iv

### Project Implications For the I992 base year, the annual methane emissions estimate for the U.S. natural gas industry is 314 Bscf

### ± 105 Bscf 

### (± 33%). This is equivalent to 1.4% 

### ± 0.5% 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 warming potentials (GWPs) recently published by the Intergovernmental Panel on Climate Change (JPCC). The analysis showed that natural gas contributes less to potential global warming than coal or oil, which supports the fuel switching strategy suggested by JPCC and others. In addition, results from this study are being used by the natural gas industry to reduce operating costs while reducing emissions. Some companies are also participating in the Natural Gas-Star program, a voluntary program sponsored by EPA's Office ofAir and Radiation in cooperation with the American Gas Association to implement costeffective emission reductions and to report reductions to EPA. Since this program was begun after the I992 baseline year, any reductions in methane emissions from this program are not reflected in this study's tota1 emissions.
Robert A. 

### Lott Senior Project Manager, Environment and Safety

v

### TABLE OF CONTENTS Page 

### 1.0 SUMMARY ................................................. I 2.0 INTRODUCTION ............................................. 3 3.0 EMISSION FACTOR METHODOLOGY ............................. 5 3.I EPA Protocol Approach
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 3.!.1 Compcnent Screening ................................ 6 3.!.2 Enclosure Method/Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 3.1.3 Correlation Equation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 

### 3.!.4 Pegged Source Emission Factors
. . . . . . . . . . . . . . . . . . . . . . . . 19 3.1.5 Default Zero Emission Factors . . . . . . . . . . . . . . . . . . . . . . . . . 22 

### 3.2 Alternative Approach Using the GRI Hi-Flow"' Sampler ............ 22 4.0 AVERAGE EMISSIONS FROM EQUIPMENT AND FACILITIES ......... 26 4.1 Onshore Gas Production ................................... 28 4.1.1 Onshore Production in the Eastern U.S. Region ............. 28 4.1.2 Onshore Production in the Western U.S. Region ,. ............ 34 

### 4.2 Offshore Gas Production .................................. 37 4.3 Gas Processing .......................................... 42 4.4 Transmission Compressor Stations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 

### 4.4.1 Station Components
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 4.4.2 Compressor-Related Components . . . . . . . . . . . . . . . . . . . . . . . 53 4.5 Gas Storage Facilities ..................................... 61 

### 4.5.1 Station Compcnents
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 4.5.2 Compressor-Related Components . . . . . . . . . . . . . . . . . . . . . . . 67 4.5.3 Injection/Withdrawal Wellhead-Related Components . . . . . . . . . . 67 4.6 Customer Meter Sets
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 

### 5.0 NATIONAL EMISSIONS FROM EQUIPMENT AND FACILITIES ........ 72 5.1 Onshore Gas Production ................................... 72 5.2 Offshore Gas Production .................................. 75 5.3 Gas Processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 5.4 Transmission Compressor Stations ............................ 77 5.5 Gas Storage Facilities ..................................... 78 5.6 Customer Meter Sets
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 

### 6.0 REFERENCES .............................................. 82
VI

### TABLE OF CONTENTS (Continued) Page APPENDIX A - Compressor Slowdown Operating Practices A-1 

### APPENDIX B - Source Sheets
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1 APPENDIX C - Conversion Table ................................ C-1

VII

### LIST OF FIGURES Page 

### 1-1 Summary ofEquipment Leaks Using Component Method . . . . . . . . . . . . . . . . . 2 3-I Overview ofEPA Protocol
. . . . . . . . . . . . . . . . . . . ................... 7 3-2 Conventional Gate Valve ........................................ 9 3-3 Manual Globe Valve .......................................... 

### !0 3-4 Plug Valve ................................................. 1 I 3-5 Ball Valve ................................................. 12 3-6 Threaded and Flanged Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 3-7 Pressure ReliefValve
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 3-8 Open-Ended Line .......... : . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 3-9 Screening Instruments ......................................... 16 

### 3-!0 Sampling Train for Bagging a Source Using the Vacuum Method ........... 18 3-11 Scatter Plot ofBagging Data and Correlation Equation .................. 20 4-1 Illustration ofCompressor Slowdown Valve Arrangement ................ 55 4-2 Overhung and Beam-Type Centrifugal Compressors ... , . . . . . . . . . . . . . . . . 62

viii

### LIST OF TABLES 

### Page 3-1 Correlation Equations Developed by 

### EPA . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 

### 3-2 Default Zero and Pegged Emission Factors Developed by 

### EPA . . . . . . . . . . . . . 23 4-1 Equipment Categories by 

### Segment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 4-2 Equipment Leak Measurement Programs ............................ 29 4-3 Component Emission Factors for Eastern U.S. Gas Production
. . . . . . . . . . . . . 31 4-4 Average Component

**Co~ts** 

### for Gas Production Equipment in the Eastern U.S. . 32 4-5 Average Equipment Emissions for Onshore Production in the Eastern U.S. . . . . 33 4-6 Component Emission Factors for Onshore Production in the Western U.S. . . . . . 35 4-7 Average Component Counts for Onshore Production in the Western U.S....... 36 4-8 Average Equipment Emissions for Onshore Production in the Western U.S..... 38 4-9 Average Component Emission Factors for Offshore Gas Production ....... -. . 40 4-10 Average Component Counts for Offshore Gas Production Equipment ........ 41 4-11 Average Facility Emissions for Offshore Production .................... 43 4-12 Component Emission Factors for Gas Processing
. . . . . . . . . . . . . . . . . . . . . . 45 4-13 Average Component Counts for Gas Processing Equipment
. . . . . . . . . . . . . . . 4 7 4-14 Average Facility Emissions for Gas Processing Plants ................... 48 4-15 Component Emission Factors for Transmission ........................ 50 4-16 Average Component Counts for Transmission ......................... 51 4-17 Average Facility Emissions for Transmission ......................... 52 4-I 8 Breakdown ofCompressor Emissions 

### by Component Type . . . . . . . . . . . . . . . . 53

IX

### LIST OF TABLES (Continued) Page 4-19 Average Emission Rates for Compressor Slowdown Valves in Pressurized/ Depressurized Operation
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 4-20 Operating Modes ofCompressors in Gas Transmission .................. 

### 57 4-21 Compressor Seal Emission Rates
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 

### 4-22 Component Emission Factors for Gas Storage ......................... 64 4-23 Average Component Counts for Gas Storage
. . . . . . . . . . . . . . . . . . . . . . . . . 65 4-24 Average Facility Emissions for Gas Storage .......................... 66 4-25 Operating Modes ofCompressors in Gas Storage
. . . . . . . . . . . . . . . . . . . . . . 68 4-26 Summary ofEmission Rates from Outdoor Residential Customer Meter Users
. . 69 4-27 Summary ofEmission Rates from Commercial/Industrial Customer Meter Sets
. . 71 5-1 National Activity Factors for Gas Production
. . . . . . . . . . . . . . . . . . . . . . . . . 73 5-2 National Annual 

### Emissions from Onshore Production in the Eastern U.S.
. . . . . 74 5-3
**Nat~onal** 

### Annual Emissions from Onshore Production in the Western U.S...... 75 5-4 National Annual Emissions from Offshore Production.
. . . . . . . . . . . . . . . . . . . 76 

### 5-5 National Annual Emissions from Gas Processing.
. . . . . . . . . . . . . . . . . . . . . . 77 5-6 National Annual Emissions from Transmission Compressor Stations
. . . . . . . . . 78 5-7 National Annual Emissions from Gas Storage Facilities
. . . . . . . . . . . . . . . . . . 79 5-8 Statistics on Indoor Customer Meters by 

### Region . . . . . . . . . . . . . . . . . . . . . . . 80 5-9 Nationai 

### Annual Emissions from Customer Meter Sets
. . . . . . . . . . . . . . . . . . 8 I A-I Compressor Blowdown Valve Operating Practices-Transmission .......... A-2 A-2 Compressor Blowdown Valve Operating Practices-Storage Stations ........ 

### AA A-3 Compressor Blowdown Valve Operating Practices--Gas Processing Plants ... A-5

X1.0 

### SUMMARY 

### This report is one ofseveral volumes that provide background information supporting the Gas Research Institute (GRI) and U.S. Environmental Protection Agency Office ofResearch and Development (EPA/ORD) methane emissions project. The 

### objective ofthis comprehensive program is to quantify methane emissions from the gas industry starting at the wellhead and ending immediately downstream ofthe customer's meter. The accuracy goal ofthe program is to determine these emissions to within 

### ± 5% of 

### national gas production for the 1992 base year. This report documents the approach used to estimate methane emissions from 

### equipment leaks using the 

### component method. In this method, an average emission factor is determined for each ofthe basic components, such as valves, flanges. seals, and other connectors that comprise a facility. The component emission factor. detennined from measured data, is combined with the average number ofcomponents comprising the facility to estimate average facility emissions. The average facility emissions are extrapolated to a national estimate by the number offacilities within the gas industry. The component method was used to estimate methane emissions from equipment leaks for onshore and offshore gas production, gas processing, transmission/storage, and customer meter sets. As shown in Figure 1-1. the total industry emissions from equipment leaks using the component method are 115 Bscf. The major contributors to emissions from equipment leaks are components associated with compressors, which have unique design and operating characteristics and are subject to vibrational wear. The single component with 

### the largest emission rate is the compressor blowdown open-ended line which allows the compressor to be depressurized for maintenance or when idle. The compressor blowdown open-ended lines leak continuously at different rates depending upon Whether the compressor is pressurized (operating or idle) or depressurized (idle).

IProduction 17.4Bscf CustomerMeters 5.8Bscf Storage 16.8 Els::f Transmission 50.7Bscf



### Figure 1-1. Summary ofEquipment Leaks Using Component Method 

### Equipment leaks from onshore and offshore production contribute around 16.2 Bscf

### ±43% and 1.2 Bscf

### ±29%, respectively, to annual national methane emissions. The emissions from onshore production were estimated separately for the Atlantic and Great Lakes region (Eastern U.S.) and the rest ofthe country (Western U.S.) because of regional differenc;es in number and type 

### ofequipment, and leak detection and repair practices. Likewise, the emissions from offshore production were estimated separately for the GulfofMexico and Pacific Outer Continental Shelf(OCS) regions. Equipment leaks from gas processing 

## 3.re 24.4 Bscf

### ± 68%. For gas processing, transmission, and storage facilities, fugitive emissions from compressor-related ·components were estimated separately from the remaining facility because ofdifferences in

leakage characteristics. In gas processing, compressor-related components account for 90% ofthe total 

### emissions from equipment leaks. Fugitive emissions from transmission and storage stations in the United States are 50.7 Bscf± 52% and 16.8 Bscf± 571/o, respectively. As with 

### gas processing, the emissions from compressor-related components account for the majority ofemissions, at 89% and 74% ofannual fugitive emissions from transmission and storage, respectively. Customer meter sets contribute approximately 5.8 Bscf

### ± 20% to annual 

### emissions from equipment leaks. Emissions from outdoor residential customer meter sets account for 96% ofthe annual fugitive emissions from customer meters, whereas commercial/industrial meter sets account for only 4%. 2

### 2.0 INTRODUCTION In the GRI/EPA program to quantifY methane emissions from the U.S. natural gas industry, estimates were developed for each source ofmethane emissions. Fugitive emissions from equipment leaks were identified as a potentially significant source of methane losses from production, processing, and gas transmission/storage. The purpose of the study documented in this report was to define and quantify fugitive emissions from equipment leaks using the component method.· Equipment leaks are typically low-level, unintentional losses ofprocess fluid (gas or liquid) from the sealed surfaces ofabove-ground process equipment. Equipment components that tend to leak include valves, flanges and other connectors, pump seals, compressor seals, pressure reliefvalves, open-ended lines, and sampling connections. These components represent mechanical joints, seals, and rotating surfaces, which 

### in time tend to wear and develop leaks. In the component method for estimating emissions from equipment leaks, an average emission factor is determined for each ofthe basic components, such as valves,

.flanges, seals, and other connectors that comprise a facility. The average emission factor 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 factor per component type (i.e., the component emission factor) and the average number ofcomponents associated with 

### the major equipment or facility, an average estimate ofthe emissions per equipment/facility can be determined. Extrapolation to a national emissions estimate can then be made by determining the total count ofthat specific equipment/facility in the United States.

*Other types offugitive emissions from the gas industry, including leaks from underground pipelines and meter and pressure regulating stations, are documented in separate reports. 1• 2 

### 3

### Component emission factors can vary depending upon the operating pressure, age, and leak detection and repair practices at the site. By randomly selecting a large number ofsites to measure leaks, these variations from site 

### to site are taken into account. However, it is important to develop different component emission factors for segments of the gas industry with uniquely different emission characteristics to avoid introducing bias. For example, typical component sizes, manufacturers, service, and maintenance practices are different for facilities in gas production, processing, transmission, and distribution. To eliminate bias, different component emission factors were developed for each ofthe industry segments. In gas production, regional differences were found between similar facilities that affected the emissions. Therefore, regional component emission factors were developed for onshore and offshOre gas production. This report documents the overall approach used 

### to estimate emissions from equipment leaks using the component method. The method used to measure and evaluate emission rates ls discussed in Section 3. The estimation ofemission factors for specific equipment or facilities by 

### combining the component emission factor 

### with average component counts is described in Section 4. The extrapolation to a national estimate for each equipment or facility type is discussed in Section 

### 5. This report 

### is one ofseveral volumes prepared under the GRI/EPA methane emissions project.

43.0 

### EMISSION FACTOR METHODOLOGY Component emission factors are used with the average component counts to determine average emissions from equipment and/or facilities. Two approaches were used to quantify component emissions for valves, flanges, seals, and other components. The first approach is based on the EPA protocol documene 

### and EPA Reference Method 21, Determination ofVolatile Organic Compound Leaks."4 

### EPA Method 21 involves screening 

### components using a portable instrument to detect total hydrocarbon (THC) leaks. Based on the EPA 

### protocol document, the corresponding screening value for a component is then converted to an emission rate by 

### using a correlation equation developed from data 

### collected using an enclosure method. (Note: The correlation equation may have been developed from screening and enclosure data collected at similar, but different, facilities.) EPA Method 21 and the approach based on the EPA protocol used to calculate emission rates from the resulting data are described in detail in Section 3.1. The second approach used to quantifY emissions from equipment components is a modification ofthe EPA protocol using the GRI Hi-Flowl'M (trademark ofGas Research Institute) sampler or a direct flow measurement to replace the data collected using an enclosure method. The GRI Hi-Flow sampler is a

**ne~ly** 

### developed device which allows the leak rate of a component to be measured directly. The sampler creates a flow field around the component in order to capture the entire leak. As the stream passes through the instrument, the flow rate and concentration are measured. The GRI Hi-Flow sampling method and the approach used to calculate emissions from the resulting data are described in Section 3.2. 3.1 EPA Protocol Approach 

### In general, EPA Method 21 and the EPA protocol were used to estimate emissions from equipment components in onshore production (except for production facilities in the Atlantic and Great Lakes region), offshore production, and gas processing. 5

### Using EPA Method 21 and the EPA protocol, emission factors are derived from screening data for a single component type 

### depending upon the service [i.e., gas, light liquid (high vapor pressure) or heavy liquid (low vapor pressure)]. (Note: There are very few heavy liquid streams in the gas industry.) The screening data are converted to an emission rate using an existing or newly generated correlation equation. The correlation equation is developed from measured data using an enclosure method coUected from the same component type 

### in similar facilities and similar service. The component emission factor is then derived as the average emission rate from all components screened. The following subsections describe the screening, enclosure, and correlation equation techniques. Figure 3-1 shows an overview ofthe EPA protocol as it was 

### applied to sources in the gas industry. 3.1.1 Component Screening 

### The EPA Method 2I screening measurement technique uses a portable instrument to detect

**I~ge** 

### around flanges, valves, and any other components by traversing the instrument probe over the entire surface ofthe component interface where leakage could occur. Components are typically subdivided according to type and service as follows:

o 

### Valves --gas/vapor, light liquid, heavy liquid; o 

### Pump Seals
-- light liquid, heavy liquid; • Compressor Seals
-- gas/vapor; • Pressure ReliefValves
-- gas/vapor; • Connections (includes flanges and threaded unions)
-- aU services; o Open-Ended Lines' --all services; and • Sampling Connections

-- all services. The components that may be subject to fugitive leakage at natural gas facilities include valves, flanges and other connections, pump and compressor seals, **Only includes fugitive leakage from around the valve seat when the 

### valve is closed. 6Conduct Complete Screening Survey (EPA Method 21)

Approach 1 Apply Existing Correlation Equations N

**~** 0 

## • e

**~**

**~** <( Apply Average Develop Component Calculate Average

Emission Factors Component Equipment/Facility Bag a Fraction of Counts for Emissions the Components for Equipmeni/Facility Each Component Type

Develop Correlation Apply New Equations for Each Correlation Component Type Equations



### Figure 3-1. Overview ofEPA Protocolpressure relief valves (PRVs), and open-ended lines (OELs). Components in heavy liquid service are not associated 

### with gas operations. Pump seals and sample connections were 

### considered outside ofthe gas industry boundary. Figures

**3~2** 

### through 3-8 show typical gate, globe, plug, and ball valves, flanged and threaded connections, pressure reliefvalves, 

### and open-ended lines with 

### the areas ofpossible fugitive leakage identified. 

### All components associated with 

### an equipment source or facility are screened using the procedures specified in EPA Method 21. 

### The components are categorized as to type (e.g., valves, flanges, and other connections) and also possibly by service (e.g., gas and light liquid). The maximum measured concentration, or screening value, is recorded. Levels below the detection limit ofthe instrument and levels above the full-scale range of the instrument are also recorded. The portable instrument used for screening must meet the specifications and performance criteria ·contained in EPA Method 21. In general, an organic vapor analyzer (OVA) that uses a flame ionization detector (FID) is typically used for screening measurements. Figure 3-9 shows two typical OVA instruments used for component screening measurements. The portable instrument provides a concentration measurement of THC from the screened component. The portable monitoring instrument 

### has a pump that draws a continuous sample ofgas from the leak interface to the detector. Because the commercially available FID instruments that meet the criteria specified in the method have limited pump capacity, the instrument does not always capture the entire leak or, for large leaks, the concentration may exceed the full-scale range. As part ofthe GRI/EPA methane emissions program, a dilution probe was used during co11ection ofsome ofthe screening data to extend the upper range ofthe instrument from I0,000 to 100,000 ppmv.



### 8PACKING GLAND ---, PACKING RINGS ----..._ VALVE STEM



### Figure 

### 3-2. Conventional Gate Valve



### 9 POSSIBLE LEAKAREASTEM PACKING GLAND**PACKING--~**

SEAT ---.J



### Figure 3-3. Manual Globe Valve

10**~--** POSSIBLE LEAK AREA

BODYBODY--'-**PLUG~** 

# 0 / / /



### Figure 3-4. Plug Valve

!I ,---LUBRICANTSCREW**~** GLAND STUD AND NUT // /-- LUBRICANT CHECK VALVE / '**/~GLAND ~COVER**  

# 0 0POSSIBLE --STEM LEAKAREASPHERICAL PLUG --

SEAT R!NG ---



### - BODY


## BALLVALVE(OPEN)
POSSIBLE LEAKAREA- r--- STEM SPHERICAL PLUG --

-BODY 

## BALLVALVE(CLOSED) Figure 3-5. Ball Valve 

### 12POSSIBLE LEAK AREA
**--~** 

# FLANGED CONNECTION

**~--** POSSIBLE LEAKAREA ---



# THREADED CONNECTION Figure 

### 3-6. Threaded and Flanged Connections 

### 13ALTE 

# r--·~

# ..

**~** 

# If!. 

# N

**~**

RNATE SCREENING AREA IF HORN INACCESSIBLE 

### lr

# r,- HORN 

## I?'" .,-'

**If"~** 

### lr"

# :.c.-

# I [ lr' --' Jr- ..--- 

## ,c: ,-- '!= 

# l 

# l:l

**~**



# J~ r F 

# '

**~l )llt~** 



# ~ **~**

# J f.-- 

# \ r I ( 

### IT\1 I 

# lr 

# I POSSIBLE 

# I LEAKAREA __) f-- 

# t:J J 

## I f-- ' ' 

# ' TO PROCESS 

### Figure 3-7. Pressure Relief Valve



### 14 I


# tJ TEN

SPRI SION ADJUSTMENT THIMBLE

NG

DISK

NOZZLEOPEN TO ATMOSPHERE

SEAT RING

**----~**

OPEN

TO ATMOSPHERE 

## OPEN-ENDED LINE (GlobeValve-Closed)



## OPEN-ENDEDLINE (Ball Valve-Closed) Figure 3-8. Open-Ended Line

15 **~-BODY**

BODY CONNECTED TO PROCESS

CONNECTED TO PROCESS

### SNIFFER

(a) TL V 

### Sniffer

(b) OVA-108 Figure 

### 3-9. Screening Instruments 

### 16

### 3.1.2 Enclosure Method/Data To convert the screening, or concentration, data to an emission rate, a correlation must be developed between the screening concentrations and the actual mass emission rates. The first step in this process is to directly measure some ofthe mass

**emi~sion** 

### rates that were screened. The procedure used to directly measure the emission rate is an enclosure method, which is often referred to as the "bagging" technique. The bagging technique is used to provide mass emission rates by measuring the THC concentration for a known flow rate ofinert gas. In the bagging technique, a leaking component is completely enclosed in a bag and a measured flow rate ofinert gas is passed through the bag either by vacuwn pump or blower. The concentration ofTHC is then measured at the outlet ofthe bag after complete mixing ofthe inert gas with the leaking process fluid. The actual leakage rate is the product ofthe flow rate and the concentration measurement. In some cases, a sample ofthe stream flowing through the bag is collected and analyzed to speciate the hydrocarbon compounds. Figure 3-10 illustrates a typical sampling system for the enclosure measurement method. Typically, bagging data are obtained from a relatively small, random sample ofleaking components identified using the screening technique. (The reason that bagging data are not collected for all leaking components is that the method is relatively expensive and time consuming.) The bagging data are used to correlate concentration values obtained using the screening technique 

### with mass emission rates. 3.1.3 Correlation Equation A correlation equation is developed which relates the concentration measured during the screening test to the emission rate measured from the bagging data. Because the screening values and mass emission rates span several orders. ofmagnitude and are highly variable, the equation is derived as a logarithmic function. In general, a correlation 

### 17Tbslne shJUd beM:II'at 

# --

COldTtapII!lceBitfl {Dp:IOI'Ial) 

# ....

0



# ""'" 

# """"'m

"""' **T~rr=0'­** 

# I!J

**....,.~** 

# """

Figure 3-10. Sampling Train for Bagging a Source Using the Vacuum Method

18

### equation is derived for each specific component type (e.g., valves, connections, open-ended lines, pressure rellefvalves) for a given type offacility. Figure 3-11 illustrates the correlation equation derived from the screening and bagging data for connectors in the oil and gas industry.3 

### Components associated with a specific facility type/service may have unique emission characteristics because size, manufacturer, service, age, and/or leak detection and repair practices are unique to that type offacility. Therefore, to avoid introducing bias, the correlation equation may only be applicable to similar facility types within the gas industry 

### or other like industries. Correlation equations derived for a given type offacility can be used to convert screening data from a similar, but different, facility into mass emission rates. Therefore, extensive bagging data are not required by every facility that desires to quantify fugitive emissions from equipment components. Screening data alone can be collected and used to predict emissions using an existing correlation equation derived from similar facilities. However, because ofthe high variability in the data which are used to generate the correlation equation, the uncertainty in the estimated mass emission rates generated from screening data and the correlation equation approach may be high. 

### For many sources offugitive emissions from the gas industry, a single set ofcorrelation equations developed from data co1Iected in the petroleum and 

### gas industries were used to estimate mass emission rates from screening data.5 

### Table 3-1 shows the EPA correlation equations used. 3.1.4 Pegged Source Emission Factors 

### Although components with 

### large leaks typically account for only a small fraction ofthe total components at a facility (often 2% or less), their emissions can contribute over 90% to the total emissions from the facility. Because ofthe limitations of commercially available instruments which meet the EPA Method 21 criteria, components

191E+01 !E<OO

**~** tE-01

**~** 1E-02 

## • iS < %

**~** • 

## " !E-03 

# • • • E > w 

### • •

**~** !E-04

# "- • 

### • 

# • !E<>S !E<l6 tE-07 

### Fugitive Correlation Equation Connectors

# • • 

# ' • 

# :I • 

# .. 

# . '

# .. .., •:. .. **4_~··** 

# ..... • ,_ •• 41" 

# •• 

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10 

# •

100 1000

**~pm~** Scre•ningV1lue !0000 

# • •

**~t**



# <

!00000



### Figure 3-11. Scatter Plot ofBagging Data and Correlation Equation3


### 20

### TABLE 3-1. CORRELATION EQUATIONS DEVELOPED BY EPA Component Type" Connector 

### Flange Open-Ended Line 

### Pump Seal Valve Other 

### Correlation Equation b,c 

### THC (lb/day)

**~** 

### (7.99 x 

### 10"5 ) x 

### (ISV)0 "' 

### THC (lb/day)

**~** 

### (2.35 x I

### 04 ) x 

### (ISV)0 "' 

### THC (lb/day)

**~** 

### (1.14 x 104 ) 

### x (ISV)0

·7" 

### THC (Ib/day)

**~** 

### (2.55 x 10"3) 

### x (ISV)0 ' 10 

### THC (lb/day)

**~** 

### (1.21 x 104 ) 

### x (ISV)07" 

### THC (lb/day)

**~** 

### (6.98 x 104 ) 

### x (ISV)0

·589 

### " Combined for all services (e.g., gas, light liquid, heavy liquid). b 

### Per EPA study offugitive emissions from petroleum refineries, marketing terminals, and

oil and gas production.s c 

### THC = 

### total hydrocarbon; ISV = 

### instrument screening value. 

### leaking at a high rate can exceed the full-scale range ofthe screening instrument (5-15% of all leaks exceed the full-scale range ofthe instrument). This results in a practical upper limit to the correlation equation and requires that a separate "pegged source" emission rate be developed. Typically, the pegged source emission rate is the lognormal mean emission rate ofall 

### the bagging data collected for pegged components. Pegged source emission rates were developed for full-scale screening values of 10,000 and 100,000 ppmv based on screening data obtained without and with an instrument dilution probe, respectively. Because ofthe high variability in measured leakage rates for pegged sources (refer to Figure 3-11 for a typical range in emission rates at I0,000 and I00,000 ppm screening values), an average pegged source emission factor developed from screening and bagging data has a high uncertainty. Since the majority ofemissions from a typical site are due to pegged sources, estimated emissions based on screening data and EPA correlation equations, default zero, and pegged source factors also have a high uncertainty.

21

### 3.1.5 Default Zero Emission Factors For components with screening values below the detection limit ofthe method or below the background concentration level, a zero response level is recorded during data collection. In an EPA study offugitive emissions from refineries, marketing terminals, and oil and gas production,5 

### default zero factors were calculated based on bagging data collected from a random sample ofeach component type with screening values below the detection limit ofthe method. The default zero factors were calculated as the lognormal mean emission rate from the bagging data for the components with a "zero" screening value. Table 3-2 presents the average default zero and pegged source factors developed in the EPA study5 

### which were used for many sources offugitive emissions in the gas industry. At sites with 

### few leaks (e.g., sites subject to strict regulations, such as petrolemn refineries and synthetic organic chemical manufacturing facilities), the value of the default zero factor can have a significant influence on the overall site emission rate. 

### 3.2 Alternative Approach Usin& the GRI Hi-Flow Sampler The GRI Hi-Flow sampler 

### was developed to provide a more accurate evaluation ofemissions from equipment leaks than 

### the EPA protocol approach. 6• 7 

### In general, the GRl Hi-Flow sampler, which is used to measure the emission rate ofa component, is a low cost replacement for bagging measurements. Because ofthe lower cost and ease ofuse, it can be used to measure aU leaking components at a facility instead ofonly a fraction ofthe leaking components, as with the bagging method. The GRI Hi-Flow sampler has a high flow rate and generates a flow field· around the component that captures the 

### entire leak. As the sample stream passes through the instrument, both the sample flow rate and THC concentration are measured. With 

### accurate flow rate and concentration measurements, the mass emission rate can be calculated as the product ofthe flow rate and concentration..Because ofthe high flow rate,


### 22

### TABLE 3-2. DEFAULT ZERO AND PEGGED EMISSION FACTORS DEVELOPED BY EPA' Pegged Factor, lb THC/day 

### Default Zero Factor,b 

### Component Type lb THC/day >10,000 

### ppmt >100,000 ppmd Connector 

### 3.97 X 10 4 

### 1.48 !.59 Flange 1.64 X 10"5 

### 4.50 4.44 Open-Ended Line 1.06 

### x 

# w• 1.59 4.18 Pump Seal 1.21 

### x 

# w·' 3.92 8.47 Valve 

### 4.13 

### x 

# w• 3.39 7.41 Other 2.12 

### x 10 4 

### 3.86 5.82 3

### Per EPA study offugitive emissions 

### from petroleum refineries, marketing terminals, and

oil and gas production.5 

### bDefault zero factors calculated from refinery and marketing terminal data only. cBased on lognormal mean emissions using emission and 

### screening data for 

### screening values above 10,000 ppm (includes screening data of I00,000 ppm). dBased on lognormal mean emissions using emission and screening data for screening

values above 100,000 ppm. the instrument can accurately measure the emission rate from large leaks which would exceed the fuii-scale range ofmost commercially available OV(\. instruments. The GRI Hi-Flow sampler is different than the conventional approach based on the EPA protocol for the following reasons:

• The emission rate is measured directly by providing both concentration and sample flow rate measurements. 1-n contrast, the EPA protocol approach requires the use ofeither bagging data to determine the emission rate from a component or use ofa correlation equation to calculate the emission rate. Bagging data are very costly to obtain and the correlation equation approach has a high uncertainty. • Because using the GRI Hi-Flow sampler is much faster than bagging, the total emissions from a given facility can be measured within a few percent. [The sampler is not well suited for generating default zero 23

### factors because ofthe higher dilution rate leading to lower concentrations (i.e., lower resolution) for small 

### leaks. However, because 90% ofthe emissions from a facility are from leaks that exceed the upper range ofthe screening instrument, emissions from components that are below the threshold (i.e., default zeros) have an insignificant impact on total emissions.] • Because ofthe much higher flow rate, the sampler can accurately measure large leaks. In contrast, the EPA protocol approach classifies large leaks (i.e., those that exceed the full-scale range ofthe screening instrument) as pegged sources and an average emission factor 

### (with high 

### uncertainty) is assigned as the leak rate. The GRI Hi-Flow sampler was used to measure fugitive emission rates from onshore production sites in the Atlantic and Great Lakes region, transmission compressor stations, and customer meters. Two general approaches were implemented for gas industry sources using the GRl Hi-Flow sampler. The first approach, used for transmission compressor stations and customer meters, included the identification ofall leaking components using soaping tests. AH 

### components found to be 

### leaking were then measured using the GRI Hi-Flow sampler. Leaks in excess ofthe GRI Hi-Flow sampler range were measured directly using rotameters. Component emission factors were derived from the emission rates ofall components, including leaking and non-leaking components. (Nonleaking components were assumed to have a negligible emission rate.) This approach provided a direct measurement ofall leaking components at a site and, consequently, an accurate estimate ofemissions without the use ofcorrelation equations. The second general approach using the GRI Hi-Flow sampler included screening ofall components at a site using EPA 

### Method 21 with a conventional FID instrument. All components with screening values exceeding the full-scale range ofthe instrument (i.e., pegged sources) were measured using the GRI Hi-Flow sampler. Therefore, a direct measurement ofemissions was 

### provided for the pegged sources which contribute around 90% to total emissions. A fraction (30-50%) ofthe components 

### with screening values below 10,000 ppm were also measured using the GRJ Hi-Flow sampler instead ofbagging measurements. A correlation equation was then developed for 

### 24

### components with screening values below I0,000 ppm and applied to all components screened at less than I0,000 ppm. Because all large leaks (i.e., above I0,000 ppm) were measured, this approach provides a more accurate estimate ofemissions than the EPA protocol approach where a pegged source er.tission factor is applied. This approach was used for onshore production sites in the Atlantic and Great Lakes region.



### 254.0 

### AVERAGE EMISSIONS FROM EQUIPMENT AND FACILITIES This section presents the component emission factors for the various segments ofthe industry, and how these were used to determine the average emissions from 

### equipment and facilities. Emission factors for equipment leaks were developed for:

in Table 4-l. • Onshore production in the Atlantic and Great Lakes region (i.e., Eastern U.S.) and the rest ofthe U.S. (i.e., Western U.S.); 

### • Offshore production in the GulfofMexico and Pacific OCS; • Gas processing; • Transmission; • Storage; and • Customer meters. 

### Fugitive methane emissions were estimated for the types ofequipment listed
The average emissions for a given type ofequipmenVfacility were calculated 

### as the product ofthe component emission factor (i.e., the average emission rate per component) and the average number ofcomponents, summed over ali the types of components associated with 

### the equipment/facility:

where:

= EA = 

## I (EF, X CC;) 

### Average equipment emissions for equipment/facility type A (Mscf/equipment-yr);



### 26

### TABLE 4-1. EQUIPMENT CATEGORIES BY SEGMENT • Production: 

### Onshore gas production: Wellhead emissions Heater emissions Separator emissions Meters and piping 

### Gathering compressors (small) Large production (gathering) compressors Dehydrators Offshore gas production: 

### Platforms (one 

### EF that includes all equipment on the platform) 

### • Transmission: Pipelines Transmission and storage compressor stations (reciprocating compressors, centrifugal compressors, and rest of station) • Processing: Gas processing plants (reciprocating compressors, centrifugal 

### compressors, and rest ofstation) • Distribution: Customer meters (residential and commercial/industrial)



### 27

### EF, 

# cc,

**~** Average component emission factor for component type 

### i (Mscflcomponent-yr); Average component count for component type 

### i. Type ofcomponent (e.g., valves, connectors, open-ended lines). 

### This section provides documentation ofthe component emission factor and component count data and the resulting average equipment emissions for equipment'facilities within the gas industry where the component method was used. Table 4-2 presents a summary ofthe measurement programs providing data for each segment'region within the gas industry where the component method was used for estimating fugitive emissions. 

### 4.1 

### Onshore Gas Production 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 Eastern U.S. (i.e., Atlantic and Great Lakes region) and the Western U.S. (i.e., rest ofthe country, excluding the Atlantic and Great Lakes region) and between offshore production in the GulfofMexico and the Pacific OCS. Therefore, separate measurement programs were conducted to account for these regional differences. 

### 4.1.1 Onshore Production in the Eastern U.S. Region Fugitive emissions from equipment leaks were estimated separately for onshore production in the Eastern U.S. because ofdifferences 

### in the service, number, type, age, and leak detection and repair characteristics ofequipment typically located at production sites in this region. In general, the gas produced from wells in the Eastern U.S. region has a very low hydrogen sulfide (H2S) and carbon dioxide (CO,) content. relatively 

### 28TABLE 4-2. EQUIPMENT LEAK MEASUREMENT PROGRAMS Measurement Correlation Equation Pegged Source Default Zero Industry Area Study Approach Technlque(s) Used Method Method Production

Onshore Eastern U.S. Star/GRI8 GRI Hi-Flow Screening and Developed new GRI Hi-Flow Assumed negligible GRI Hi-Flow correlation equation measurements leakage Onshore Western U.S. APIIGRI9 EPA Protocol Screening and Bagging EPA Correlation EPA Factorg5 EPA FactorsS Equations Offshore Gulfof Mexico APIIGRI9 EPA Protocol Screening and Bagging Developed new Developed new Developed new correlation equation pegged source default zero factors Offshore Pacific OCS MMS 10 EPA Protocol Screening and Bagging Developed new Developed new 

## • correlation equation pegged source factors Gas Plants API/GRI9•11 EPA Protocol Screening and Bagging EPA Correlation EPA Factors5 EPA Factors5

(excludingcompressors) Equation5 N Transmission Stations Indaco/GRI 12 GRI Hi-Flow Soaping and GRI Hi- Direct measurement used Direct measurement Assumed negligible '<> (excludingcompressors) Flow (all leaking instead ofcorrelation using GRI Hi-Flow leakage components) equation Compressors lndaco/GRI 11 GRI Hi-Flow GRI Hi-Plowor Direct measurement used Direct measurement Assumed negligible

(transmission, Rotameter (all leaking instead ofcorrelation using GRI Hi-Flow leakage processing, storage) components) equation and rotameter Customer Meter Sets Indaco/GRin EPA Protocol Screening EPA Correlation EPA Factors5 Assumed negligible Equation5 leakage Jndaco/GRI 1 ( GRI Hi-Flow Screening and Direct measurement used Direct measurement Assumed negligible GRI Hi-Flow instead ofcorrelation using GRI Hi-Flow leakage equation Star/GRI 15 GRI Hi-Flow Screening and Direct measurement used Direct measurement Assumed negligible GRI Hi-Flow instead ofcorrelation using GRI Hi-Flow leakage equation • Developed non-emitteremission factor for components which have a screening value less than 500 ppm.

### low moisture content, and low production rates per 

### well compared to gas produced in the other regions ofthe United Stales. For this reason, there are significant regional differences. (Note: A statistical analysis ofthe data also confirmed a significant difference between regions.) 16 

### Component emission factors for onshore production in the Eastern U.S. were based on a measurement program using a combination ofscreening to identify leaking components and the GRI Hi-Flow device to quantify emission rates from leaking components.8 

### A total of 192 individual well sites were screened using EPA Method 21 at 12 eastern gas production facilities. All pegged source components (with screening values above 10,000ppm) and a fraction (30-50%) ofthe leaking components with screening values less than 10,000ppm were measured using the GRI Hi-Flow sampler. A correlation equation was developed from the screening and direct measurement data for components with screening values less than 

### 10,000ppm. This correlation equation was used to estimate emission rates from all components 

### with screening values less than 10,000ppm. The emission rates for components with screening values of 10,000ppm and above were measured directly. The component emission factors were estimated based on the average emission rates ofali components (i.e.,calculated using the developed correlation equation or directly measured). The component emission factors were adjusted for the average methane content (69.6 wt. 

### %or 78.8 volume 

### %in production"). Table 4-3 shows the component emission factors for valves, connections, open-ended lines, and pressure reliefvalves. Component counts for gas production 

### in the Eastern U.S. were based on information collected as part ofthe Eastern U.S. production fugitives study. 8 

### Component count data were collected for gas wellheads, separators, meters and the 

### associated aboveground piping, and gathering compressors. Few in-line heaters and glycol dehydrators exist for gas production in 

### the Eastern region. Although no heaters and dehydrators were identified as pan ofthe measurement study,8 

### site visits and phone surveys ofseven additional sites provided data used for determining the number ofunits in the region. For the small
30TABLE 4-3. COMPONENT EMISSION FACTORS FOR EASTERN U.S. GAS PRODUCTION

Total Number of Components Component Screened Valves 

### 4200 Connections 

### 18639 Open-Ended Lines 

### 260 Pressure Relief Valve 

### 92 

### Component Emission Factor,a Mscf/component-yr 

### 0.184 0.024 0.42 0.279 90% Confidence 

### Interval, % 

### 29 20 

### 54 88 3 Total methane emission rate adjusted for average 69.6 wt. 

### % (78.8 val. %) methane in

production. 17 number ofheaters and dehydrator units thatdo exist in the Eastern region. the component counts were assumed to be identical to those derived from data collected in the Western U.S. (see next section). Table 4-4 presents a summary ofthe average component counts estimated for each type ofequipment associated 

### with gas production 

### in the Eastern U.S. Confidence intervals were not available for the component count data provided from the measurement 

### program. The average equipment emissions for each type ofequipment associated with gas production in the Eastern U.S. were derived as the product ofthe component emission factors and the average number ofcomponents, summed over all component types. Table 4-5 presents the component emission factors and component counts for each type of component associated with the equipment, along with the average equipment emissions and 90% confidence interval.



### 31w N 

### TABLE 4-4. AVERAGE COMPONENT COUNTS FOR GAS PRODUCTION EQUIPMENT IN THE EASTERN U.S. Average Component Coune 

### Quantityof Open-Ended Pressure Relief Equipment No. ofSites Equipment Valves Connections Lines Valves Gas Wellheads 

### 12 192 8 38 

### 0.5 0 Separators II 

### 110 I 

### 6 0 0 Meters/Piping 

### 12 83 

### 12 45 0 0 Gathering Compressors I 

### 2 12 57 0 0 **In~Line** 

### Heatersb II 

### 77 14 65 2 I 

### Dehydratorsb 10 

### 52 24 90 2 2 a 

### Based on the Eastern U.S. onshore production study offugitive emissions from equipment leaks,8 

### unless otherwise noted. b Based on the oil and gas production operations study offugitive emissions from equipment leaks.9TABLE 4-5. AVERAGE EQUIPMENT EMISSIONS FOR ONSHORE PRODUCTION IN THE EASTERN U.S. Component Emission Average Equipment 90% Confidence Component Factor,t> Average Component Emissions, [nterval, Equipment Type Type' :Mscf/component-yr Count scf/equipment-yr % Gas Wellheads Valve 0.184 8 2,595 27 Connection 0.024 38 OEL 0.42 0.5 Separators Valve 0.184 328 27 Connection 0.024 6 Heaters Valve 0.184 14 5,188 43 C01mection 0.024 65 OEL 0.42 2 PRY 0.279 I

**~** Glycol Dehydrators Valve 0.!84 24 7,938 35 **~** Connection 0.024 90 OEL 0.42 2 PRY 0.279 2 Meters/Piping Valve 0.184 12 3,289 30 Connection 0.024 45 Gathering Valve 0.184 12 4,417 6 Compressors Connection 0.024 57 OEL 0.42 2 aOEL = Open-Ended Line; PRY = Pressure ReliefValve. b Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %) methane in productionY4.1.2 Onshore Production in the Western U.S. Region Component emission factors for onshore production in the Western U.S. (i.e., all regions excluding the Atlantic and Great Lakes region) were based on an API/GRI measurement program using the EPA Method 21/protocol approach to screen and bag selected components at 12 oil and gas production sites. 9 In this measurement program, screening and bagging data were collected from 83 gas 

### wells at 4 gas production sites in the Pacific, Mountain, Central, and Gulfregions. Component emission factors were determined from the screening data that were converted to emission rates using a correlation equation developed by EPA in a separate study.' (The EPA study' developed new equipment leak correlation equations, default zero factors, and pegged source factors based on a combination ofthe API/GRJ study' and data from petroleum production, refmeries, and marketing terminals.) To
**est~ate** component emission factors, Radian used the screening data from the API/GRJ study' and the component correlation equations derived by EPA' for components with screening values between 10ppm and 10,000ppm. For components with screening values below 10ppm, the default zero factors developed by EPA were used. For pegged source components (i.e., with screening values of 10,000ppm and above), the 10,000ppmpegged source factor developed by EPA was applied. The component emission factors were recalculated instead ofusing those presented in the API/GRJ report'because: (1) confidence intervals needed to be provided which were not available from the API/GRJ report; (2) the API/GRJ report combined pressure relief valves and compressor seals, both with relatively high emission rates, into a single "other" category (separate emission factors were recalculated for pressure relief valves and compressor seals as pan ofthis study); 

### and (3) because some ofthe site visit data combined flanges and connectors into a single category, a combined component emission factor for flanges/connectors was calculated.

34The component emission factors for gas production in the Western U.S. are presented in Table 4-6 for valves, connections, open-ended lines, pressure relief valves, and compressor seals. The 90% confidence intervals for the average component emission rates were calculated based on the variability in the estimated emission rates for all components screened as part ofthe AP!/GRI study.



### TABLE 4-6. COMPONENT EMISSION FACTORS FOR ONSHORE PRODUCTION IN THE WESTERN U.S. Total Number of ComponentEmission 90% Confidence Components Factor,a Interval, Component Screened Mscf/component-yr % Valves 

### 6059 0.835 10 Connections 

### 32513 0.114 9 Open-Ended Lines 

### 1051 0.215 33 PRVs" 

### 448 1.332 37 Compressor Seals 

### 40 2.37 72

a Total methane emission rate adjusted for average 69.6 wt. 

### % (78.8 vol. %) methane in

production. 17 t> Pressure relief valves. The average component counts for each piece ofmajor process equipment associated with gas production in the Western U.S. were based on data from the API!GRI study' and additional data collected for this project during 13 site visits to gas production fields. Table 4-7 shows the number ofproduction sites and equipment used as data sources and the average component counts for wellheads, separators, heaters, glycol dehydrators, meters and the associated piping, and field gathering compressors. For large reciprocating compressor stations 

### in production, the component counts were assumed to 

### be identical to those in transmission compressor stations (see Section 4.4).



### 35

### TABLE 4-7. AVERAGE COMPONENT COUNTS FOR ONSHORE PRODUCTION IN THEWESTERN U.S. Average Component Coone 

### No. of Open· Ended Compressor Equipment No. ofSites Equipment Valves Connections 

### Lines PRVs' Seals Gas Wellheads 17 

### 184 II (30%) 36 (20%) I (28%) 0 0 

### Separators 16 183 34 (44%) 106 (38%) 6 (94%) 2 (68%) 0 Meters/Piping 12 73 14 (31%) 51 (47%) I (113%) I (150%) 0 Gathering 13 

### 61 73 (102%) 179 (51%) 3 (50%) 4 (84%) 4 (69%) Compressors 

### Heaters II 77 14 (49%) 65 

### (70%) 2 (66%) I (89%) 0 

### Dehydrators 10 52 24 (31%) 90 (37%) 2 (69%) 2 (53%) 0 **~** 

# "' a 

### Values in parentheses represent the 90% confidence inte.r;val. h 

### Pressure reliefvalves.

### Overa11 average equipment emissions were derived from the component emission factors and component counts for each equipment type. Table 4-8 presents the average equipment emissions for each type ofequipment along with the 90% confidence interval. Several transmission companies reported that some transmission-owned gathering stations were similar in size and operational characteristics to transmission compressor stations. Therefore, average equipment emissions for large reciprocating compressor stations in production were assumed equal to transmission compressor stations 

### (Section 4.4). 4.2 Offshore 

### Gas Production Emissions from equipment leaks from offshore production sites in 

### the United States were quantified based on two separate screening and bagging studies:

• The API/GRI oil and natural gas production operations stiidy,9 

### which included four offshore production sites in the GulfofMexico; and • The Minerals Management Service study ofseven offshore production sites in the Pacific OCS. 10 

### The component emission factors and 

### average component counts were taken directly from the field test reports.9•10 

### Tables 4-9 and 4-10 present the component emission factors and average component counts, respectively, for offshore production in 

### the Gulfof Mexico and Pacific OCS. The average component counts for offshore production in 

### both the GulfofMexico and Pacific OCS were combined for all major equipment on a production 

### platform.

37TABLE4-8. AVERAGE EQUIPMENT EMISSIONS FOR ONSHORE PRODUCTION IN THE WESTERN U.S. Component Emission Average Average Equipment 90% Confidence Factor," Component Emissions, Intenal, Equipment Type Component Type Mscf/component-yr Count scf/yr % Gas Wells Valve 0.835 II 13,302 24 Connection 0.114 36 Open-Ended Line 0.215 Separators Valve 0.835 34 44,536 33 Connection 0.114 106 Open-Ended Line 0.215 6 Pressure ReliefValve 1.332 2 Heaters Valve 0.835 14 21,066 40 Connection 0.114 65 w 

# "' Open-Ended Line 0.215 2 Pressure ReliefValve 1.332 I Dehydrators Valve 0.835 24 33,262 25 Connection 0.114 90 Open-Ended Line 0.215 2 Pressure ReliefValve 1.332 2 Meters/Piping Valve 0.835 14 19,310 30 Connection 0.114 51 Open-Ended Line 0.215 Pressure ReliefValve 1.332 Continuedw '0 Equipment Type Gathering Compressors

Large Compressor Stations

Station Components Compressor-Related Components 

### TABLE 4-8. (Continued)
Component Type Valve Connection Open-Ended Line Pressure RdiefValve Compressor Seal

b b Component Emission Factor," Mscf/component-yr 0.835 0.114 0.215 1.332 2.37

b b • Total methane emission rate adjusted for average 69.6 wt. % (78.8 vol. %) methane in productionY b Refer to Table 4-17 under transmission compn:ssor stations. · Average Component Count

73 179 3 4 4

b b Average Equipment Emissions, scf/yr 97,729

3.01 X 10' 5.55 X 10' 90% Confidence Interval, % 68

102 65TABLE 4-9. AVERAGE COMPONENTEMISSION FACTORS FOR OFFSHORE GAS PRODUCTION'

Component Emission Factor, **Mscf/oomponent~yr** Component GulfofMexico!• Pacific

## ocsc Valve 0.187 0.048 Connection 0.046 0.021 Open-Ended Line 0.368 0.092 Other 2.517 0.091 •Confidence intervals were not available

**fo~** the published component emission factors. b Total methane emission rate adjusted for average 79.1 wt. % methane in GulfofMexico. cTotal methane emission rate adjusted for average 72.8 wt. %methane for components in

gas service in Pacific OCS.



### 40TABLE 4-10. AVERAGE COMPONENT COUNTS FOR OFFSHORE GAS PRODUCTION EQUIPMENT Average Component Counts Number of Open-Ended Equipment Sites Valves Connections Lines Other Total GulfofMexico Platform 4 2207 8822 326 67 11421 Pacific OCS Platform 7 1833 13612 313 307 16065

### Separate component emission factors were estimated for valves, connections, open-ended lines. and other components from offshore production in the GulfofMexico and Pacific OCS. Confidence intervals were not provided for the component emission factors from either study9•10 

### and were not independently estimated as 

### part ofthe GRI/EPA methane emissions program since this represents a small source ofemissions. Table 4-11 presents the overall average facility emissions for offshore production platfonns in the GulfofMexico and Pacific OCS, respectively. The average facility emissions were derived as 

# the product ofthe component emission factors and component counts. The 90% confidence interval was estimated based on the variability in the component count data for the Pacific OCS. Forthe GulfofMexico, the 90% confidence interval was based on the variability 

### in. total estimated emissions from each ofthe four platfonns where measured data were collected. 

### 4.3 Gas **Processin~** 

### Component emission factors were developed for gas processing plants from screening data provided as part ofthe API/GRI oil and natural gas production study. 9•11 

### The screening data from eight gas processing plants were segregated by component type 

### for the entire gas processing facility instead ofby major equipment type. 

### Correlation equations derived by EPA5 

### were used to calculate emission rates for screening values between the 

### background concentration and the .full-scale range ofthe instrument. Default zero and the appropriate pegged source factors developed by EPA were used to quantify screening values below background concentrations and above the range ofthe instrument, respectively. Site blowdown open-ended lines allow a facility to depressure equipment to 

### the atmosphere for maintenance orallow the entire facility to be depressured for emergency situations. Site blowdown open-ended lines are found at gas processing plants. gas transmission stations, and gas storage stations. These open-ended lines are much larger than


### 42TABLE 4-11. AVERAGE FACILITY EMISSIONS FOR OFFSHORE PRODUCTION Equipment Type Gulfof Mexico Platform

Pacific OCS Platform Component Type Valve Connection Open-Ended Line Other Valve Connection Open-Ended Line Other Component Emission Factor,a,b Mscf/component-yr 0.187 0.046 0.368 2.517 0.048 0.021 0.092 0.091 Average Component Count 2,207 8,822 326 67 1833 13612 313 307 • Total methane emission rate adjusted for average 79.1 wt. % methane in GulfofMexico. Average Equipment Emissions,

Mscf/yr

1,064

430

b Total methane emission rate adjusted for average 72.8 wt. % methane for components in gas service in Pacific OCS. 90% Confidence Interval 27

36

### those typically used as drain valves and bleeder valves. Although site blowdown valves are infrequently operated, they have a significantly higher leakage rate than those associated with small valves. Component emission factors from compressor-related components were estimated separately because these components were found to have significantly higher emission rates than components associated with other equipment. This results from the unique design, size, and operation ofsome compressor components, as well as from the vibrational wear associated with compressors. The components associated with compressors include

# :an fittings and sealed surfaces physically connected to, or immediately adjacent to, the compressor. Two types ofcompressors are employed in the gas industry: reciprocating and centrifugal. In general, reciprocating compressors are driven by internal combustion (IC) engines and centrifugal compressors are driven by gas turbines. The component emission factors for compressor-related components were based on screening data provided by a separate GRI study. 12 

### A detailed discussion of component emission factors from compressor-related components is given in Section 4.4. Adjustments were made for the fraction oftime reciprocating and centrifugal compressors are pressurized in gas processing service (89.7% and 43.6% for reciprocating and centrifugal compressors, respectively, as shown 

### in Appendix A). Based on data collected during site visits, some fugitive sources (i.e., pressure reliefvalves and compressor blowdown openended lines) at a few gas processing plants are routed 

### to a flare. It was found that 

### approximately 11% ofcompressors 

### in gas processing have blowdown valves and pressure reliefvalves which are routed to a flare. Table 4-12 shows the component emission factors for each component type in gas processing, with separate estimated values for compressor-related components and the remainder ofthe gas plant.



### 44

### TABLE 4-12. COMPONENT EMISSION FACTORS FOR GAS PROCESSING"·' Component Valve Connection Open-Ended Line 

### Pressure Relief Valve B1owdown Open-Ended Line Compressor Seal Miscellaneous 

### Gas Plant (non-compressor) 

### 1.305 (6%) 0.117 (9%) 0.346 (31 %) 0.859 (56%) 230 (190%) Reciprocating Compressor



### 1341' (121 %) 349'·' (171 %) 2035'·' (144%)

450' (53%) 189' (19%) Centrifugal Compressor



### 1341' (121 %) 6447'·' (46%)

228' (53%) 31' (220%)

a 

### Component emission factors in units ofMscf/component-yr. Values in parentheses represent the 90% confidence interval. b 

### Annual methane emission rate adjusted for average 87.0 vol. % 

### methane in gas processingY c 

### Starter Open-Ended Line. d 

### Adjusted for 89.7% oftime reciprocating compressors in processing are pressurized. e 

### Adjusted for 11.1% of streams routed to flare. rAdjusted 

### for 43.6% of time 

### centrifugal compressors in processing 

### are pressurized.Component counts for gas processing plants were based on 21 sites from the following data sets:

• Published counts from four gas plants in the API/GRI oil and gas production study; 9 

### • An additional four gas plants in a later update to the API/GRI study; 11 • Six gas plants included in the 

### EPA study ofnatural gas liquids plants;18 and • Site visits to seven gas plants conducted by Radian International for this project. Table 4-13 presents the average component counts for a gas plant and the reciprocating and turbine compressorengines located at a gas plant. Because only a fraction ofcompressor starters 

### in gas processing use natural gas, the component counts for compressor starter open-ended lines were adjusted for the fraction ofunits that are operated with natural gas (i.e., 25% and 66.7% for reciprocating and centrifugal compressors, respectively). The average facility emissions, shown 

### in Table 4-14, were derived as the product ofthe component emission factors and the average component counts. 

### 4.4 Transmission Compressor Stations 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. 46TABLE 4-13. AVERAGE COMPONENT COUNTS FOR GAS PROCESSING EQUIPMENT' 

### Component Valve Connection Open-Ended Line 

### Pressure Relief Valve Blowdown Open-Ended Line Compressor Seal Miscellaneous 

### Gas Plant (non-compressor) 1392 (26%) 4392 (31 %)

134 (54%) 29 (35%) 2 Reciprocating 

### Compressor

I I 2.5

I'

a Average component counts. Values in parentheses represent the 90% confidence intervals. b Starter open-ended line. c Only 25% ofstarters for reciprocating compressors in processing use natural gas. d Other components counted/measured in aggregate per compressor. 

### Centrifugal Compressor

0.667' I 1.5 I'

### TABLE 4-14. AVERAGE FACILITY EMISSIONS FOR GAS PROCESSING PLANTS Equipment Type Gas Plant (noncompressor related components)
Reciprocating Compressor

Centrifugal Compressor Component Type Valve Connection Open-Ended Line Pressure ReliefValve Site Slowdown Open-Ended Line Compressor Slowdown OpenEnded Line Pressure Relief Valve Miscellaneousb Starter Open-Ended Line Compressor Seal Compressor Blowdown OpenEnded Line Miscellaneousb Starter Open-Ended Line Compressor Seal Component Emission Factor: **Mscf/component~yr** 1.305 0.117 0.346 0.859 230

31' 1341 2282 Average Component Count

1392 4392

134 29 2

I' 2.5

I' 1.5 • Annual methane emission rate adjusted for average 87.0 vol. % methane in gas processing. 17 b Includes cylinder valve covers and fuel valves. c Adjusted for 11.1% ofcompressors which have sources routed to flare. 4 Adjusted for 89."?/o oftime reciprocating compressors in processing are pressurized. e Other components counted/measured in aggregate per compressor. Average Equipment Emissions, MMscf/yr 2.89

4.09

7.75 90% Confidence Interval, % 48

74

39

rOnly 25% ofstarters for reciprocating compressors in processing use natural gas.g Adjusted for 43.6"/o oftime centrifugal compressors in processing

are pressurized. s Adjusted for 43.6% oftime centrifugal compressors in processing are pressurized.The component emission factors, average component counts, and average facility emissions for station and compressor-related components in gas transmission are presented in Tables 4-15 through 4-17. Table 4-15 shows the component emission factors for the station components (discussed in Section 4.4.1), along with component emission factors for reciprocating and centrifugal compressor-related components (discussed in Section 4.4.2). Table 4-16 presents the average component counts for transmission compressor stations. Table 4-17 presents the average facility emissions for station and compressorrelated components. The component emission factors and average component counts for station components (i.e.• non-compressor related components) and compressor-related components are discussed in Sections 4.4.1 and 4.4.2, respectively. 

### 4.4.1 Station Components Component emission factor.s for station components were based on a measurement program conducted at six compressor stations using the GRI Hi-Flow sampler to quantify compressor station emissions and develop component emission factors. 12 Leaks were identified using soaping tests and all leaks found were measured using the GRI Hi-Flow sampler. [Note: Componentemission factors were developed as part ofthe compressor station fugitive emissions measurement program12 assuming that non-leaking components had a negligible (i.e., zero) contribution to total emissions.] The component emission factors for station components are summarized in Table 4-15. Component counts for station components were estimated based on the following data collected at 24 sites:

• Data from eight sites tested as part ofthe transmission station fugitives study; 12
• Data from nine sites visited as part ofthis

**project~** and • Data from seven sites provided by two transmission companies.
49**~** 0 TABLE4-15. COMPONENTEMISSION FACTORS FOR TRANSMISSION' Reciprocating Compressor-Related Station Components" Components Component 90% Component EmissionFactor, Confidence EmissionFactor, Component Mscf/comp-yr Interval Mscf/comp--yr Valve 0.867 Control Valve 8.0 Connection 0.147 Open-Ended Line I1.2 Site Blowdown Open- 264 84% Ended Line Pressure ReliefValve 6.2 3724 Compressor Dlowdown 3683d Open-Ended Line Compressor Starter



### --• Open-Ended Line Compressor Seal 396d.r Miscellaneous< 180' • Annual methane emission rate adjusted for average 93.4 vol. % methane in gas transmission.17 b Excludes components physically connected to ordirectly adjacent to compressor. " Includes cylinder valve covers and fuel valves associated with compressors. 90% Confidence

Interval

171% 96%

53% 19% CentrifugalCompressor-Related Components Component 90% Emission Factor, Confidence

Mscf/comp-yr Interval

9352d 38% 1440 121% 16Sd 53% 18' 223%

d Adjusted for the fraction oftime the compressor is pressurized (79.1% and 24.2% for reciprocating and centrifugal compressors, respectively). • Reciprocating compressor starters were assumed to use compressed air or electricity instead ofnatural gas based on site visit data (see Appendix A). rIncludes adjustment for seals equipped with Static-Pac•.TABLE 4-16. AVERAGE COMPONENT COUNTS FOR TRANSMISSION
Component Valve Control Valve Connection Open-Ended Line Site BlowdownOpenEnded Line Pressure ReliefValve Compressor Slowdown Open-Ended Line Compressor Staner Open-Ended Line Compressor Seal Miscellaneousb Station Components• Average Component 90% Confidence Count Interval

673 26% 31 62% 3068 28% 51 60% 4 49% 14 45% Reciprocating CompressorRelated Components Average Component Count



### --' 3.3

I' • Excludes components physically connected to or directly adjacent to compressor. b Includes cylinder valve covers and fuel valves associated with compressors. "Miscellaneous equipment counted in aggregate for compressor. d Reciprocating compressor Starters were assumed to use compressed air or electricity instead ofnatural gas. Centrifugal Compressor-Related Components Average Component Count

1.5 I'TABLE4-17. AVERAGE FACILITY EMISSIONS FOR TRANSMISSION Equipment Type Compressor Station (non-compressor related components)

Reciprocating Compressor

Centrifugal Compressor Component Type Valve Control Valve Connection Open-Ended Line Pressure ReliefValve Site Slowdown OpenEnded Line Compressor Blowdown Open-Ended Line Pressure ReliefValve Miscellaneous Compressor Starter OpenEnded Line Compressor Seal Compressor Blowdown Open-Ended Line Miscellaneous Compressor Starter OpenEnded Line Compressor Seal Component Emission Factor: Mscf/component-yr 0.867

8.0 0.147

11.2 6.2 264 368Jb

__

### ,
9352'

18" 1440 Average Component Count

673 31 3068

51 14 4

1'

__

### , 3.3

1'

1.5 • Annual methane emission rate adjusted for average 93.4 vol. % methane in gas transmission. 17 Average Equipment Emissions, MMscf/yr 3.01 (Note: 3.2 MMscf/yr used in national emission estimate)"

5.55

li.I

b Adjusted for the fraction oftime the compressor is pressurized (79.I% and 24.2% for reciprocating and cemrifuga], respectively). c Reciprocating compressor starters were assumed to use compressed air orelectricity instead ofnatural gas. d Miscellaneous equipment counted in aggregate for compressor. • Adjusted for data received from one company that were not considered representative ofnational average. rIncludes adjustment for seals equipped with Static-Pac.® 90% Confidence Interval, % 102

65

34

### The average facility emissions for the station and compressor-related components were calculated as the 

### product ofthe individual component emission factors and the 

### associated average component counts. As shown in Table 4-17. the average facility emissions are 3.2 MMscf/station-yr for the station components (excluding compressor-related components), with a 90% confidence interval of± 102 %. 

### 4.4.2 Compressor-Related Components Emissions from compressor-related components were estimated separately because ofthe differences in leakage characteristics for components subject to vibrational conditions, in addition to the unique types ofcomponents associated with compressors. The types ofcomponents associated with compressors include blowdown open-ended lines, starter open-ended lines. pressure reliefvalves, compressor seals, and other components such as cylinder valve covers and fuel valves. Compressor blowdown and starter open-ended lines are unique to compressors and were found to have very high leak rates. Table 4-18 provides a breakdown ofthe compressor emissions by component type for reciprocating and centrifugal compressors. TABLE 4-18. BREAKDOWN OF COMPRESSOR EMISSIONS BY 

### COMPONENT TYPE Reciprocating Compressors CentrifugalCompressors Component Mscf/yr. % 

### Mscf/yr % 

### Type Compressor Blowdown 3,683 66.4 9,352 84.6 Open-Ended Line Pressure Relief Valve 372 6.7
. . Miscellaneous 180 3.2 18 0.2 Compressor Starter Open- . 

### . 1,440 13.0 Ended Line Compressor Seal 1,315 23.7 248 2.2 Total 5,550 11,058 

### 53Compressor Blowdown Open-Ended Lines Compressor blowdown open-ended lines allow a compressor to be depressurized when idle, and typically leak when the compressor is operating or idle. Figure 4-1 illustrates the compressor blowdown valve arrangement. There are two primary modes ofoperation leading to different emission rates for compressor blowdown open-ended lines. The first operating mode is when the b!owdown valve is closed and the compressor is pressurized, either during normal operation or when idle. The second operating mode is when the blowdown valve is open. This occurs when the compressor is idle, isolated from the compressor suction and discharge manifolds, and the blowdown valve is opened to depressure the compressor. (Note: Fugitive losses do not include the vented emissions from depressuring the compressor. 1

# '1 The fugitive emission rate is higher for the second operating mode 'Yhen 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 valve open-ended line. 

### The component emission factors for each mode ofcompressor blowdown operation wete estimated from measured data collected at 15 compressor stations using a rotameter to measure the large leakage rates. 12 Ofthe 15 compressor stations that were measured, four were operated by a company that had instituted a voluntary gas conservation program that included the investigation and repair ofleaks from compressor blowdown valves in 1984. These four stations were found to have lower than average emission rates from 

### the compressor blowdown valve when the compressor was pressurized; however, when the compressor was depressurized, the leakage rate was higher 

### thanaverage. These data were not considered significantlydifferent from the rest ofthe measurement data and were included in the overall average emission rates. Table 4-19 presents the average emission rates for compressor blowdown valves 

### in the pressurized and depressurized mode of operation.
54

### Compressor Comp.OEL BID

Discharge Block Valve
Suction Block Valve 

### -----< Open Vent

-- - - - - - - - - - - - -1



### Figure 4-1. Illustration ofCompressor Blowdown Valve Arrangement

### TABLE 4-19. AVERAGE EMISSION RATES FOR COMPRESSOR BLOWDOWN VALVES IN PRESSURIZED/DEPRESSURIZED OPERATION ReciprocatingCompressor OperatingMode

**Pressurized~** 

### Depressurizedb Emission Rate, Mscf/yr 1,361 13,729 ' Either (a) operating or (b) 

### idle, pressurized. b 

### Depressurized, idle. 90% Confidence Interval 36% 30%

An overall average component emission factor was derived for compressor 

### blowdown open-ended lines by 

### determining the fraction oftime the compressor operates in each mode (i.e., pressurized and 

### depressurized). The total fraction ofcompressors that are idle was estimated from the Federal Energy Regulatory Commission (PERC) database, the GRl TRANSDAT database, and a transmission company supplied database.20 

### The 

### fraction of idle compressors that are pressured was estimated using the data supplied 

### by 13 transmission companies. Operating practices at the sites differed significantly. (A summary is provided in 

### Appendix A for transmission, storage, and gas processing.) Overall, reciprocating compressors operated 45% ofthe time during the 1992 base year. Ofthe idle reciprocating compressors, 62% are left in a pressurized mode and 

### 38% are depressurized. Nearly all 

### (92%) centrifugal compressors are depressurized when idle. Table 4-20 shows the fraction oftime associated 

### with each operating mode for reciprocating and centrifugal compressors in gas 

### transmission.



### 56

### TABLE 4-20. OPERATING MODES OF COMPRESSORS IN GAS TRANSMISSION Percent ofTime Associated with OperatingMode OperatingMode 

### Reciprocating Compressor Centrifugal Compressor Pressurized:

In Operation 

### Idle, Pressurized 45.2 33.9 24.2 5.8 Depressurized:

Idle, Depressurized 

### 20.9 70.0 Based on the average emission rate and fraction oftime each type of compressor is pressurized versus depressurized, an overaii average component emission factor was calculated for compressor blowdown valves using Equation 

### 1.

where: (1)

EF oelloomp = component emission factor for compressor blowdown openended line; 

### ERo.,11pr = 

### average emission rate for compressor blowdown open-ended line when compressor is pressurized (operating or idle, pressurized); 

### FP, = 

### fraction ofcompressors that are pressurized (operating or idle, pressurized);

**ERid-<~epr** = average emission rate for compressor blowdown open-ended line when compressor is idle and depressurized; and Fid-depr = fraction ofcompressors that are depressurized and idle.


### The overall component emission factor is 3,683 

## ± 96% and 9,352 

## ± 38% Mscf/component-yr for reciprocating and centrifugal compressor blowdown valves, respectively, as shown in Table 4-15. Each compressor has one blowdown open-ended line. 57

### Compressor StarterOpen-Ended Lines Most compressors have a starter motor that turns the compressor shaft to start the engine. Many ofthe 

### starters use natural gas as the motive 

### force to spin the starter's turbine blades and then vent the discharge gas to the atmosphere. The inlet valve to the 

### starter can leak and therefore is considered an open-ended line unique to 

### compressors. Compressor starters that use compressed air or electricity instead ofnatural gas to power the starter motor are not sources ofmethane emissions. Based on data 

### from site visits to 

### six transmission companies, all centrifugal compressors use natural gas to power the starter motor, whereas no reciprocating compressor starter motors 

### use natural gas. The percentages ofcompressors 

### that use natural gas for starter motors inother segments are: (1) 

### storage: 50% of

### centrifugal compressors and 60% ofreciprocating compressors; and (2) processing: 100% ofcentrifugal compressors and 25% ofreciprocating compressors. Component emission factors for compressor starters were based on the measurement data 

### collected at 15 compressor stations. 12 

### The average emission rate from a compressor starter open-ended line is 1,524 Mscf/component-yr 

## ± 121%. Compressor Seals All compressors have a mechanical or fluid seal to minimize the flow of pressurized natural gas that leaks from the location where the shaft penetrates the compression chamber. These seals are vented to the atmosphere after passing through labyrinth seals ora seal oil trap and degassing tank. 

### Compressor seal emissions were measured as part ofthe transmission station fugitives study
.12 

### Different component emission rates were calculated for the 

### different operating modes ofcompressors, as follows:
• Operating and pressurized; • Idle and fully pressurized;


### 58• Idle and partially pressurized (using a fuel-saver system
- reciprocating compressors only); and • Idle and depressurized. The pressurized seal emission rates (operating and idle) were calculated as the

**ave~age** of all reciprocating and centrifugal compressor seals combined, since the data indicate that the emission rates were similar. Table 4-21 shows the compressor seal emission rates based on the data collected as part ofthe transmission station fugitives study
.12 The average emission rate for compressor seals when the compressor is idle but pressurized is slightly lower than when the compressor is operating, due to the absence ofcompressor shaft motion when the compressor is idle. About 5% ofreciprocating compressors in gas transmission have a fuel-saver system which allows the compressor blowdown line to go to the fuel gas system (net effect is that idle, pressurized compressors are not at full operating pressure). The fuel-saver system results 

### in substantially lower fugitive emission rates from the compressor seal during idle time periods where the compressor is pressurized. The overall component emission factors for compressor seals (shown in Table 4-15) were calculated based on the emission rates (Table 4-21) and fraction oftime (Table 4-20) for each mode of operation using Equation 2. (Note: For compressor seals, the emission rate was assumed to be negligible when the compressor is depressurized and idle.) 

### TABLE 4-21. COMPRESSOR SEAL EMISSION RATES OperatingMode Pressurized, Operating Pressurized, Idle Pressurized, Fuel

**Save~** ComponentEmission Rate, Mscf/seal-yr 

### 599 531 116

a Reciprocating compressors only.



### 59 90% Confidence Interval, % 30 19 46**EFsea~** = 

### where: (ER,.. ,.,..,,) X (F.,..,,) 

## + (ER,.,) X (F"_,,) 

## + (ER,,.,,) X (F,,.,,) 

### (2) EFseal = 

### component emission factor for compressor seals;

**ERsea~top-pr** = 

### average emission rate for compressor seal when compressor is pressurized and operating; 

### Fop-pr 

### = fraction ofcompressors that are pressurized and operating; ERid-pr = 

### average emission rate for compressor seal when compressor is idle and pressurized; Fid-pr 

### = fraction ofcompressors that are pressurized and idle; ER.rs-pr = 

### avei-age emission rate for compressor seal when idle, partially pressurized on a fuel-saver system; and Ffs-pr = 

### fraction ofcompressors that are idle. partially pressurized on a fuel-saver system. Reciprocating compressors have sliding shaft seals equal in number to the stages ofcompression_ The average number ofreciprocating compressor seals in 

### transmission was estimated from data collected at four gas transmission sites with a total of 47 reciprocating compressors. The average number ofseals per compressor was calculated for each site and the overall average for the four sites used as the average component count for reciprocating compressor seals. The average component count of3.3 seals per reciprocating compressor compares well with system-wide data supplied by a major gas transmission company_ An additional adjustment was made to account for the number of reciprocating compressors seals equipped with **Static-Pac.~ 21**  

### According to the vendor, this device can reduce oreliminate gas leakage from idle. pressurized compressor seals_ 

### An estimated 1750 kits for reciprocating compressor seals have been sold in the gas industry.21 

### These were accounted for 

### in the component emission factor as having negligible fugitive emission rates; however, the overa11 industry effect was small since this device is used on less than 8% ofthe reciprocating compressors in 

### transmission.



### 60

### The number ofcentrifugal compressor seals per compressor depends on the type ofcompressor. As shown in Figure 4-2, centrifugal compressors with overhung rotors have one seal and beam-type compressors have two compressor seals. According to the results ofa survey ofthree compressor vendors and one seal vendor,22 

### there is an even split between the number ofoverhung and beam-type centrifugal compressors in the gas industry. In addition, the more recent trend toward dry gas seal technology as opposed to mechanical contact (face or sleeve seals with oil lubrication) was evaluated. Although the dry gas seal technology could potentially result in lower emissions, this is a recent trend for new installations and was estimated to have a negligible impact on emissions from compressor seals in 1992, the base year ofthis study. 

### Other Components The component emission factors for other components associated with compressors, such as pressure relief valves, were adjusted for the average fraction oftime compressors are pressurized in 

### transmission service (79.1% 

### and 24.2% for reciprocating and centrifugal compressors, respectively). 

### 4.5 Gas Storage Facilities Equipment leaks from gas storage facilities were separated into three categories due 

### to differences 

### in leakage characteristics:

• Station components including all sources associated with the storage station inlet and outlet lines, meter runs, dehydrators, and other piping located outside ofthe compressor building; • Injection/withdrawal well components including all sources associated with the injection/withdrawal well "Christmas tree" piping configuration; and • Compressor-related components including all sources physically connected to or immediately adjacent to the compressors. 61Inlet G"ido '- 

# 1\'1 Vanes 

### ""r--l 

# i\

Sucti011 

# ""''' (in!«) 

## 11-1"~-'-r"l 

# u \\

Overhung **Axi~lnlet** CentrifugalCompressor (SingleSeal)



### Beam-Type Centrifugal Compressor (Two seals) Couplingand DriveEnd



# - .....

Figure4-Z. Overhung and Beam· Type CentrifugalCompressors 

### 62

### The component emission factors, average component counts, and average facility emissions for station, injection/withdrawal well, and compressor-related components in gas storage are presented in Tables 4-22 through 4-24. Table 4-22 presents the component emission factors for storage facility components (discussed in Section 4.5.1), compressorrelated components (discussed in Section 4.5.2), and injection/withdrawal wellhead-related components (discussed in Section 4.5.3). Table 4-23 presents the average component counts for storage compressor stations. Table 4-24presents the average facility emissions for station and compressor-related components. The component emission factors and average component counts for station-, compressor-, and injection/withdrawal weiihead-related components are discussed in Sections 4.5.1 through 4.5.3. 

### 4.5.1 Station Components Component emission factors for station components not associated with the compressors or wellheads are similar in type, service, and operation to those in gas transmission. Therefore, component emission factors for the station components 

### in gas storage are the same as for gas transmission, as shown in 

### Table 4-22.



### 63a, 

# ... TABLE 4-22. COMPONENT EMISSION FACTORS FOR GAS STORAGE' Reciprocating Centrifugal Injection/Withdrawal Compressor- CompressorWellhead-Related Related Related Component Station Components' Components Components Components Valve 0.867 0.918 (10%) 

### Connection 0.147 0.125 (9%) 

### Open-Ended Line 11.2 0.237 (33%) 

### Site Blowdown Open- 264 (84%) 

### Ended Line Pressure ReliefValve 6.2 1.464 (37%) 317' (171 %) Compressor Blowdown 5024' (71%) I0233' (35%) Open-Ended Line Compressor StarterOpen- 1440 (121%) 1440 (121 %) 

### Ended Line Compressor Seal 300' (53%) 126' (53%) 

### Miscellaneousc 153' (19%) 17' (223%) a 

### Component emission factors in Mscf/component-yr. Values in parentheses represent the 90% confidence interval. Total

methane emission rate adjusted for average 93.4 vol. 

### %methane 

### in gas transmission/storage. 17

**~>** Excludes components physically connected to ordirectly adjacent 

### to compressor. c 

### Includes cylinder valve covers and fuel valves associated with 

### compressors. d Adjusted for the fraction oftime the compressor is pressurized (67.5% and 22.4% for reciprocating and centrifugal

compressors, respectively).

# "' V> TABLE 4-23. AVERAGE COMPONENT COUNTS FOR GAS STORAGE' Injection/Withdrawal Reciprocating Centrifugal Station ·Wellhead-Related Compressor-Related Compressor-Related Component Components" Components Components Components Valve 1868 (120%) 30 (82%) Connection 5571 (120%) 89 (82%) Open-Ended Line 353 (194%) 7 (98%) Site Slowdown Open- 4 (74%) Ended Line Pressure Relief Valve 66 (!07%) I (130%) Compressor Slowdown Open-Ended Line Compressor Starter 0.6' 0.5' Open-Ended Line Compressor Seal 4.5 1.5 Miscellam:uusd I" I" aAverage component counts. Values in parentheses·represent the 90% confidence interval. b Excludes components physically connected to or directly adjacent to compressor or wellhead. '" Adjusted for the fraction ofcompressor starters using natural gas (60% and 50% for reciprocating and centrifugal compressors, respectively). d Includes cylinder valve covers and fuel valves associated with compressors. • Miscellaneous equipmentcounted in aggregate for compressor.TABLE4-24. AVERAGE FACILITY EMISSIONS FOR GAS STORAGE ComponentEmission Average AverageEquipment 90% Confidence Factor,• Component Emissions, Interval, Equipment Type ComponentType **Mscf/component~yr·** Count MMscf/yr % Storage Facility

**(non~** Valve 0.867 1868 7.85 !00 compressor related Connection 0.147 5571 components) Open-Ended Line 11.2 353 Pressure ReliefValve 6.2 66 Site Blowdown 264 4 Open-Ended Line Injection/Withdrawal Valve 0.918 30 0.042 76 Wdihead Connection 0.125 89 Open-Ended Line 0.237 7 Pressure ReliefValve 1.464 Reciprocating Compressor Blowdown 5024b 7.71 48 a, Compressors Open-Ended Line a, Pressure ReliefValve 317b Miscellaneous l53b I Compressor Starter 1440 0.6< Open-Ended Line Compressor Seal 300' 4.5 Centrifugal Compressors Compressor Blowdown Open-Ended Line l023Jb ll.l6 34 Miscellaneous !7" Compressor Starter 1440 

### o.sc Open-Ended Line CompressorSeal l26b 1.5 • Total methane emission rate adjusted for average 93.4 vol.% methane in gas transmission/storage. 17 b Adjusted for the fraction oftime the compressor is pressurized (67.5% and 22.4% for reciprocating and centrifugal compressors, respectively). o Adjusted for the fraction ofcompressor starters using natural gas (60% and 50% for reciprocating and centrifugal compressors, respectively).

### The average component counts for station components were based on site visits to five storage facilities as part ofthe GRI/EPA methane emissions program. Table 4-23 presents the average component counts for gas storage. The overall average facility emissions were estimated as the product ofthe component emission factors and the average component counts. Table 4-24 presents the average facility emissions for gas storage, with the associated 90% confidence interval. 

### 4.5.2 Compressor-Related Components The individual component emission rates for compressor-related components (e.g., compressor blowdown open-ended lines, starter

**open~ended** 

### lines, and compressor seals) in 

### gas storage are identical to those estimated for gas transmission (refer to Section 4.4). However, the overall component emission factors for compressor blowdown openended lines and compressor seals in storage were adjusted for the average time allocated to each mode ofoperation: pressurized and operating, pressurized and 

### idle, and depressurized and idle. Table 4-25 shows the fraction oftime associated with each operating mode for reciprocating and 

### centrifugal compressors in 

### gas storage. The component counts for compressor starter open-ended lines were adjusted for the fraction of starters using natural gas. Based on data from five sites, 60% of reciprocating compressors and 50% ofcentrifugal compressors use natural gas starters in 

### gas storage facilities. 

### 4.5.3 Injection/WithdrawalWellhead-Related Components The component emission factors for onshore gas production equipment (Section 4.1.2) were used to estimate emissions from storage wellheads and related equipment. The component emission factors for onshore gas production in the Western U.S.

67

### TABLE 4-25. OPERATING MODES OF COMPRESSORS IN GAS STORAGE Operating Mode Pressurized:

In Operation Idle. Pressurized 

### Depressurized:

Idle, Depressurized Fraction ofTime Associated with 

### OperatingMode Reciprocating Compressor Centrifugal Compressor 43.1 24.4 

### 32.5 22.4 

### 0 77.6 

### (Table 4-6) were adjusted for an average of93.4 

### volume %methane from equipment leaks in gas transmission/storage. 17 

### Average component counts for injection/withdrawal wellhead-related 

### components were based on the site visit"data from five storage facilities. 

### 4.6 Customer MeterSets Commercial/industrial and residential customer meter sets include the meter itselfand the related pipe 

### and fittings. Leakage from customer meter sets occurs from the 

### fittings associated with 

### the meter, includingthe valve, regulator, and inlet and outlet pipe connectors. Although thejoints and gaskets associated 

### with the meter were screened, virtually no leakage was detected from the meter itself. Equipment emission factors from customer meter sets were estimated based on test data collected from 10 local distribution companies across the United States. 13•14•15 

### Customer meter screening data were coUected at three Eastern U.S. sites, a midwestern site, a Rocky Mountain site, and five Western U.S. sites. A summary ofthe total number of meter sets tested, the number and percentage ofleaking meters, and the average emission rates from each ofthe 10 sites is shown in 

### Table 4-26. A total ofapproximately 1600 meter 

### 68

### TABLE 4-26- SUMMARY OF EMISSION RATES FROM OUTDOOR RESIDENTIAL CUSTOMER METER USERS Numberof Number of Perceotage of Average Leak Standard Meters Meter Sets Meter Sets Rate,• 

### Deviation," 

### Site Screened 

### Leaking Leaking lb methane/day lb methane/day Site 1 -- West Coast 

### 134 37 27.6 0.0098 0.0239 Site 2
-- East Coast 40 29 72.5 0.0002 0.0004 Site 3
-- East Coast 158 37 23.4 0.0789 0.1753 Site 4 -- Midwest 

### 156 8 5.1 0.0057 0.0061 Site 

### 5 -- Rocky Mountain 

### 188 28 14.9 0.0035 0.0082 Site 6 -- West Coast 

### 194 5 2.6 0.0002 0.0001 Site 7 -- Southeast 

### 201 56 27.9 0.0146 0.0328 

# "' Site 8
-- Northwest 101 31 30.7 0.0101 0.0199 'D Site 9 -- Southwest 

### 150 50 33.3 0.0222 0.0404 Site 10
-- Northwest 150 40 26.7 0.0125 0.0230

Average 

### 0.0158
a 

### Average value for all meters (i.e.. leaking and non-leaking) screened at 

### the site.

### sets were tested as part ofthe GRI!EPA study. About 20% ofthe meter sets were found to be leaking at low levels. The average leak rate permeter set was only 0.0157 scf/hr. For the majority ofcustomer meter sets screened. the 

### GRl Hi-Flow sampler 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. Average emission rates from the customer meter sets screened at each site were estimated by averaging the emission rates ofall the meters screened, including those where no measurable leak was detected by the screening instrument. The overall average equipment emissions for outdoor residential customer meter sets were derived by 

### averaging the emission rates for the 10 sites. Emissions from indoor meters are much lower 

### than for outdoor meters because gas leaks within the confmed space ofa residence are readily identified and repaired. This is consistent with the findings that pressure regulating stations located in vaults have substantially lower emissions than stations located above-ground.2 

### The emissions from indoor customer meters were assumed to be negligible. Fugitive screening ofcommercial/industrial meter sets was conducted at four sites for a total of 149 meter sets. A summary ofthe total number ofmeters screened, the nwnber and percentage ofleaking meter sets, and the average emissions from each ofthe four sites is shown 

### in Table 4-27. 

### The overall equipment emissions from conunerciaiiindustrial customer metersets were derived by averaging the emission rates for the four sites. The resulting average equipment emissions are 47.9 scf/meter-yr 

### ± 35% for conunerciai!industriai meter sets.

70

### TABLE 4-27. SUMMARY OFEMISSION RATES FROM COMMERCIAL/INDUSTRIAL CUSTOMER METER SETS Number of Number of Percentage of Meters 

### Meter Sets Meter Sets Site Screened 

### Leaking Leaking Site 3 -- East Coast 

### 45 12 26.7 Site 4 -- Midwest 

### 61 0 0 Site 

### 5 -- Rocky Mountain 

### 21 6 28.6 Site 6 -- West Coast 

### 22 

### I 4.5 Average

a Average value for all meters (i.e.• leaking and non-leaking) screened at the site. 

### Average Leak Rate," 

### Ib methane/day 0.0112 0.0088 0.0018 0.0055 

### Standard Deviation," 

### lb methane/day 0.0251 0.0076

### 5.0 NATIONAL EMISSIONS FROM EQUIPMENT AND FACILITIES Methane emissions from equipment leaks using the component approach were extrapolated to 

### a national estimate for the 1992 base year. The national armual emissions are the product ofthe average equipment orfacility emissions, as documented in Section 4, and 

### a national activity factor. The national activity factor is the population ofsources, equipment or facilities, within the U.S. natural gas industry. Although some national population statistics are published, such as the number ofonshore gas wells, others were not known and 

### had to 

### be calculated, such as the number ofseparators in onshore gas production. This section documents the national activity factors that were used to 

### develop the national emissions estimate for each source withinthe gas industry where the component method was used to quantitate fugitive emissions. A detailed discussion ofthe activity factors is provided 

### in Volume 5 on activity factors.23 

### 5.1 

### Onshore Gas Production National activity factors are provided for the following onshore production equipment:


## • Gas wells; 

## • Separators; 

# • Heaters; 

## • Dehydrators; 

## • Metering runs; and 

# • Gathering compressors. Table 5-1 presents the national activity factor estimates for onshore production in the Eastern and Western U.S. regions, along with the 90% confidence interval. 72TABLE 5-1. NATIONAL ACTIVITY FACTORS FOR GAS PRODUCTION Eastern U.S. Western U.S. Activity 90% Activity 90% Factor, Confidence Factor, Confidence Equipment Count Interval, % Connt 

### Interval, % Gas Wells 129,157 

### 5 142,771 

### 5 

### Separators 91,670 23 74,674 57 Heaters 260 196 50,740 95 Dehydrators 1,047 20 36,777 20 Metering Runs 76,262 100 301,180 100 Small Gathering 129 33 16,915 52 Compressors Large Gathering 96 100 Compressors Large Gathering 12 100 Compressor Stations


### The total number ofactive gas wells is a nationally tracked statistic. The breakdown between gas wells in the Eastern and western

# u.s. regions was based on a count ofproducing gas wells published by the American Gas

**Association?~** Total U.S. activity factors or equipment counts for separators, heaters, metering runs, and gathering compressors were based on site visit data. For all equipment except dehydrators, the average count per well was calculated from the site visit data and used to calculate a regional estimate based on the regional well count. The total number·of glycol dehydrators in gas production were based on published data from a separate GRJ study. 25 The equipment counts associated with Eastern U.S. production were estimated from data collected during the measurement program conducted at 12 Eastern production sites.8 Likewise, the equipment associated with production in the

**W~stern** U.S. was estimated based

73on data collected as part ofthe oil and gas production fugitive emissions measurement program9 and 13 additional site visits conducted as part ofthis program. The extrapolation to national methane emissions from onshore production is shown in Tables 5-2 and S-3 for Eastern and Western U.S. regions, respectively. As shown, the national annual methane emissions from onshore production in the Eastern and Western U.S. are 0.63 Bscf 

## ± 46% and 15.6Bscf 

## ± 45%, respectively. TABLE 5-2. NATIONAL ANNUAL EMISSIONS FROM ONSHORE PRODUCTION IN THE EASTERN U.S, Average Activity. Equipment 

### Factor, AnnualMethane 90% Confidence Emissions, Equipment Emissions, 

### Interval, Equipment scf/yr Count Bscf % Gas Well 2,595 129,157 0.34 27 Separator 328 91,670 0.03 36 Heater 5,188 260 0.001 218 Dehydrator 7,938 1,047 0.008 41 Meters/Piping 3,289 76,262 0.25 109 Gathering 4,417 129 0.0006 44 Compressors Total 0.63 46

74TABLE 5-3. NATIONAL ANNUAL EMISSIONS FROM ONSHORE PRODUCTION 

### IN THE WESTERN U.S. 

### Average Activity Annual 90% Equipment 

### Factor, Methane Confidence Emissions, Equipment Emissions, 

### Interval, Equipment sef/yr 

### count Bscf % Gas Well 13,302 142,771 1.9 25 

### Separator 44,536 74,674 3.33 69 

### Heater 21,066 50,740 1.07 110 Dehydrator 33,262 36,777 1.22 32 

### Meters/Piping 19,310 301,180 5.82 109 Small Gathering 97,729 16,915 1.65 93 

### Compressors Large Gathering 5.55E+06 

### 96 0.53 136 

### Compressors Large Gathering 3.0IE+06 12 0.04 176 

### Compressor Stations Total !5.6 45 

### 5.2 Offshore

### Gas Production The activity factors for offshore gas production were based on data from the Minerals Management Service26 and Offshore Data Services27 for the Pacific OCS and Gulf ofMexico, respectively. Half ofthe offshore platforms were allocated to the oil industry and, therefore, were not included within the boundaries ofthe gas industry. Table 5-4 

### summarizes the activity factors and resulting annual methane emissions from offshore production. As shown, the national fugitive emissions from offshore production are 1.2 Bscf 

### ± 29%.

75TABLE 5-4. NATIONAL ANNUAL EMISSIONS FROM OFFSHORE PRODUCTION Activity Average 

### Factor, Annual 90% Facility Number of Methane Confidence 

### Emissions, Platforms 

### in 

### Emissions, Interval, Region Mscf/yr Gas Industry Bscf % Pacific OCS 430 22 0.01 38 GulfofMexico 1,064 1,092 

### 1.16 29

Total 

### 1.17 29 

### 5.3 Gas Processinll The number ofgas processing plants in the U.S. was based upon published statistics from the Oil & 

### Gas 

### Journal." Based upon data from 1992, the total number ofgas plants is 726. A confidence limit of 

### ± 2% was assigned based on engineeringjudgement. The number and type ofcompressor drivers 

### in gas processing were based on site visit data from 

### 11 gas plants. The average ratios ofreciprocating and centrifugal compressors per plant were scaled up to national estimates by multiplying by the total number ofgas plants. 

### The confidence interval was estimated from a statistical analysis ofthe individual site averages. The split between reciprocating and centrifugal compressors estimated from the site visit data (i.e.• 85% reciprocating and 15% centrifugal) agrees well with the results from a national survey conducted in the 1980s'' (i.e., 90% reciprocating and !0% centrifugal). The national annual emissions from gas processing plants was calculated as the product ofthe activity factor and the average facility emissions (see Section 4.3). Table 

### 5-5 presents a sununary ofthe national annual emissions from gas processing plants in the U.S. Emissions from compressor-related components account for the majority ofthe total 24.4 Bscf 

## ± 68% fugitive losses from gas processing plants.



### 76TABLE 5-5. NATIONAL ANNUAL EMISSIONS FROM GAS PROCESSING Activity Average Factor, Annual 90% Facility Number of Methane Confidence Equipment/ Emissions, Plants/ Emissions, 

### Interval, Facility MMscf/yr Compressors Bscf % Gas plants 2.89 726 2.1 48 Reciprocating 4.09 4,092 16.7 95 

### Compressors Centrifugal 7.75 726 5.6 91 

### Compressors Total 24.4 68 5.4 Transmission Compressor Stations The activity factor for transmission compressor stations was based on nationally tracked statistics by the Federal Energy Regulatory Conunission (FERC).20 The data reported to PERC account for around 70% ofthe total transmission pipeline mileage. The average station per mile data from FERC was extrapolated to a national estimate based on the total transmission pipeline mileage.24 

### The confidence interval was estimated as 

### ± 10% based on engineeringjudgement. The split between reciprocating and turbine compressor engines in gas transmission was estimated from the GRI TRANSDAT database,30 adjusting for the total industry horsepower. Transmission compressor stations were split from those associated with storage according to site visit data from eight storage stations and published information on storage stations.24 A further adjustment was made to account for compressors with electric motor drivers. The 90% confidence interval ofthe estimate was calculated from the variation in site visit data accounting for the storage station allocation and assignment of 

### ± 10% error in the GRI TRANSDAT database information.

77Table 5-6 presents the annual methane emissions from transmission compressor stations in the United States. As shown, the overall estimate of50.7 Bscf 

## ± 52% from transmission compressor stations is primarily due to fugitive emission losses from compressor-related components. TABLE S-6. NATIONAL ANNUAL EMISSIONS FROM TRANSMISSION COMPRESSOR STATIONS Average Activity Annual 90% Facility 

### Factor, Methane Confidence Equipment/ 

### Emissions Number ofStations/ Emissions, 

### Interval, Facility 

### MMscf/yr 

### Compressors Bscf % Compressor 3.2 1700 5.4 !03 Stations Reciprocating 5.55 6799 37.8 68 Compressors Centrifugal 11.1 681 7.5 44 Compressors

Total 50.7 52 

# s.s Gas

**Stora~e** Facilities The activity factors for storage injection and withdrawal and liquefied natural gas (LNG) storage facilities were compiled from published statistics. The number of underground storage facilities and LNG storage facilities is based onpublished data in Gas 

### Facts. 24 As previously discussed in Section 5.4, the activity factor for compressors associated with gas storage were estimated from data collected during visits to eight storage sites. The number ofinjection/withdrawal wells was also estimated from the site visit data. The annual fugitive emissions from gas storage facilities are presented 

### in Table 5· 7. As shown, the total annual emissions are 16.8 Bscf 

## ± 57%.

78TABLE S-7. NATIONAL ANNUAL EMISSIONS FROM GAS STORAGE FACILITIES Activity Average Factor, Annual 90% Facility Nmnber of Methane Confidence Equipment/ Emissions, Facilities/ 

### Emissions, Interval, Facility MMscf/yr 

### Compressors Bscf % Storage 7.85 475 3.7 100 

### Facilities Injection/ 

### 0.042 17,999 0.75 76 Withdrawal Wells Reciprocating 7.71 1,396 10.8 80 

### Compressors Centrifugal 11.16 136 

### 1.5 130 

### Compressors

Total 16.8 57 

### 5.6 Customer Meter Sets

· The total number ofresidential and commercial/industrial customer meters 

### in the U.S. gas industry was based on published data available 

### in 

### Gas Facts

### ? 4 The number of residential customer meters located indoors versus outdoors was estimated based on a published regional breakdown oftotal customers combined with data obtained from 22 individual gas companies within different regions ofthe country. (Note: The number of customers in each region was assumed to be equivalent to the number ofcustomer meters because a regional breakdown ofcustomer meters was not available.) Table 5-8 summarizes the average percentage of customer meters located indoors 

### in each region.

79

### TABLE 5-8. STATISTICS ON INDOOR CUSTOMER METERS BY REGION Average Total Percent 

### Estimated 90% 

### Residential Indoor Sample Indoor Confidence Region Customers Meters Size 

### Meters Interval New England 1,886,500 52 I 

### 980,980 471,625' Middle 8,403,400 61 7 5,126,074 I 

### ,905,371 Atlantic East North I I

### ,633,500 17 7 I 

### ,977,695 1,461,663 

### Central West North 4,684,100 

### 40 I I 

### ,873,640 1,873,640' Central South Atlantic 

### 4,987,700 21 4 I 

### ,030,680• I 

### ,030,680' East South 2,465,200 0 0 123,260' Central West South 5,666,600 0 0 283,330' Central 

### Mountain 3,318,700 0 0. 331,870' Pacific 

### 9,724,500 5 2 486,225 486,225'

Total 52,770,200 22 I 

### 1,475,294 3,317,254 a 

### Estimated based on engineeringjudgement. b 

### Estimated for each state separately in region, since Northern States (Maryland and



### Delaware) are included. c 

### Estimated based on industry comments suggesting that customer meters in southern

regions are essentially all located outdoors. The 

### estimated number ofindoor meters, 11.475,294, was subtracted from the 

### total number ofreported meters, 51,524,600, toderive an estimated 40,049,306 outdoor residential customer meters 

### in the United States. 

### The 90% confidence interval was estimated from the data provided 

### by companies, engineeringjudgement for some regions, and an estimated 5% 

### error in the nationally reported number ofresidential customer meters.



### 80

### For conunercial/industrial customer meters, the activity factor of4,608,000 is a nationally tracked statistic24 

### and the precision is assumed to be 

## ± 5% based on engineering judgement. The total annual emissions from customer meter sets are presented in Table 5-9. As shown, customer meters contribute 5.8 Bscf 

### ± 20% to annual methane emissions from the gas industry.

TABLE 

### S-9- NATIONAL ANNUAL EMISSIONS FROM CUSTOMER METER SETS Average Activity 

### Annual 90% 

### Equipment 

### Factor, Methane Confidence Emissions, number of Emissions, 

### Interval, .Category scf/yr · meter sets Bscf % 

### Outdoor residential 138.5 40,049,306 

### 5.55 20 meter sets Commercial/industrial 47.9 4,608,000 0.22 35 meter sets

Total 5.77 20



### 81

### 6.0 REFERENCES I. 

### Campbell, L.M., M.V. Campbell, and D.L. Epperson. Methane Emissions from the Natural 

### Gas Industry, Volume 9: Underground Pipelines, 

### Final Report, GRI-94/0257.26 and EPA-600/R-96-0SOi; Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 2. Campbell, L.M. and B.E. Stapper. Methane Emissionsfrom the Natural Gas Industry, Volume 10: Metering andPressure Regulating Stations in Natural 

### Gas Transmission andDistribution, 

### Final Report, GRI-94/0257.27 and EPA600/R-96-0SOj, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 3. Hausle, K.J. Protocol forEquipmentLeakEmission Estimation, 

### EPA-453/R- 93-026 (NTIS PB93-229219), Office ofAir Quality Planning and Standards, June 1993. 4. Code of FederalRegulations, Title 40, Pan 60, AppendixA. 

### National 

### Archives and Records Administration, Office ofthe Federal Register, July 1. 1995. 5. U.S. Environmental Protection Agency. 

### New EquipmentLeakEmission FactorsforPetroleum Rejinen·es, GasolineMarketing, and Oil & 

### Gas Production Operations 

### (EPA file LEAKS_95.WP5; background file LKS95_BK.ZIP). U.S. Environmental Protection Agency, Office ofAir Quality Planning and Standards, Technology Transfer Network bulletin board system, February 1995. 6. Lott, 

### R., M. Webb, and T. Howard. "Sampler Enables Measurement of 

### Leaks on Site-Specific Basis." 

### American Oiland Gas Reporter, March 1995, pp. 61-66. 7. Howard, T., et al. A High FlowRate Sampling SystemforMeasuring Leak 

### Rates atNatural 

### Gas System Process Components. 1994 International Workshop: Environmental and Economic Impacts ofNatural Gas Losses, Prague, Czech Republic, Man:h 1994. 8. 

### Star Environmental. Fugitive Hydrocarbon Emissions: Eastern Gas Wells, 

### Final Report, GRI-95/0117, Gas Research Institute, July 1995. 9. 

### Star Environmental. Fugitive Hydrocarbon Emissionsfrom Oiland Gas Production Operations, 

### API Publication Number 4589. American Petroleum Institute, December 1993. 

### 82!0.


### II. 12. 13.
14. !5. !6.

17.

!8.

!9.

20. ABB Environmental Services. 

### Fugitive Hydrocarbon Emissionsfrom Pacific OCSFacilities, MMS Report 92-0043, U.S. Department of the Interior, Minerals Management Service, November 1992. Star Environmental. 

### Emission Factorsfor Oil and Gas Production Operations, API Publication No. 4615. American Petroleum Institute, January 1995. Indaco Air Quality Services, Inc. 

### LeakRate Measurements at U.S. Natural 

### Gas Transmission Compressor Stations, Gas Research Institute, July 1994. Indaco Air Quality Services, Inc. 

### Methane Emissionsfrom Natural Gas CustomerMeters: Screening andEnclosure Studies, Draft Report, August 15, !992. Indaco Air Quality Services. 

### LeakRate Measurementsfor Natural Gas 

### CustomerMeters: Gas Research Institute, 1996. Star Environmental. 

### FugitiveMethane Emissions: CustomerMeter Sets, Final Report, GRI-95/0204, Gas Research Institute, July 1995. Williamson, H.J., M.B. Hall, and M.R. Harrison. 

### Methane Emissionsfrom theNatural Gas Industry, Volume 4: StatisticalMethodology, Final Report, GRI-94/0257.21 and EPA-600/R-96-080d, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. Shires, T.M. and M.R. Harrison. 

### Methane Emissionsfrom the Natural Gas Industry, Volume 6: Vented and Combustion Source Summary, Final Report, GRI-94/0257.23 and EPA-600/R-96-080f, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. Dobose, D.A., J.l. Steinmetz, G.E. Harris, and J.W. Kamas. 

### Frequency of Leak Occurrence andEmission Factorsfor Natural Gas Liquids Plants, EMB 80-FOL-1. U.S. Environmental Protection Agency, Emissions Measurement Branch, July !982. Shires, T.M. and M.R. Harrison. 

### Methane Emissionsfrom the Natural Gas Industry, Volume 7: Blow and Purge Activities, Final Report, GRI-94/0257.24 and EPA-600/R-96-080g, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. Stapper, C.J. 

### Methane Emissionsfrom the Natural Gas Industry, Volume 11: Compressor DriverExhaust, Final Report, GRI-94/0257.28 and EPA-600/R96-0SOk, Gas Research Institute and U.S. Environmental Protection Agency, June 1996.
83

### 21. 22.
23.
24. 25. 26.
27. 28. 29.
30. Telephone conversation with Paul Hanlon, C. Lee Cook (Louisville, KY) by K.E. Hummel, Radian Corporation, February 16, 1995. 

### Memorandum to M.R. Harrison, Radian Corporation, from K.E. Hummel, Radian Corporation. "Overhung versus Beam-Type 

### Centrifugal Compressors in Transmission Pipeline Service," August 1994. Stapper, B.E. Methane Emissionsfrom theNatural Gas Industry, Volume 5: ActivityFactors, 

### Final Report, GRI-94/0257.22 and EPA-600/R-96-080e, Gas 

### Research Institute and U.S. Envirorunental Protection Agency, June 1996. American Gas Association, Gas Facts. 

### Arlington, VA. 1992. Wright Killen & 

### Co. Natural Gas Dehydration: Status and Trends, 

### Gas Research Institute, GRI-94/0099, January 1994. 

### Minerals Management Service. Users Guide. MMS Outer Continental Shelf ActivityDatabase (MOAD), 

### OCS Study MMS 94-0018, U.S. Department of Interior, New Orleans, LA, April 1994. 

### Telephone conversation 

### with David Sutherland, Offshore Data Services (Houston, Texas) by K.E. Humnte1, Radian Corporation, April 27, 1994. Oil & Gas Journal. 

### !992 Worldwide Gas Processing Survey Database, 1993. Farmer, J.R. EquipmentLeaks ofVOC inNatural Gas Production IndustryBackgroundInformationfor Promulgated Standards, 

### EPA-450/3-82-024b (NTIS PB85-233112), May 1985. Biederman, N. GRI TRANSDAT Database: Compressor Module. (prepared 

### for Gas Research Institute). npb Associates 

### with Tom Joyce and Associates, Chicago, IL, August 1991.

84APPENDIX A 

### CompressorBlowdown OperatingPractices

A-l

### TABLEA-1. COMPRESSORBLOWDOWNVALVEOPERATINGPRACTICES- TRANSMISSION

-

**--==--~** -- No. ml
**~lnt:~** Turblnn Sil..



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

# ..... AlmBD 

# ..

# _. r.o.c.....,.._PnttJc,a



### ·~ Aim BD Stp:ua!t ld'- Com-l"raclk5

**-~** 

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# ...... '"" 

# ...... ....

# .. .....

# .. 'llal•e ODU... Sh"-'"' 

# ... b71biri 

## ""' u..c. 

# ... loLowP 

## ..!:: OOp.
**or..o..~r ~G•**  U...Go 

# ... CaLow P Do- 00p. ill' Lo..., **""~;_,_,** 

# '"""" ' 

# ... TC>Aim 

# '"' 

# ,_, 1oAtm 

# .. ToAim 

# '"' Spltft>! .\!lot 

# -- ...

# _ =-- l"r........ p,.._.,.,.•• 

### '"

- 

### ' N 

# " ; .f diiiDpiO 

### ' 

## ' - - - 

## ·- - - "'I""' 

### ' D N 

## '
**Nota~** 

## ' ; 

# ,.... N I ouro 

## '"' ' N 

# • Nola-.blo 

## ' ; 

# ,.... N .faulo 

# • N 

## • ; ; 

## '

- - - ---· 

## ' 

# ., N 

## ' ; ; 

## • 

# •

- ------
- 

## • N 

### - No.Wa



## - Nod•l•

·- 

### ' N 

# • NOII-.bio 

## ' ' ; 

# "

-- 

# • N 

# • Nota....!<rablo 

## ' ' ; 

### . , " 

## • 

# .. N 

# " ; 

# ,. ; 

## • ' '"' I



### - ' 

# " N 

# • 

# ,. ; I ; 

### ' 

# '

- 

# .. " N 

## ' ; 

# ,. ' ' -· 

### - .. 

## ·- --

- - 

# " N 

# • ' 

# ,. ; 

## • - - 

### - ·- . . 

### ----- 

# ., n N 

# " ; 

# ,. ' ' ; 

## ' ;

---- 

## " N 

# " ; 

# •• N 

# .... ' • ' 

# ' 

# • N ; >W 

# " " N 

# " ; 

# ,. N .(If>l41u" ; 

## ' ' 

# ' ' N ; t<MJ 

### ---- . 

# " 

# ,

-- 

# " 

# "

-

## >- ' w F 

### -- No.cf 

## "'g

**R~pro** oonltd 

# "" "• l>y tbJI 

# "'" 

# ....... ' 

# " Y"' 

## " "' N 

# " N 

# "

**~** N 

# " • N 

## " 

# • N

**~** n N••• 

# " 

# .. n 

# " "

**l<~ai.-IA•es** 

# ... 

# ..
'I

**o·o>trlfupl<ompr~r** >rilb r..:lproc.Cinr:tflllr>t. ''FLoro does 1101 hand!< Comp BOor Sll< BD. ••• Sit• llllro Ill 2ftf H fo<iiiHN. ''''Sil< d.-p«""ur<d In

**1~** p:m. 

# ...... u..c. No. ToAim 

## • 

# • ' 

# • •• 

# • " 

# • ' 

# • • • 

# • • • • 

# • "' 

# ·- TABLEA-1. (Continued)

. RecipToco1lnC

**&~,;,...** AunBD 

# ,.,.,... Idle Comp,...or Ptlkllc.,. Vlln 

# ....... 

# ... toLow P 

# ,.:;,. oo,. SJIII.<m! oLo
...r 

# ""' 

# .........

**"-~** I 112" N 

# • 

# • 

# .... , . N I 

# • ,. 

# • • NaC opplkoblt 

# , . N 

# • • 

# • .[dumpto 

# ...""' 

# • • I dumpto 

# ""'""' l-4" 4121 "' &Ill "' U/21

**~** !Ill "' 1 •.11.. 38.1'4 57.1... 

## ....... - - ---- ---·· - -""=--'- !urhi"" 

## .0, .l.tmBD Separat< ldlo Comp<e«Or

**Pra<Ho~** 

## •0' sun.... 

# """

# .. Val•• BD Un< Stol"!<r' on Ga. Lin< GO 

# ... tolow P 

# .. cop. "" (;., !<> OLo,.or



### -·~ No. To Aun (in) Sy•lom! ressur< Prossuro Prcsom< Aim



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### --

**0.0~** 

# .. •oo• >4' 11.11'1. tl/IJ = !!B

**~** 

### "-""' lOU'' 92.}-J, 1.1.. 

### II

. -

### TABLEA-2. COMPRESSORBLOWDOWN VALVE OPERATING PRACTICES.STORAGESTATIONS

**~·** 

# .. No. ol 

# .... ...... 

# _ .. "" 

# ...... ,,

# ... ..... 

# ....... 

# ... ...... ' No. To Aim 

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- GAS PROCESSING PLANTS

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=--=- H•nAPPENDIXB 

### Source Sheets

B-1SOURCESo OPERATING MODEo EMISSION TYPEo ANNUALEMISSIONS: BACKGROUNDo P-2 PRODUCTION SOURCE SHEET All Production Equipment {SeeBelow) Nonnal Operation Steady,Fugitive l7.4Bscf±41% Equipment leaks are typically low-level, unintentional losses ofprocess fluid (gas orliquid) from the sealed surfaces ofabove-ground process equipment. Equipmentcomponents thattend to leak include valves, flanges and other connectors, pumpseals, compressorseals, pressurereliefvalves, open-ended lines,and samplingconnections. Thesecomponents represent mechanicaljoints, seals, androtating surfaces, which in time tend to wearanddevelop leaks. EMISSION FACTOR: (scf/equipment-yr, see below) In the componentmethod forestimatingemissionsfrom equipmentleaks, an average emission factor is determined foreach ofthe basic components, such as valves, flanges, seals, and otherconnectors that comprisea facility. The averageemission factor for each type ofcomponent is determined by measuring the emission ratefrom a large numberofrandomly selectedcomponents from similartypesoffacilities throughoutthecountry. An average estimateofthe emissionsperequipmentorfacility are determined as theproduct oftheaverage emission factorper componenttype (i.e., the componentemissionfactor) andthe average numberofcomponents associated with the majorequipmentorfacility: Ef = f(Nvlv X Efv1J + {Ncn X Ef.,)+(Noel X Ef

**oe~)** + (Nath X EF...JJ where: Nx =averagecount ofcomponentsoft)'pex perplant, and EF, = averagemethane emissionratepercomponent oftype x. Componentemission factors for fugitive equipmentleaksin gas production were estimated separatelyfor onshore and offshoreproductiondueto differences in operational characteristics. Regional differences were found to exist between onshore production in theEastern U.S. (i.e., Atlantic and GreatLakesregion)andthe Western U.S. (i.e., rest ofthe country, excludingtheAtlantic and GreatLakesregion) and between offshoreproduction in the Gulfof Mexicoand the Pacific OuterContinental Shelf(OCS). Separatemeasurementprograms were conductedto account for these regional differences. OnshoreProduction in theEastern U.S. Region. Gas production in the Eastern U.S. accounts foronly4.2%of grossnational gas production,but includes47%ofthetotal gas wells in the country. Componentemission factors foronshoreproduction in the Eastern U.S. were based on a measurement program conductedby GRI/Star Envirorunental of 192 individual well sites at 12 eastern gas production facilities. Componentcounts forgas wellheads, separators,meters andthe associated above-groundpiping, and gatheringcompressors were based on information collectedas part oftheEastern U.S. produCtion measurementprogram. Sitevisits andphone surveys of 7 additional sites provideddataused fordeterminingthenumberofheaters and dehydrators in the Eastern U.S. region. Componentcounts forheaters anddehydratorswere assumed to be identicaltothosederived from data collected in the Western U.S. Thefollowing table presentsthe componentemission factors,average component counts, and averageequipmentemissions for onshore gas production in the Eastern U.S. region.

B-2Average Equipment Emissions for Onshore Production in the Eastern U S 

### .. EquipmentType Component Type Component Average Average Equipment Emission Factor, Component Emissions,• Mscf/component-yr Count scf/equipment-yr Gas Wellheads Valve 0.184 8 2,595 (27%) Connection 0.024 38 Open-Ended Line 0.42 0.5 Separators Valve 0.184 I 328 (27%) Connection 0.024 6 Heaters Valve 0.184 14 5,188 (43%) Connection 0.024 65 Open-Ended Line 0.42 2 PressureRelief 0.279 I Valve Glycol Valve 0.184 24 7,938 (35%) Dehydrators Connection 0.024 90 Open-Ended Line 0.42 2 PressureRelief 0.279 2 Valve Meters/Piping Valve 0.184 12 3,289(30%) Connection 0.024 45 Gathering Valve 0.184 12 4,417 (27%) Compressors Connection 0.024 57 Open-Ended Line 0.42 2 •Values in parenthesesrepresentthe 90% confidence interval. OnshoreProduction in theWestern U.S. Region. Componentemission factors for onshoreproduction in the Western U.S. werebased on a comprehensivefugitiveemissionsmeasurementprogram conductedby API/GRl at 12 oil and gasproduction sites. In thisprogram, measurement data were collectedfrom 83 gas·wells at4 gas production sites in the Pacific, Mountain,Central, and Gulfregions. Theaveragecomponentcounts foreach piece ofmajorprocessequipmentassociated with gasproduction in theWestern U.S. werebasedon data collectedduring theAPVGRl studyand additional datacollected for GRl during 13 site visits to gas production fields. The following tablepresentsthe componentemission factors, average componentcounts,and averageequipment emissionsfor onshoregasproduction in the Western U.S.region.



### B-3A E verage ::QU1Dment E rmss10ns or llSnQ!"e ro uct10n mt e estern f 0 h p d h 

## w 

## us Equipment Type Component Component Average Average Typ' Emission Factor, Component Equipment Mscflcomponent-yr Count Emissions,' scf/equipmen t·yr Gas Wellheads Valve 0.835 II 13,302 (24%) Connection 0.114 36 OEL 0.215 I Separators Valve 0.835 34 44,536(33%) Connection 0.114 106 OEL 0.215 6 PRY 1.332 2 Heaters Valve 0.835 14 21,066(40%) Connection 0.114 65 OEL 0.215 2 PRY 1.332 I Glycol Dehydrators Valve 0.835 24 33,262 (25%) Connection 0.114 90 OEL 0.215 2 PRY 1.332 2 Meters/Piping Valve 0.835 14 19,310 (300/c) Connection 0.114 51 OEL 0.215 I PRY 1.332 I GatheringCompressors Valve 0.835 73 97,729(68%) Connection 0.! 14 179 OEL 0.215 3 PRY 1.332 4 Compressor 2.37 4 Seal Large CompressorStations 3.01 X 106 a a a (102%) Station Components Compressor-RelatedComponents a a a



### i<ss,~ 10' 65% •Values m parentheses representthe 90%confidencemterval. b RefertoT-1 source sheetfor a discussion ofthebasis forestimatedemissionsfrom large compressorstations. B-4OffshoreGas Production. Emissions from equipment leaks from offshoreproduction sites in the U.S. were based on two separatemeasurementprograms: • TheAPI/GRI oil and natural gas production operations study, which included 4 offshore production sites in the GulfofMexico; and • The Minerals Management Service study of7 offshore production sites in the Pacific OuterContinental Shelf. Thecomponentemission factors and componentcountsweretaken directly from the field test reports from these studies. The following tablepresents the componentemission factors, componentcounts, and average facility emissions for offshoreproduction in the GulfofMexicoand Pacific OCS. Average Facilitv Emissions for Offshore Production Equipment TYPe ComponentTYPe Component Average Average Facility Emission Factor, ComponentCount Emissions,• Mscflcomponent-yr Mscf/yr GulfofMexico Valve 0.187 2,207 1,064 (27%) Platfonn Connection 0.046 8,822 Open-Ended Line 0.368 326 Other 2.517 67 Pacific OCS Valve 0.048 1,833 430(36%) Platfonn Connection 0.021 13,612 Open-EndedLine 0.092 313 Other 0.091 307 •Values in parenthesesrepresentthe900/o confidenceinterval. EFDATA SOURCES• I. Emission Factorsfor Eastern Gas Production basedupon datafrom the GRI/Starprogram forthecomponentEPsat 12 gas production sites. 2. Fraction ofmethane (78.8 mol%)based on datafrom MethaneEmissions from the NaturalGasIndustry, Volume 6: VentedandCombustionSourceSummary {1). Conversion ofemission facton from (pounds THC perday)to (methaneMscf/yr) also required estimation ofgas average molecularweight. Based on datafrom Perry's ChemicalEngineerHandbook (2), Table 9-15, selectedmost similar gas composition speciation from C1through C6• andperfonned linearextrapolation from averageof3 lowest data (87 mol%methane) to 78.8 mol%methane. Resultant weightpercent of69.6 wt% methaneused to speciatemethaneemissions. 3. Componentcounts in Eastern gas production were based on average counts per equipmentfrom the GRI/Starprogram at 12 gas production sites. Componentcountsfor heaters and dehydrator in the Eastern region werebasedon datacollected in theWestern region. Componentcounts for onshoreproduction in the Western U.S. were based on the averages from the GR!!Star program at 4 gas production sites and GRJ/Radian datafrom I3 sitevisitsto gas production fields.



### B-54. Offshoredatafrom APIIGRl/Star20-siteprogram for GulfofMexicoplatforms (4 platforms, site numbers 17 through 20), andMineralsManagement Service/ABB Pacific OCS fugitive study(7platforms). Seerespective testreports (GulfofMexico Offshore: API!Star20-site study (3); Pacific OCSOffshore:MMS report 92-0043 November30, 1992)(4). 5. Largegatheringcompressors and largegatheringcompressor station emission factors are taken from Transmission segment (see SheetT-1). EF PRECISION: GasWells- Eastern

Basis: Separators- Eastern Heaters

- Eastern Dehydrators

- Eastern Meters/piping

- Eastern GatheringCompressors- Eastern GasWells- Western separators
- Western Heaters- Western Dehydrators

- Western Meters/piping- Western GatheringCompressors- Western LargeGatheringCompressors LargeGatheringStations Offshore(GuiO Offshore(Pacific) ±27% ±27% ±43% ±35% ±30% ±27% ±24% ±33'% ±40% ±25% ± 30% ±68% ±65% ± 102o/e ±27% ±36% Theaccuracyis rigorouslypropagatedthrough the EFcalculation from therange ofindividual measurements. Ninetypercentconfidenceintervals were calculated forthe sites using the!- statisticmethod. Computed90%confidenceintervalsfor site averagecomponentcounts were combinedwith 90%confidCllce intervals forcomponentemission factorstoobtain pooled uncenaintyin aggregate emission factor. ACTIVITY FACTOR: (129157 GasWells- Eastern) (91670Separators- Eastern) (260Heaters- Eastern) (1047 Dehydrators- Eastern) (76262Meters

- Eastern) (129GatheringCompressors- Eastern) (142771 Gas Wells-Western) (74674 Separators-Western) (50740Heaters- Western) (36777Dehydrators- Western) (301180Meters- Western) (16915GatheringCompressors- Western) (96 LargeGatheringCompressors) (12 LargeGatheringStations) (1092 GulfofMexico Platforms) (22 Western Offshore)



### B-6 ±5% ±23% ±196% ±20% ± 100% ±330/e ±5% ±57% ±95% ±20% ± IOOG;. ±52% ± 100% ± 100% ±10% ±10%AF DATA SOURCES:

AFPRECISION: I. The gas well count is from A.G.A.'s GasFacts !992 data (5). 2. Eastern gas wells and equipmentAFs were regionalizedusing site visit data. Eastern meterAFbasedon 0.43 meterpergas industry we!! (per Star Environmental). Western U.S. meterAF basedon industryadvisorinfonnation of 1: I meterpergas industry well. 3. Dehydratorcounts are basedon 37,824glycoldehydrators in production (seeSheetP-6 fordetails). Adjustmentto activity factor for Eastern gasproduction: subtract I,047 dehydrators (included in Eastern gasproduction componentcounts). 4. Offshoreplatform counts provided by OffshoreDataServices, Inc., Houston, Texas, and MineralsManagementService MOADdatabase forproducing platforms (6). Assumed 50150 split between "oil" industry and "gas" industry. 5. Largegatheringcompressors and compressorstation counts wereestimated from FERC Fonn 2 database. Largegatheringcompressorstationswerethose with at least 16 stages ofcompression (5 compressorsperstation and an average of3.3 stagespercompressor). Theresult wasextrapolatedtothenational total by ratioingon gathering miles covered in FERCtototal gatheringmileage. 6. The othereqUipment counts were produced from equipmentcountdata taken duringthe site visitsby Radian and Star. As explained in the activity factor section ofthetext of this report, extrapolation tonational counts wasdoneon a regional basis to accountfor regional equipmentconfiguration differences. Basis: I. 2. Theprecision forthe activewells isassignedbyengineeringjudgement, baseduponthe fact that the numberofactivewells is tracked nationally andknown accuratelyby A.G.A./DOE, etc. Theaccuracy forthe otherequipmenttypes is basedupon rigorous propagation oferror from therange in averages from the 9 production sites visited.

B-7ANNUAL EMISSIONS: (17.4 Bscf/yr±7.1 Bscf/yr) Theannual emissions weredetermined bymultiplyingthe average equipmentemissions by the population of equipment in the segment.

**Ca<~gory** Emtsston Facto• Aotivtly Foetor EmiSSion Rate Unoertaintv GasWellh.,,d/Eastft>l US) 2S9S soflyrmoth.,, 129157 as wolls(E..,emUS) 0 34 BsoOyr methane 27"1. Separators{EIU!om US) J2B sdlyrmethane 91670>epar>l<>rs (East<m US) 0m Bsoflvrmethane )6% Heaton (EIISiem US) S187 soflyr m<thM! 260 healer>(Ea..tem U S ) 0001 Bsof7vrm"'h""• 218% O.hydrators (East<m US) 79)9 «:.flyrm"'ham !047dehydrators (&s!omUS) 0008 **Bscfl~rmetllaM** 4Wo M"'en-P'tpin (East<m US I **J289sc;f/yr~""'.** 76262 "'"'..,(EasternUS) 0 2S Bscf/yr methalle 109>/o G•theringCom '"""''(&stemUS) **4417soflyr~ane** 129golhenngcompr"""'"(E&slem US ) 00006Bscflyr m"'hant 44% GO$ We!lh.. ds {WenernUS) 13)02

**><fl~r** meoh.. e 142771 gas,.,..lb (Western US ) I 9Bsc:flyr meob.,e 2S'4 Seyarotors(Westem US I «H6sof!yrm<thatle 74674 .,...<>n!WestemUS) J JJ Booflyr..,..,n..,, 69'4 H.. ,.,.,/Western U S ) 21066 seflyrm<thiflt s0140 ;.,.);,.n.. .,.(W"'emu.s) I 07 B><:f/yr meth>flt 110% O.hydratOf1 !WesternUS) JJ262 •d/op methone ]6717dehydra!OtS{Westem US) I 22 Bsof/Vrm"'hane J2% M..,e,.(Wesoem US) 19l!Oscflyr methane **30IJ80m...,..{W~em** US)

**~** 82 Bsc:fiyrmolhOflt

**,~.** Smoll GatheringComp.....,..(WeooemUS) 97729 rd/yrmethan< !691Sco **~n(W~US_)** I 6S Bscf/frm..n...e

**9J~.** LorgeGatherin Cornp<e!>Ors(Weooem U S ) S55 MMscflyr meth&•e 96large **compr~** 0 SJ Bscf/yrmtlhaoe !l6*/o UrgeGathering Compressor SWiOJ>I(Western l 01 MMscflyr

**~**... 12 Iorgegllhenngcomp.....,..wion• 0 IJ4

**Bscfl~r** metha<.e 176% U'l OffshortOti!G&< (Gulf) 1064 l.is<fl rmethone !092GulfofMextooplarfomu; I 16Bsoflyrm"'h""e

**'~** OffshoreOil/GO$ ((Pacifi<) 4)00Msoflyr m..n...e 22 piO!fbfm•IPacifte) 0 01 B>eflf'methane 38¥. TOTAL 17 4Bsof/yrmethilrre 4!% REFERENCES I. Shires, T.M. and M.R. Harrison. Methane Emissions from theNatural Gas Industry, Volume 6: 2. 3. 4. VentedandCombustionSourceSummary, Final Report, GRI·94/0257.23 andEPA·6001R·96· 080f;GasResearch Instituteand U.S. Environmental ProtectionAgency,June 1996. Perry,J.H. (ed). ChemicalEngineers Handbook5thEdition, McGraw-Hill BookCo., New York, NY, 1984. StarEnvironmental. EmissionFactors for OilandGasProduction Operations, API Publication No.,4615. American Petroleum Institute, January 1995. MineralsManagementService_ FugitiveHydrocarbonEmissions from Pacific OCSFacilities. Volume I, Final Report. MMS92-0043. U.S.DepartmentofInterior,NewOrleans, LA, November30, !992. 

### B-85. 6. American GasAssociation. Gas Facts, Arlington, VA. 1992. MineralsManagement Service. Users Guide. MMSOuter ContinentalShelf ActivityDatabase (MOAD), OCS Study MMS 94-0018,U.S. Department ofthe Interior, New Orleans, LA, April 1994.

B-9SOURCES: OPERATING MODE: EMISSIONTYPE: ANNUAL EMISSIONS: BACKGRvUND: GP-1 PROCESSING SOURCE SHEET All EquipmentatGas Processing Plants Normal Operation Steady and Unsteady, Fugitive 24.45 Bscf± 68% Equipment leaks are typically low-level, unintentional losses ofprocess fluid (gas orliquid) from the sealed surfaces ofabove-ground processequipment. Equipmentcomponents thattend to leak includevalves, flanges and other connectors, pump seals, compressor seals, pressurereliefvalves, open-ended lines,and sampling connections. Thesecomponents representmechanicaljoints, seals, and rotating surfaces, which in time tendto wearand develop leaks. EMISSION FACTOR: a. Plant""2.89MMscf/yrmethaneperplant b. ReciprocatingCompressor""4.09MMscflyrmethaneperrecip c. CentrifugalCompressor=7.75 MMscf/yrmethaneperturbine The average fugitive emission rate forgas processingplants was detenninedto becomposed oftwoparts: a) plant componentcounts (excludingcompressorcomponents), and b) compressor-relatedcomponents. Fugitives fromthe compressor-related components have much higheremission factors thancomponents in therest ofthe facility. Pan ofthis is due to thehigh vibrationthatcompressors generate, butmostofthe largeremissions are due to unique compressorcomponents, as explained below. a. The contribution from non-compressorcomponents wasdeterminedbymultiplying the averagecomponentcount by the componentemission factor. The numberofcomponents was subdivided into valves, connections/flanges, smallopen-ended lines, siteblowdown (BID) OELs, control valves,and othercomponents (suchas pressurerelief valves). (Tubing components were determinedto beinsignificant.) All ofthese componentsare typical fugitive components (as described inthe EPAFugitiveEmissions Protocol) withthe exception ofcontrol valves and site BiDOELs. Control valves emitatahigherratethan manual isolationvalves sincetheirpacking is stressed more often as they are activated muchmore frequently. Site BIDOELs are thelarge diameteremergency station blowdown valves thatare designed to depressure the entiresiteto the atmosphere when the valve isopened. Thecomponentemission factors for gas plantcomponents (i.e., non.compressorrelated) were basedon an_API/GRl measurementprogram conducted at 8gas plants. The average facility emissions are then calculatedas follows: where: N, =average countofcomponents oftype xperplant, and EF, =averagemethane emission ratepercomponentoftype x. b. The contribution from compressor-relatedcomponents was obtainedbymultiplying the average numberof fugitive componentspercompressor enginebycomponentemissionfactors. Thecomponentemission factors were basedonthe GRl!Indaco measurementprogram conductedat 15 compressorstations. Somecompressor components are unique, while othershavehigherleakrates than identicalcomponents elsewhere intheplantdue to vibration. Compressorshave the following types ofcomponents:

B-10I)Comp. BIDOEL A blowdown (BID) valve to the annosphere that can depressure the compressorwhen idle. The BIPvalve or the large unit block valves (depending on the operating status of the compressor) can act as an open-ended line that leaks at an extraordinarilyhigh rate through the valve seat. The leak rate is dependent upon whetherthecompressor is pressurized (in operation oridle, pressurized} or depressurized (idle,depressurized). 2) Comp. PRY The pressure reliefvalve {PRV) is usually installed on acompressor discharge line, and leaks at ahigher than average rate due to vibration. 3)Comp. StarterOEL Most compressors have agasstartermotorthat turns the compressor shaft to startthe engine. Someuse natural gas as the motive force to spin the starter's turbine blades,and vent the discharge gas to the annosphere. The inlet valve to the starter can leak and is therefore an OELunique to compressors. 4) Comp. Seal All compressors have a mechanical orfluid seal to minimize the flow ofpressurized natural gas that leaks from the location where the shaftpenetrates thecompression chamber. These seals are vemed to the annosphere. Reciprocating compressors have sliding shaft seals while centrifugal compressors have rotating shaft seals. 5) Miscellaneous There are many components on each compressor, such as valve covers on reciprocating compressorcylindersand fuel valves. Each compressorhas one BIDOEL, one PRV, and one starterOEL. Reciprocating compressorshave one compressor seal percompression cylinder(which averaged 2.5 perengine), whilecentrifugal compressorshave 1.5 sealspergasturbine. Forthe miscellaneous component category, there are many componentspercompressor engine, but the emission rates were minorand so wereadded intoone lumpemission factorpercompressorfor miscellaneouscomponents. All ofthecompressoremission factors take several correction factors into account. First, the various phases of compressoroperations [such as the amount oftime thatcompressors are a) idle and depressured, b) idle and pressuredup, orc)running}. This is actually a complex adjustmentthat takes into account valve position practices. [See MethaneEmissions from the Natural Gas Industry, Volume 8: EquipmentLeaks (I)fordetails.} Correction factors were also added for fraction ofstartergasturbinesusing air instead ofgas (75% forrecip, 33%forturbines in gasprocessing), and for sites with flares handling PRYorcompressorBID discharge (approximately 11% ofthe compressor blowdown OELs were routed to a plant flare). EFDATA SOURCES: I. Componentemission factors based on screeningresults from API!GRI/Star program for the componentEF's for eight gas processingplants and EPA's current default zero factors, correlationequations, and pegged source factors. Confidence limits derived from analysis ofscreening data by Radian in April 1995. 2. OEL (site BID)emission factorbased on results from GRI!Jndaco program for compressor stations (June 1994). 3. Plant component counts were based on average of8API!Star sites, 6 EPA/Radian sites in 1982, and 7 sites visited underthis project in 1992. 4. Compressoremission factors based on results from GRIIIndaco program for 15 compressorstations (June 1994). Compressoroperatinghours (%running) based on data from 3gasprocessing company databases.



### B-11Average Facility Emissions for Gas Processing Equipment Type Component Type Component Average Component Emission Factor, Count Mscf/component·yr Gas Plant (non· Valve 1.305 1,392 compressor related components) Connection 0.117 4,392 Open·Ended Line 0.346 134 Pressure Relief 0.859 29 Valve Site Blowdown 230 2 Open·Ended Line Reciprocating Compressor

**2,036b.~** I Compressor Slowdown Open· Ended Line Pressure Relief

**349b.~** I Valve Miscellaneous

**189~** I Starter Open-Ended 1,341

**o.z5~** Line Compressor Seal 450< 2.5 Centrifugal Compressor 6,447b.d 1 Compressor Slowdown OpenEnded Line Miscellaneous 31' I Starter Open-Ended 1,341 0.667[ Line Compressor Seal 228d 1.5 • Values in parentheses represent 90% confidence interval. b Adjusted for 11.1% ofcompressors which have sources routed to flare. <Adjusted for 89.7% oftime reciprocating compressors in processing are pressurized. d Adjusted for 43.6% oftime centrifugal compressors in processing are pressurized. < Only 25% ofstarters for reclprocating compressors in processing use natural gas. rOnly 66.7% ofstarters for centrifugal compressors in processing use natural gas.

B-12 Average Equipment

**Emissions,~** MMscf/yr 2.89 (48%)

4.09 (74%)

7.75 (39%)EF ACCURACY:
Basis: l.

ACTIVITY FACTOR a. Plant Emission Factor = 

### ± 48% b. Recip. Compressor = ± 74% c. Turbine Compressor = 

### ± 39% The accuracy was propagated through the EF calculation from each terms accuracy. 90% confidence intervals were calculated for the sites using the t-statistic method. The 90% confidence intervals accounted for variability in component count from the range in site averages and estimates were also provided for the component emission factors from the API!Star and GRI/Indaco program.

a. Plant Activity Factor = 726 plants b. Compressor Activity Factor = 4092 recip engines, 726 turbines The number ofgas processing plants was determined from the Oil and Gas Journal (2) (July 1993). The number and type of gas processing compressor engines were determined from eleven gas plant site visits. The average ratio ofcompressors per plant was multiplied by the total number ofplants, 726, to obtain these estimates. [See Methane Emissions from the Natural Gas Industry, Volume 5: Activity Factors (3) for details.] AF DATA SOURCES: Oil and Gas Journal (July 1993) (2) AF ACCURACYc Basis: l. 2. 3. a. Plant Activity Factor: 

### ± 2% b. Compressor Activity Factor: Redp engines = ± 48%; Turbines = 

### ± 77% An accurate count ofgas plants by the Oil and Gas Journal (2) is very likely since counting such large, discreet facilities should be straightforward. The ± 2% was assigned by engineeringjudgement. The compressor count accuracy was determined by statistical analysis ofthe "compressor per site" averages for II gas plant sites. A check was performed to estimate whether gas plant sites visited for compressor counts were representative ofindustry average. Based on Oil and Gas Journal, the average plant capacity was 88.3 MMscfd and throughput was 51.2 MMscti'd. Site visit data averaged 271 MMscfd and throughput was 182 MMscf!d, suggesting that plants visited were larger than average. However, further investigation revealed that there is no correlation between plant capacity/throughput and number of compressors (The plant visited with the most compressors had 20 engines with 20,000 HP and a low throughput of 56 MMscfd, while the plant with the highest current operating rate of750 MMscfd had only one compressor at 17,500 HP.)

B-13ANNUAL EMISSIONS: (24.45 Bscf/yr ± 16.7 Bscf/yr) Theannual emissionswere determined bymultiplying the averageequipment/facility emissions by thepopulation ofequipment in the segment. Category Emission Factor Activity Emission Uncertainty Factor Rate Gas processing 2.89 MMscflyr 726 plants 2.1 Bscf/yr 48% plants methane methane RecipComp 4_09 MMscflyr 4092

**~cip** 16.7Bscflyr 95% methane methane TurbineComp 7_75 MMscflyr 726 turbine 5.6Bscflyr 91% methane methane TOTAL 24.4 Bsct/yr 68% methane REFERENCES I.

2. 3. Hummel, K.E., L.M. Campbell, and M.R. Harrison. Methane Emissions from theNaturalGas Industry, Volume 8: EquipmentLea/cs,FinalReport, **GRI~94/0257.25** and **EPA-600/R-96~080h,** Gas Research Institute and U.S. Environmental ProtectionAgency,June 1996. OilandGasJournal. 1992 Worldwide GasProcessing Survey Database,July 1993. Stapper, B.E.. MethaneEmissions/romtheNaturalGasIndustry, Volume 5:ActivityFactors, Final Repon, GRl-94/0257.22 and EPA-600/R-96-080e, Gas Research Instituteand U.S. Environmental Protection Agency, June 1996.

B-14SOURCES: OPERATING MODE: EMISSION TYPE: ANNUAL EMISSIONS: BACKGROUND: T-1 TRANSMISSION SOURCE SHEET CompressorStations Nonnal Operation Steady and Unsteady, Fugitive 50.7 Bscf±52% Equipment leaks are typically low·level, unintentional losses ofprocess fluid (gas or liquid) from the sealed surfaces ofabove-groundprocess equipment. Equipmentcomponents thattend to leak include valves, flanges and other connectors, pumpseals, compressorseals, pressure reliefvalves, open-ended lines, and sampling connections. These componentsrepresentmechanicaljoints, seals, and rotating surfaces, which in timetend to wear anddevelop leaks. EMISSION FACTOR: a. Station = 3.2 MMscf/yrmethane perplant b. Recip. Compressor=5.55 MMscf/yrmethane perrecip c. TurbineCompressor= 11.1 MMscflyrmethane perturbine The average fugitive emi$sion rate for transmission compressorstations was determined to be composedoftwo parts: a) station components (excludingcompressor-relatedcomponents); andb)compressor.related components. Fugitives from the compressor-relatedcomponentshave much higheremission factors than components in the rest ofthefacility. This is due in part to the high vibration that compressors generate, but most ofthe largeremissions are due to unique compressorcomponents, as explainedbelow. a. Thecontribution from non-compressorcomponentswas determined by multiplying the average componentcount ]JY thecomponentemission factor. Thenumberofcomponentswas subdividedinto valves, connections/flanges, small open-ended lines, site blowdown (BID)OELs, control valves, and othercomponents (such aspressurerelief valves). (Tubingcomponents were determined to be insignificant.) All ofthese components are typical fugitive components (as described in the EPA FugitiveEmissionsProtocol) with the exception ofcontrol valves and site BIDOELs. Controlvalves emit at a higherrate than manual isolation valves sincetheirpacking is stressedmore often as they are activated much more frequently. Site BIDOELs are the large diameteremergency station blowdown valves thataredesigned to depressurethe entire site to the atmosphere when the valve is opened. Thecomponentemission factors for stationcomponents were based on a GRI!Indaco measurementprogram conducted at 6 compressorstations. Theaverage facility emissions are then calculated as follows:
where·. N, =averagecount ofcomponents oftype x perplant, and EF, = average methane emission rate percomponent oftype x. b. The contribution from compressor-related components was obtained by multiplying the average number of fugitive components percompressor engine by the component emission factors. The component emission factors were based on the GRI/Indaco measurement program conducted at 15 compressor stations. Some compressor components are unique, while others have higher leak rates than identical components elsewhere in the plant due to vibration. Compressorshavethe following types ofcomponents:

I) Comp. BID OEL A blowdown (BID) valve to the atmosphere that can depressure the compressor when idle. The BID valveor the large unit block valves (depending on the operating status of the compressor) can act as an open-ended line that leaks at anextraordinarily high rate 

### B-15through the valve seat. The leak rate is dependent upon whether the compressor is **pressurized(~** operation oridle, pressurized) or depressurized (idle, depressurized). 2) Comp. PRV The pressure relief valve (PRV) is usually installed on a compressordischarge line and leaks at a higher than average rate due to vibration. 3) Comp. Starter OEL Most compressors have a gas startermotorthat rums the compressor shaft to start the engine. Some use natural gas as the motive force to spin the starter's turbine blades and vent the discharge gas to the atmosphere. The inlet valve to the startercanleak and is therefore an OEL unique to compressors. 4)Comp. Seal All compressorshave a mechanical or fluid seal to minlmize the flow ofpressurized natural gas that leaks from the location where the shaft penetrates the compression chamber. These seals are vented to the atmosphere. Reciprocating compressors have sliding shaft seals while centrifugal compressors have rotating shaft seals. 5) Miscellaneous There are many components on each compressor, such as valve covers on reciprocating compressorcylinders and fuel valves. Each compressorhas one BID OEL, one PRV, and one starter OEL. Reciprocating compressors have one compressor seal percompression cylinder (which averaged 3.3 perengine), while centrifugal compressors have 1.5 seals pergas turbine. For the miscellaneouscomponent category, there are many componems percompressor engine, but the emission rates were minor and so were added into one lump emission factor percompressor for miscellaneouscomponents. All ofthe compressoremission factors take several correction factors into account. First, lhe various phases of compressoroperations (such as the amount oftime that compressors are a) idle and depressured, b) idle and pressured up, or c) runn.ing). This is actually a complex adjustment that takes into account valve position practices. [See Methane Emissionsfrom theNatural GasIndustry, Volume 8: EquipmenrLeaks (1) for more details.] Correction factors were also added for fraction ofstartergas turbines using air instead ofgas (100% for recip, 0% for turbines in Transmission). EF DATA SOURCES, I. Component emission factors based onresults from GRI/Indacoprogram for the component EF's for 6 transmission compressor stations (June 1994). Adjustment of station EFis toaccount for data obtained from one interstate transmissionpipeline company that was found to havehigheremissions than average. 2. Plant component counts were based on an average of8 Indaco sites in 1994 and 9 sites visited underthis project in 1993, plus 7 industry sites. 3. Compressoremission factors based on results from GRI/Indacoprogram for 15 compressor stations (June 1994). Compressoroperating hours(% running) based on data from FERC database, GRI TRANSDATdatabase, and data supplied by one large interstate transmissionpipeline company. 4. Fractionofmethane (93.4 mol%) based on data from GRI TRANSDATdatabase.

B-16Average Facility Emissions for Gas Transmission Equipment Type Component Type Component Average Average Equipment Emission Factor, Component Emissions,' Mscflcomponent-yr Count MMscf/yr Compressor Station Valve 0.867 673 3.0! (102%) (non-compressor (Note: 3.2 MMscf/yr related components) Control Valve 8.0 31 used in national emission estimate}" Connection 0.147 3,068 

### OEL 11.2 51 PRY 6.2 14 Site BID OEL 264 4 Reciprocating Compressor BID 3,683 I 5.55 (65%) Compressor 

### OEL PRY 372" I Miscellaneous 180' I Compressor Starter d d 

### OEL Compressor Seal 396" 3.3 Centrifugal Compressor BID 9,352 I 11.1 (34%) Compressor 

### OEL Miscellaneous 18' I Compressor Starter 1,440 I 

### OEL Compressor Seal 165" 1.5 • Values in parentheses represent 90% confidence interval. b Adjusted for data received from one company that was not considered representative ofnational average. "Adjusted for the fraction of time the compressor is pressurized (79.1% and 24.2% for reciprocating and

centrifugal compressors, respectively). d Reciprocating compressor staners were assumed to use compressed airor electricity instead of natural gas.

B-17EF ACCURACY' a. Station = 102% b. Recip. Compressor = 65% c. Turbine Compressor = 34% Basis: Rigorous propagation oferror from the spread ofthousands of individual measurements taken by Indaco. ACTIVITY FACTOR: a. StationActivity Factor = 1700stations b. Compressor Activity Factor = 6799 recip engines, 681 turbines AF DATA SOURCES' I. 1992 PERC Fonn 2 responses accounted for 70% ofnational transmission pipeline mileage. Total station count extrapolated using national total transmission mileage of 276,900 miles from A.G.A. Gas Facts (2). 2. Compressor engine count based on GRI TRANSDAT

**~industry** database" with adjustments for total industry horsepower. Transmission compressor station counts were split from storage based upon storage station site visit data and Gas Facts (2) data on storage stations. Added 0.2% to recip count account for electric motor drivers. AF ACCURACY' Basis: I. 2. a. Station Activity Factor: ± 10% b. Compressor Activity Factor: Recip engines = 

### ± 17 %; Turbines = 

### ± 26 % FERC Form 2 data have a high percentage (70%) ofall transmission companies. Therefore a national extrapolation should not add much error. This 10% figure was assigned based on engineeringjudgement. The compressor count accuracy was assigned based upon the propagation from: a) rigorous error propagation for the 8 storage station **~compressor/station~** averages; and b) engineeringjudgement assignment of ± 10% error to the large GRI TRANSDAT database.

B-18**A~'UAL** EMISSIONS: (50.73 Bscf/yr ± 26.3 Bscf/yr) The annual emissions were determined by multiplying the average facility/equipment emissions by the population ofequipment in che segment. Category Station Recip Comp
Turbine Comp TOTAL
REFERENCES !.
2. Emisston Factor Activity Factor Emission Rate Uncertamty 3.2 MMscflyr 1 700 stations 5.4 Bscf/yr 103% CH4 CH4 5.55 MMscf/yr 6799 recip 37.8 Bscf/yr 68% CH4 CH4 !l.! MMscf/yr 68! rurbine 7.5 Bscf/yr 44% CH4 CH4 50.7 Bscf/yr 52% CH4

Hummel, K.E., L.M. Campbell, and M.R. Harrison. Methane Emissionsfrom the Natural Gas Industry, Volume 8: EquipmentLeaks, Final Report, GRI-94/0257.25 and EPA-600/R-96-080h, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. American Gas Association, Gas Facts. Arlington, VA, 1992.

B-19SOURCES: OPERATING MODE: EMISSION TYPE: ANNUAL EMISSIONS: BACKGROUND: S-1 STORAGE SOURCE SHEET Storage Facilities (Compressor Stations and Wells) Nanna! Operation Steady and Unsteady, Fugitive 16.76 Bscf±57% Equipment leaks are typically !ow-level, unintentional losses ofprocess fluid (gas or liquid) from the sealed surfaces ofabove-ground process equipment. Equipment components that tend to leak include valves, flanges and other connectors, pump seals, compressor seals, pressure reliefvalves, open-ended lines, and sampling connections. These components represent mechanicaljoints, seals, and rotating surfaces, which in time tend to wear and develop leaks. EMISSION FACTOR: a. Station = 7.85 MMscUyr methane per station b. Wellhead
.. 41.8 Mscf/yr methane per wellhead c. Recip. Compressor = 7.71 MMscf/yr methane per recip d. Turbine Compressor = II.I6 MMscf/yr methane per turbine The average fugitive emission rate for storage facilities was detennined to be composed ofthree parts: a) storage compressor station components (excluding compressor-related components), b) injection/withdrawal wellhead components, and c) compressor-related components. Fugitives from the compressor-related components have much higher emission factors than components' in the rest ofthe facility. This is due in part to the high vibration that compressors generate, but most ofthe larger emissions are due to unique compressor components as explained below. a) The contribution from non-compressor components was detennined by mul!iplying the average number of fugitive components by the component emission factor. The number ofcomponents was subdivided into valves, connections/flanges, small open-ended lines, and othercomponents (such as pressure reliefvalves); tubing components were detennined to be insignificant. All ofthese components are typical fugitive components (as described in the EPA Fugitive Emissions Protocol) with the exception ofsite blowdown (BID) open-ended lines (OELs). Site BID OELs are the large diameter emergency station blowdown valves that are designed to depressure the entire site to the atmosphere when the valve is opened. Emission factors for storage station components were based on the GRI/Indaco program at 6 transmission compressor station sites. b) The contribution from storage injection/withdrawal wells was determined in the same manner as storage compressor stations (see below). Emission factors for storage injection/withdrawal wells were based on the updated API/GRVStat 20-site study (4 gas production sites). Physical and operational characteristics of injection/withdrawal wells were compared to gas production wells, and were found to be similar but typically larger (more components). This was taken into account in the component count data. The number ofcomponents was subdivided into types, such as valves, connections/flanges, open-ended lines, and other components (such as pressure reliefvalves). The average facility/equipment emissions are calculated as follows:
where: N. = average count ofcomponents oftype x per plant, and EF, = average methane emission rate per component oftype x. B-20c)The contribution from compressor-relatedcomponents was obtained by multiplying the average numberof fugitive componentspercompressorengineby the component emission factors. The componentemission factors were based on the GRI/Indaco measurementprogram conducted at 15 compressorstations. Somecompressor components areunique, while others have higher leakrates than identical componentselsewhere in the plant due to vibration. Compressorshave the following types ofcomponents:

I} Comp. BIDOEL A blowdown (BID) valve to the atmosphere that can depressure the compressorwhen idle. The BID valve N the large unit block valves (depending on the operating status of the compressor) can act as an open-ended line that leaks at an extraordinarily high rate through the valve seat. The leakrate is dependent upon whetherthe compressoris pressurized (inoperation oridle, pressurized) or depressurized (idle, depressurized}. 2)Comp. PRV Thepressure reliefvalve (PRV} is usually installed on a compressordischarge line and leaks at ahigherthan average rate due to vibration. 3)Comp. StarterOEL Most compressors havea gas startermotor that turns the compressorshaftto startthe engine. Some use natural gas as the motive force to spinthe starter'sturbine blades and vent the dischargegas to theatmosphere. The inlet valve to the startercan leak and is therefore an OELunique to compressors. 4} Comp. Seal Ail compressOrs have amechanical or fluid seal to minimize the flow ofpressurized natural gasthatleaks from the location where the shaftpenetrates the compression chamber. These seals are vented tothe atmosphere. Reciprocating compressors have sliding shaft seals while centrifugal compressors haverotating shaft seals. 5)Miscellaneous There are many componentson each compressor, suchas valve coverson reciprocating compressorcylindersand fuel valves. Each compressorhas one BIDOEL, one PRV, and one starterOEL. Reciprocating compressors haveone compressor seal percompressioncylinder(which averaged4.5 perengine), while centrifugal compressors have I.5 sealspergasturbine. For the miscellaneous component category, there are many componentspercompressor engine, but the emission rates were minorand so were added into one lumpemission factorpercompressorfor miscellaneouscomponents. All ofthe compressoremission factors takeseveral correction factors intoaccount. First, the various phases of compressoroperations (such asthe amountoftime that compressors are a) idleand depressured, b) idle and pressured up, orc)running). This is actually acomplex adjustment that takes into account valve position practices. [SeeMethane Emissions.fromNaturalGasIndustry, Volume 8: EquipmentLeaks (I)for more details.

### J Correction factors were also added for fraction ofstartergas turbines using air instead ofgas(40%forrecip, 50% forturbines in storage). EF DATA SOURCES: I. Emission Factorsfor storage compressorstationsarebased upon GRI/Indaco transmission compressor station fugitive leak measurement surveys at 6 compressor stations. Compressoroperating hours (%running) based on data from 5 national gas storage companies. 2. Componentcounts for storagecompressorstations and injection/withdrawal wellheads are based on Radian site visits :o 5 storage facilities. 3. Componentemission factors forcompressor-relatedcomponentsbased on GRI/Indaco transmission compressorstation fugitive leak measurementprogram at 15 compressor stations. 4. Wellhead emission factors based on simple average ofGRI/Star data forgasproduction wellheads (Atlantic/Eastern region and Rest ofU.S.). 5. Fraction ofmethane (93.4 mol%) based on data from GRI TRANSDATdatabase. 

### B-21Average Facility Emissions for Gas Storage Equipment Type Component Type Component Average Component Average Equipment Emission Factor, Count Emissions,' Mscf/cornponent-yr MMscf/yr Storage Facility Valve 0.867 1,868 7.85 (100%) (non-compressor related components) Connection 0.147 5,571 

### OEL 11.2 353 PRV 6.2 66 Site BID OEL 264 4 lnjectiorv'Withdrawa Valve 0.918 30 0.042 (76%) I Wellhead Connection 0.125 89 

### OEL 0.237 7 PRV 1.464 I Reciprocating Compressor BID 5,024b I 7.71 (48%) Compressors 

### OEL PRV 317b I Miscellaneous 153b I Compressor Starter 1,440 0.6< 

### OEL Compressor Seal 300b 4.5 Centrifugal Compressor BID I0,233b I 11.16 (34%) Compressors 

### OEL Miscellaneous 17' I Compressor Starter 1,440 

### OS 

### OEL Compressor Seal 126b 1.5 • Values in parentheses represent 90% confidence interval. b Adjusted for the fraction oftime the compressor is pressurized (67.5% and 22.4% for reciprocating and

centrifugal compressors, respectively). < Adjusted for the fraction of compressor starters using natural gas (60% and 50% for reciprocating and

centrifugal compressors, respectively).



### B-22EF ACCURACY: a. Station = 

### ± 100% b. Wellhead = 

### ± 76% b. Recip. Compressor = 

### ± 48% c. Turbine Compressor = 

### ± 34% Basis: Rigorously propagation oferror from the spread ofthousands ofindividual measurements taken by Indaco and Star. ACTIVITY FACTOR a. Station Activity Factor= 475 stations b. Wellhead Activity Factor= 17999 weUheads b. Compressor Activity Factor = 1396 recip compressors, 136 turbines The activity factors for the segment were compiled from published statistics in Gas Facts (2). The total count for Underground storage stations was 386, and the total LNG storage count was 89. AF DATA SOURCES: I. 2.

3.

AF ACCURACY'
Basis: I. 2. The number ofunderground storage facilities was taken directly from A.G.A. Gas Facts, (2), Table 4-5: Number ofPools, Wells, Compressor Stations, and Horsepower in Underground Storage Fields. Data from base year 199:;! were used. The number ofLiquefied Natural Gas Storage Facilities was summed from A.G.A. Gas Facts (2), Table 4-3, "Liquefied Natural Gas Storage Operations in the U.S. as ofDecember 31, 1987." The table lists 54 complete plants, 32 satellite plants, and 3 impon terminals for a total of89 facilities
.
.Compressor engine count based on GRI TRANSDAT "industry database" with adjustments for total industry horsepower. Storage site visits to 8 storage sites provided number ofreciprocating engines and turbines per site 

### I see Activity Factor Repon (3)}. Also, the number ofreciprocating compressors in storage was increased by 31% to account for electric motor drivers.

a. Station Activity Factor: 

### ± 5% b. Wellhead Activity Factor. 

### ± 5% b. Compressor Activity Factor: Recip engines = 

### ± 58 %; Turbines = 

### ± II9 % A.G.A. Gas Facts (2) has a high percentage ofall storage facilities represented in Tables 4-5 and 4-3. Therefore a national extrapolation should not add much error. This 5% figure was assigned based on engineering judgement. The compressor count accuracy was assigned based upon the propagation from: a. Rigorous error propagation for the 8 storage station "compressor/station" averages; and b. Engineering judgement assignment of± !0% error to the large GRI TRANSDAT database.

B-23ANNUALEMISSIONS: (16.76 Bscf/yr::l:: 9.6 Bscf/yr) The annual emissionswere detennined bymultiplying an emission factor for an average equipmenttype by the population ofequipment in the segment.
Category Station lnj/With Wellheads RecipComp Turbine Comp TOTAL REFERENCES I.
2. 3. Emission Factor Activity Factor Emission Rate Uncertainty 7.85 MMscf7yrCH4 475 stations 3.73 BscfiyrCH4 100% 41.8 Mscl/yrCH4 !7999wellheads 0.752 BscUyr CH4 76% 7 71 MMscf/yrCH4 !396reclp I0.76 BscflyrCH4 80% l I 16 MMscf/yr CH4 136turbine l 52 Bscf/yr CH4 129% 16.76Bsd/yrCH4 57%
Hummel, K.E.,LM.Campbell, andM.R. Harrison. MethaneEmissions from theNatura/Gas Jnd,ustry, Volume 8: EquipmentLeaks,Final Report, GRJ-94/0257.25 and EPA-600/R-96-080h, GasResearch Institute and U.S. EnvironmentalProtection Agency,June 1996. American GasAssociation. GasFacts, Arlington, VA. !992. Stapper, B.E. Methane Emissions from theNaturalGasIndustry, Volume5:ActivityFactors, Final Report, GRI-94/0257.22 and EPA-600fR
..96-080e, Gas Research Institute and U.S. Environmental Protection Agency,June 1996.



### B-24SOURCES: OPERATING MODE' EMISSION TYPE, ANNUAL EMISSIONS: BACKGROUND: D-5 DISTRIBUTION SEGMENTSOURCESHEET CustomerMeters Nonnal Operations Steady,Fugitive 5.8 ± t.l bscfy Losses from customermeters are caused by fugitive leakage from the connections and otherfittings surrounding the meterset. EMISSION FACTOR: (outdoor residential meters: 138.5 ::t: 23.1 scUmeter·yr commercial/industrial meters: 47.9 ± 16.7 scf/meter-yr) Theestimate ofleakage from customermeters is basedon screening andbagging studies conducted atten sites throughoutthe United States. The initial study was conducted by lndacoto measure customermeters in thewest coast [IndacoAirQuality Services, Inc., MethaneEmissions fromNaturalGas CustomerMeters: Screeningand EnclosureStudies, draft report, August 15, 1992 (I)]. Data were alsocollected atnine additional sites across the United States, includingthree eastcoast sites, a mid-western site, a rocky mountain site, and five western U.S. sites. A summary ofthe average emissions from residential customermeters from each ofthe ten sites is shown in the following table:

Site Number ofMeters NumberofMeters AverageLeak Rate• Standard Screened Leaking (lbmethane/day) Deviation• (lbmethane/day) Site I --WestCoast !34 37 0.0098 0.0239 Site 2
-- East Coast 40 29 0.0002 0.0004 Site 3 -- EastCoast 158 37 0.0789 0.1753 Site4
-- Mid-West 156 8 0.0057 0.0061 Site5
-- Rocky 188 28 0.0035 0.0082 Mountain Site 6 -- West Coast 194 5 0.0002 0.0001 Site 7
- South East 20I 56 0.0146 0.0328 Site 8 --North West 101 31 0.0101 0.0199 Site9 --South West 150 50 0.0222 0.0404 Site 10-- North West 150 40 0.0125 0.0230 "Average value for all meters (i.e., leaking andnon-leaking) screened at the site.

B-25The average emission factor for residential customermeters was derived by averaging the emission rates forthe ten sites. The emission factor was convertedto units ofscf/meter-yrby assuming thatthe losses from the leaking meters were continuous throughoutthe year. The precision represents the 90%confidence interval and was calculated by averaging the standard deviations for the ten sites. The emission factor forcommercial/industrialcustomermeters was derived from screeningdata collecteu at atotal offour sites. Asummary ofthe average emissions from each ofthe four sites is shown in the followingtable:

Site Number ofMeters NumberofLeaking Average Leak Rate• Standard Deviation• Screened Meters {lb methane/day) {lb methane/day) Site 3-- EastCoast 45 12 0.0112 0.0251 Site4
-- Mid-West 61 0 

# -- -- Site 5-- Rocky 21 6 0.0088 0.0076 Mountain Site 6 -- West Coast 22 1 0.0018 

# -- "Average valueforall meters (i.e.,leaking and non-leaking)screened atthe site. The average emission factor for commercial/industrial customermeters was derivedby averagingthe emission rates forthe four sites. Theemission factor was convertedto unitsofscfi'meter-yrby assuming thatthe losses from the leakingmeters was continuousthroughoutthe year. ACTMTYFACTOR: (outdoorresidential meters: 40,049,306 :i:: 4,200,135 commercial/industrial meters: 4,608,000 :i:: 230,400) The total numberofcustomermeters in the U.S. gas industry, 56,132,300, andthe numberofresidential customer meters, 51,524,600, were based on Gas Facts,American Gas Association, 1992 (2). The numberofresidential customermeters located indoors versus outdoors was estimatedbased on aregional breakdown oftotal customers presented in GasFacts (2)combined with data obtained from 22 individual gas companies within differentregions ofthe country. (Note: Thenumberofcustomers in eachregion was used to estimate the numberofindoormeters because data on number ofcustomermeters segregated by region were notavailable.) Following is the averagepercentage ofcustomermeters located indoors in each region:

B-26Total Residential Average Percent Region Customers IndoorMeters New England l ,886,500 52 MiddleAtlantic 8,403,400 61 East North Central Il ,633,500 17 West North 4,684,100 40 Central South Atlantic 4,987,700 21 East South Central 2,465,200 0 West South 5,666,600 0 Central Mountain 3,318,700 0 Pacific 9,724,500 5

TOTAL 52,770,200 •Estimated based on engineeringjudgement. bEstimated foreach state separately in region. Estimated Sample Indoor Size Meters Precision 1 980,980 471,625" 7 5,126,074 1,905,37I 7 1,977,695 !,46I,663 1 1,873,640 1,873,640" 4 1 ,030,680b 1 ,030,680'



# -- 0 123,260'



# -- 0 283,330°



# -- 0 331,870' 2 486,225 486,225" 22 l 1,475,294 3,317,254
<Estimated based on industrycomments suggestingthat customermeters in southern regions are essentially all located outdoors. Theestimatednumberofindoormeters, 1 I,475,294, was subtracted'from the total numberofreported meters, 51,524,600,to derivean estimated40,049,306outdoorresidential customermeters in the United States. The precision was estimated from the dataprovided by the companies,engineeringjudgement for someregions, and an estimated 5%error in the nationallyreported numberofresidential customermeters. The leakage rates from customermeters located indoors was assumed to be negligible based on the increased probabilitythat leaks on indoormetersets are detected and repairedpromptly. This assumption ofnegligible leakage from indoormeters is consistentwith the fmdings from pressureregulating stations located in vaults. The precision ofthe total estimatedcommerciaVindustrialcustomermeters is assumed tobe±5%ofthe estimated 4,608,000meters. ANNUAL EMISSIONS: (5.8 ± I.I Bscrtyr) REFERENCES 1. 2. IndacoAir Quality Services, Inc. MethaneEmissions/romNatural Gas CustomerMeters: ScreeningandEnclosureStudies, Draft Report, August I5, I992. American Gas Association. Gas Facts. Arlington, VA. 1992. B-27

### APPENDIXC Conversion Table

C-1Unit Conversion Table English toMetric Conversions 

### Iscfmethane 

### = 19.23 g methane I Bscfmethane 

### = 0.01923 Tg methane I Bscfmethane 

### = 19,230 metric tonnes methane 1Bscf 

### = 28.32 million standard cubicmeters I shortton (ton) 

### = 907.2 kg I lb 

### = 0.4536kg I ft' 

### = 0.02832 m3 

### I ft' 

### = 28.32 liters I gallon 

### = 3.7851iters I barrel (bbl) 

### = 158.97liters I 

### inch 

### = 2.540cm 1ft 

### = 0.3048 m I mile 

### = 1.609 km I hp 

### = 0.7457kW I hp-hr 

### = 0.7457kW-hr !Btu 

### = 1055joules I MMBtu 

### = 293 kW-hr Ilb/MMBtu 

### = 430g!GJ T (°F) 

### = 1.8 T ( 0C)

### +32 

### 1psi 

### = 51.71 mmHg
GlobalWarming Conversions 

### Calculatingcarbon equivalents ofany gas:
MMTCE ( MW, carbon) = (MMT of gas) x x {GWP) MW, gas



### C-2Calculating C02equivalentsfor methane:

MMT of C02 equiv. 

### ' ( ccM:::W_,--,C::-;0-;'-') ' IGWp

### I MW I CH4
where MW(molecularweight) ofC02

**~** 44,MW

**carbon~** 12, andMWCH,

**~** 16.

scf Bscf MMscf Mscf Tg Giga (G) Metric tormes ps1g pSia 

### GWP MMT MMTCE MMTofC02eq.

**~** Standardcubic feet. Standardconditions are at 14.73 psia and 60°F. Billionstandard cubicfeet (IO' sci). Million standardcubicfeet. Thousand standardcubic feet. Teragrarn (1012 g). Sameas billion (IO'). 1000kg. Gaugepressure. Absolutepressure (note psia = psig +atmospheric pressure). Global Warming Potential ofa particulargreenhouse gas for a given timeperiod. Millionmetric tonnes ofa gas. Million metrictonnes, carbonequivalent. Millionmetrictonnes, carbon dioxide equivalent.
C-3TECHNICAl REPORT DATA

**(PI~** TUdIIU/nlctiOIUon 1Mrevou M[ore**compl~ting)** 1. REPORT NO. 

# I' 3. RECIPIENT'S ACCESSION NO. 

### EPA-600/R-96-080h 4. TITLE AND SUBTITLE 5. REPORT DATE 

### Methane Emissions from the Natural Gas Industry, 

### June 1996

Volumes 1-15 (Volume 8: Equipment Leaks) 6. PERFORMING ORGANIZATION CODE 1. AVTHoAcsJ 

### L. CamfJrbell, M. Camrfbell. M.
**Cow~L**

### D.Ep- 8. PERFORMING ORGANIZATION REPORT NO. 

### ¥-erson, M. Hall,
.Harrison,
. Hummel.D. yers, 

### DCN 96-263-081-17 . Shires.B.Stapper,

## c. Stapper,J.

### Wessels, and 

# * $.PERFORMING OROANIZATION NAME AND ADDRESS 10.PROGRAM ELEMENT NO. 

### Radian International LLC 

### P.0. 

### Box 201088 11. **CONTRACT~GRANT** NO. 

### Austin, Texas 

### 78720-!088 5091-251-2!71 (GRI) 68-Dl-0031 (EPA) 1:Z.SPONSORING AGENCY NAME AND ADDRESS 13.TYPE OF R'PORT

## 7NO PERIOD COVERED 

### EPA, Office of Research and Development Final; 3 91-4 96 14. SPONSORING AGENCY CODE 

### .Air Pollution Prevention and Control Division 

### Research Triangle Park, NC 

### 277ll EPA/600/13 1s.suPPLEMENTARY NoTEsEPA 

### project officer is 

### D.A.

### Kirchgessner. MD-63,919/541-4021. Cosponsor GRI project officer is R.A. 

### Lett. Gas Research Institute, 8600 West Bryn 

### Mawr Ave•• 

### Chicago, IL 60631. (*)H. 

### Williamson (Block 7). 16. ABSTRACT

### The 15-volume report summarizes the results of a comprehensive program o quantify methane (CH4) emissions from the U.S. natural gas industry for the base 

### ear. The objective was to determine CH4 emissions from the wellhead and ending ownstream at the customer's meter. The accuracy goal was to determine these missions within +/-0.5% of natural gas production for a 90% confidence interval. F01



### ~e 1992 base year, total CH4 emissions for the U.S. natural gas industry was 314 

### +!- 105 Bscf (6.04 

### +/- 2.01 Tg). This is equivalent to !.4 

### +/- 0.5% ofgross natural gas production, and reflects neither emissions reductions (per the voluntary AmeriGas Association/EPA Star Program) nor incremental increases (due to increased gas usage) since 1992. Results from this program were used to compare greenhouse

as emissions from the fuel cycle for natural gas•. oil. ·and coal using the global warming potentials (GWPs) recently published by the Intergovernmental Panel on Climate Change (IPCC). The analysis showed that natural gas contributes less to potential global warming than coal or oiL which supports the fuel switching strategy suggested by the IPCC and others. In addition, study results are being used by 

### the natural gas industry 

### to reduce operating costs while reducing emissions. 

# "· KEY WORDS AND DOCUMENT ANALYSIS 

# .. DESCRIPTORS b.IDENTIF/ERS/OI>EN ENOEO TERMS c COSATI Field/Group 

### Pollution !Pollution Prevention 

### l3B Emission Stationary Sources 

### l4G Greenhouse Effect Global Warming 

### 04A Natural Gas 

### 21D Gas Pipelines 

### l5E Methane



### ~7C 18. D!STRISUTION STATEMENT 19.SECURITY CLASS {This

**R~pOH)** 21.NO.OFPAGES 

### Unclassified 130 Release to Public :ZO. SECURITYClASS

**{Thi~**p4ge} :Z:Z. PRICE 

### Unclassified EPA Form 2220-1 (9-73) 

### C-4Q-ti!IH»iftl**~.Mi.HUIIY,n•ww:.** Vf:t:LJJW.lillll_l W**t~j _r~:.·MH<i"'~'lilill**  

### - '; -

### ·- - - -

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

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### U.S. ENVIRONMENTAL PROTECTIONAGENCY 

### Office ofResearch and Development National Risk Management Research Laboratory TechnologyTransferand SupportDivision 

### Cincinnati, Ohio 45268 OFFICIAL BUSINESS PENALTV FOR PRIVATE USE. :S300 AN EQUAL OPPORTUNITY EMPLOYER

Ifyour

**~dr~n** is

**incorr~ct.** pi .sse changtt on lhtJ abovtt label tear oil; andtetum to the above Mfdtus. Ifyou do not dttsire to continue receiving these technical reports. CHECKHER£0: tear offlabel, andteturn it to the above address. 

## Publication No. EPA-600/R-96-0SOh **,·~**

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