EPA-600/R-96-080a June 1996 METHANE EMISSIONS FROM THE NATURAL GAS INDUSTRY, VOLUME 1: EXECUTIVE SUMMARY FINAL REPORT Prepared by: Matthew R. Harrison Theresa M. Shires Jane K. Wessels R. Michael Cowgill Radian International LLC 8501 N. Mopac Blvd. P.O. Box 201088 Austin, TX 78720-1088 DCN: 96-263-081-17 Prepared for: GRI Project Manager: Robert A. Lott GAS RESEARCH INSTITUTE Contract No. 5091-251-2171 8600 West Bryn Mawr Avenue Chicago, IL 60631 and EPA Project Manager: David A. Kirchgessner U.S. ENVIRONMENTAL PROTECTION AGENCY Contract No. 68-D1-0031 National Risk Management Research Laboratory Research Triangle Park, NC 27711 ------- EPA REVIEW NOTICE This report has been peer and administratively reviewed by the U.S. Environmental Protection Agency, and approved for publication. Mention of trade names or commercial products does not constitute endorsement or recommendation for use. This document is available to the public through the National Technical Information Service, Springfield, Virginia 22161. DISCLAIMER LEGAL NOTICE: This report was prepared by Radian International LLC as an account of work sponsored by Gas Research Institute (GRI) and the U.S. Environmental Protection Agency (EPA). Neither EPA, GRI, members of GRI, nor any person acting on behalf of either: a. Makes any warranty or representation, express or implied, with respect to the accuracy, completeness, or usefulness of the information contained in this report, or that the use of any apparatus, method, or process disclosed in this report may not infringe privately owned rights; or b. Assumes any liability with respect to the use of, or for damages resulting from the use of, any information, apparatus, method, or process disclosed in this report. NOTE: EPA's Office of Research and Development quality assurance/quality control (QA/QC) requirements are applicable to some of the count data generated by this project. Emission data and additional count data are from industry or literature sources, and are not subject to EPA/ORD's QA/QC policies. In all cases, data and results were reviewed by the panel of experts listed in Appendix D of Volume 2. ii ------- FOREWORD The U. S. Environmental Protection Agency is charged by Congress with pro- tecting the Nation's land, air, and water resources. Under a mandate of national environmental laws, the Agency strives to formulate and implement actions lead- ing to a compatible balance between human activities and the ability of natural systems to support and nurture life. To meet this mandate, EPA's research program is providing data and technical support for solving environmental pro- blems today and building a science knowledge base necessary to manage our eco- logical resources wisely, understand how pollutants affect our health, and pre- vent or reduce environmental risks in the future. The National Risk Management Research Laboratory is the Agency's center for investigation of technological and management approaches for reducing risks from threats to human health and the environment. The focus of the Laboratory's research program is on methods for the prevention and control of pollution to air, land, water, and subsurface resources; protection of water quality in public water systems; remediation of contaminated sites and groundwater; and prevention and control of indoor air pollution. The goal of this research effort is to catalyze development and implementation of innovative, cost-effective environmental technologies; develop scientific and engineering information needed by EPA to support regulatory and policy decisions; and provide technical support and infor- mation transfer to ensure effective implementation of environmental regulations and strategies. This publication has been produced as part of the Laboratory's strategic long- term research plan. It is published and made available by EPA's Office of Re- search and Development to assist the user community and to link researchers with their clients. E. Timothy Oppelt, Director National Risk Management Research Laboratory iii ------- RESEARCH SUMMARY Title Methane Emissions from the Natural Gas Industry, Volume 1: Executive Summary Contractor Radian International LLC GRI Contract Number 5091-251-2171 EPA Contract Number 68-D1-0031 Principal Investigator Report Period Objective Technical Perspective Matthew R. Harrison March 1991 - June 1996 Final Report This report describes the results of a study to quantify the annual methane emissions from the natural gas industry. The increased use of natural gas has been suggested as a strategy for reducing the potential for global warming. During combustion, natural gas generates less carbon dioxide (C02) per unit of energy produced than either coal or oil. On the basis of the amount of C02 emitted, the potential for global warming could be reduced by substituting natural gas for coal or oil. However, since natural gas is primarily methane, a potent greenhouse gas, losses of natural gas during production, processing, transmission, and distribution could reduce the inherent advantage of its lower C02 emissions. To investigate this, Gas Research Institute (GRI) and the U.S. Environmental Protection Agency's Office of Research and Development (EPA/ORD) cofunded a major study to quantify methane emissions from U.S. natural gas operations for the 1992 base year. The results of this study can be used to construct global methane budgets and to determine the relative impact on global warming of natural gas versus coal and oil. This summary report is Volume 1 of a multi-volume set of reports that fully describe the project. Results The national emissions for the base year are 314 ± 105 Bscf (± 33%), which is equivalent to 1.4 ± 0.5% of gross natural gas production. In metric units, this is 6.04 ± 2.01 Tg. The overall program also showed that the percentage of methane emitted for an incremental increase in natural gas sales would be significantly lower than the baseline case. iv ------- Technical Approach Project Implications The program reached its accuracy goal and provides an accurate estimate of methane emissions that can be used to construct U.S. methane inventories and analyze fuel switching strategies. The techniques used to determine methane emissions were developed to be representative of annual emissions from the natural gas industry. However, it is impractical to measure every source continuously for a year. Therefore, emission rates for various sources were determined by developing annual emission factors for typical sources in each industry segment and extrapolating these data based on activity factors to develop a national estimate, where the national emission rate is the product of the emission factor and activity factor. The development of specific emission factors and activity factors for each industry segment are presented in a separate report. For the 1992 base year the annual methane emissions estimate for the U.S. natural gas industry is 314 Bscf ± 105 Bscf (± 33%). This is equivalent to 1.4% ± 0.5% of gross natural gas production, and does not reflect any emissions reductions (per the voluntary American Gas Association/EPA Star Program) nor incremental increases (due to increased gas usage) since 1992. Results from this program were used to compare greenhouse gas emissions from the fuel cycle for natural gas, oil, and coal using the global warming potentials (GWPs) recently published by the Intergovernmental Panel on Climate Change (IPCC). The analysis showed that natural gas contributes less to potential global warming than coal or oil, which supports the fuel switching strategy suggested by IPCC and others. In addition, results from this study are being used by the natural gas industry to reduce operating costs while reducing emissions. Some companies are also participating in the Natural Gas-Star program, a voluntary program sponsored by EPA's Office of Air and Radiation in cooperation with the American Gas Association to implement cost-effective emission reductions and to report reductions to EPA. Since this program was begun after the 1992 baseline year, any reductions in methane emissions from this program are not reflected in this study's total emissions. Robert A. Lott Senior Project Manager, Environment and Safety v ------- TABLE OF CONTENTS Page 1.0 SUMMARY 1 2.0 INTRODUCTION/BACKGROUND 1 3.0 METHOD FOR ESTIMATING EMISSIONS 2 3.1 Accounting for All Emission Sources 2 3.2 Measuring and Calculating Emissions 3 3.3 Extrapolating Emissions 4 3.4 Assessing Accuracy 5 4.0 RESULTS 5 4.1 1992 Baseline Emissions 5 4.2 Emissions from Incremental Increases in Gas Sales 8 4.3 Emissions and Fuel Switching 9 5.0 CONCLUSIONS 9 6.0 REFERENCES 10 APPENDIX A - Conversion Table A-l LIST OF FIGURES 3-1 Gas Industry Flow Chart 3 4-1 Contribution of Major Methane Sources to Total U.S. Anthropogenic Emissions 6 4-2 Summary of Methane Emissions 6 LIST OF TABLES 4-1 Largest Emission Sources by Industry Segment 7 vi ------- 1.0 SUMMARY Gas Research Institute (GRI) and the U.S. Environmental Protection Agency's Office of Research and Development (EPA/ORD) cofunded a major study to quantify methane emissions from U.S. natural gas operations. For the 1992 base year, total methane emissions were estimated at 314 ± 105 Bscf (± 33%), which is equivalent to 1.4% ± 0.5% of gross natural gas production. In metric units, this is 6.04 ± 2.01 Tg. Since 1992, many companies have participated in voluntary programs' designed to reduce emissions. Methane emission reductions from these programs are not reflected in this report. However, methane emissions from a future incremental increase in gas sales were evaluated. The incremental increase in methane emissions per the incremental increase in natural gas usage is only one-third to two-thirds of the 1.4% base emission rate. This study provides data from the U.S. natural gas industry needed for constructing global methane inventories and for determining the relative impacts of coal, oil, and natural gas use on global warming. Using this study's emissions estimate and some key assumptions (see Section 4.3), an analysis showed that the impact on warming from the use of oil and coal per unit of energy generated is much larger than the impact from the use of natural gas. This study is documented in a multi-volume set where this executive summary is the first volume. The Volume 2 report is a technical summary that includes a discussion of what was done and how the measurements and calculations were performed.2 There are 15 volumes that fully document the study. A complete list of these reports appears in the Volume 2 report. 2.0 INTRODUCTION/BACKGROUND This report presents a summary of a major study conducted by GRI and EPA to quantify methane emissions from U.S. natural gas operations. The goal was to determine these emissions to within ± 0.5% of natural gas production, starting at the wellhead and ending immediately downstream of the customer's meter. The study was conducted because this information is needed to determine if natural gas can be used as an integral part of a fuel switching strategy to reduce the potential of global warming, and to provide data for a global methane inventory. Carbon dioxide (C02) contributes nearly as much to global warming as all other greenhouse gases combined. Since natural gas produces much less C02 per unit of energy when combusted than either coal or oil, the Intergovernmental Panel on Climate Change (IPCC), EPA, and others have suggested that by promoting the increased use of natural gas, global warming could be reduced.3'4 However, methane, which is the major constituent of natural gas, is also an important greenhouse gas, and on a weight basis methane is a more potent greenhouse gas than C02. For this reason, it was important to determine if emissions from the natural gas industry are large enough to substantially reduce or even eliminate the advantage that natural gas has because of its much lower C02 emissions during combustion. 1 ------- This study, like other efforts to develop emission inventories, had to address several difficult problems. Most of these problems were primarily associated with the size and diversity of the natural gas industry and the number of sources that must be considered. This industry complexity, combined with the lack of both equipment populations and methods for estimating emissions, meant that early in the program, resources were devoted to developing comprehensive methods for estimating and extrapolating emissions. This also included selecting an accuracy goal that could reasonably be achieved but was sufficiently accurate to examine the fuel switching strategy. Considering these issues, a method of approach was developed that: • Accounted for all emission sources; • Measured and calculated emissions; • Extrapolated emissions data; and • Assessed the accuracy of the final estimate. The following sections of this summary report briefly describe the method of approach listed above, present the results of the study, and summarize the conclusions. 3.0 METHOD FOR ESTIMATING EMISSIONS This summary provides a brief description of the method used to estimate methane emissions from the natural gas industry. The methodology is discussed in detail in two separate volumes: the Volume 2 Technical Report and the Volume 3 Methods Report.2,5 3.1 Accounting for All Emission Sources The natural gas industry (as shown in Figure 3-1) was divided into four segments: production, processing, transmission/storage, and distribution. The project established boundaries for each industry segment to specify the equipment included in the study. The guideline used for setting the boundary was to include only the equipment in each segment that is required for marketing natural gas. To fully characterize the natural gas industry and account for all potential sources of methane, the four industry segments were divided into facilities, equipment, and components, and emission sources were identified by equipment type, mode of operation, and type of emission. Equipment types included individual devices, such as a pneumatic operator; large pieces of equipment, such as compressors; or a grouping of equipment, such as an offshore platform. Modes of operation are: start-up, normal operations, maintenance, upsets, and mishaps. Emission types are: fugitive, vented, and combustion. For this project each emission source was accounted for by carefully examining the operating mode for each equipment category. This differentiation ensured that all emission sources were accounted for and that all types of emissions from the source were considered. For example, compressor engines can be a significant source of fugitive, vented, and combustion 2 ------- emissions that result from a variety of operating modes. During normal operations, unburned methane is emitted in the engine exhaust and fugitive emissions can result from leaks in valves and pressurized connections. Also, natural gas is vented during engine start-ups if natural gas is used to power the starter turbine. During upsets, natural gas is released from compressor blowdown and pressure relief valves, and natural gas is vented during compressor blowdown for maintenance activities. PRODUCTION DISTRIBUTION Main and Service Pipelines M&PR Stations , @ Customer Meters m Compressor ® Meter 3 Pressure Regulator Figure 3-1. Gas Industry Flow Chart 3.2 Measuring and Calculating Emissions Initially, few methods were available for measuring and/or calculating emissions from natural gas facilities. Therefore, the early stages of this study were spent developing measurement techniques and demonstrating them in the field before using these techniques to gather data for the study. On the basis of these proof of concept tests, three measurement methods were eventually chosen for use in this study. For pipeline leaks, the emission rate was measured by isolating the section of pipe with the leak and measuring the amount of gas needed 3 ------- to maintain operating pressure in the line. For fugitive leaks from above ground facilities, either a tracer gas method or a component emission factor approach was used. For the tracer gas method, a tracer gas such as sulfur hexafluoride (SF6) is released at a known constant rate near the methane source. The emission rate was determined by measuring the concentration of the tracer and methane downwind; since the ratio of emission rates is equal to the ratio of concentrations, the methane emission rate can be calculated. The component emission measurement approach develops average emission rates for the basic components (valves, flanges, seals and other pipe fittings) that comprise natural gas facilities. The total emissions from the facility are the product of the number of components times the corresponding emission factor. New component emission factors were developed as a result of this study for natural gas production and processing facilities, compressor stations, and residential and commercial meters. Also a new "Hi-Flow" instrument was developed that can measure emissions quickly and accurately from pneumatic control devices, valves, flanges and other pipe fittings.6 In some cases it is more accurate and less complicated to calculate, rather than measure, emissions. An example is emissions from a "blowdown" to make a pipe repair. Knowing the temperature and pressure of the gas, the volume of the pipe, and the frequency of the event, emissions can be calculated. Another reason for calculating emissions is that it may not be practical to measure emissions from some sources. Since annual emissions are needed for the study, it is not practical to try to measure highly variable, unsteady emissions. In developing engineering models for calculating these types of emissions, it is necessary to first understand the equipment and the nature of the process causing the emissions and then to collect field data on the frequency of the event. 3.3 Extrapolating Emissions A considerable amount of field data was collected during this study. In addition to measuring emissions and collecting information on operating characteristics of equipment and frequency of events, a substantial effort was required to collect information on equipment populations. Equipment counts are needed to extrapolate measured and calculated emissions to other similar sources in the industry. Data were collected on each source category identified during initial stages of the project. However, because of the large number of sources in each source category, data were collected on a relatively small percentage of all sources in each category. Therefore, these data had to be extrapolated to account for the sources that were not measured in order to develop a national emissions estimate. To extrapolate the emission data, emission and activity factors were defined so that their product equals the annual nationwide emissions from a given source category. Typically, the emission factor is defined as the average annual emissions from a piece of equipment or event. The activity factor would then be the national population (i.e., the total equipment count or total number of events). For example, if fugitive emissions from compressor 4 ------- engines is the source category, then average emissions per engine would be the emission factor, and the number of engines would be the activity factor. Although this approach is straightforward, the application proved to be difficult due to the lack of data on equipment populations and operational events. Limited information is available on a national basis. Collecting data on activity factors (i.e., number of separators, pneumatic control devices, miles of gathering lines, blowdown events, etc.) required a large number of site visits and was therefore a major part of the study. 3.4 Assessing Accuracy The accuracy of the emissions estimate is dependent on the precision and bias of both the activity and emission factors. In developing activity factors, as in conducting emission measurements, care was taken in developing sampling protocols, detecting and eliminating bias, and developing methods for calculating precision. The accuracy goal of the project was to determine emissions from the natural gas industry to within ± 0.5% of gross natural gas production. This goal was established based on the accuracy needed for constructing emission inventories for use in global climate change models and for assessing the validity of the proposed fuel switching strategy. The first step in achieving the accuracy goal was to develop accuracy targets for each source category. Accuracy targets were assigned so that a higher degree of accuracy would be required for the largest sources while achieving the overall program goal. This had the additional advantage of automatically assigning more program resources to the most important source categories. Accuracy is made up of precision and bias. Precision can be calculated but bias can only be minimized. To minimize bias, a sampling approach similar to disproportionate stratified random sampling was developed. A project review committee was established and industry advisory groups were formed for production, transmission and distribution to review the program and ensure that any potential for bias was identified and eliminated. Also the data were analyzed to ensure that data were not sampled disproportionately with respect to the parameters that had a large impact on emissions. This not only minimized bias but also reduced the impact that out- lying data points had on the result. The precision of the activity and emission factors was calculated for a 90% confidence level from the number of data points collected and the standard deviation. The precision of the emission estimate for each source category as well as the national estimate was also calculated in a statistically rigorous fashion. 4.0 RESULTS 4.1 1992 Baseline Emissions Total methane emissions from the natural gas industry for the 1992 baseline year are 314 Bscf ±105 Bscf, or 6.04 ± 2.01 Tg. This is approximately 1.4 ± 0.5% of gross natural gas 5 ------- production, and this result meets the project accuracy goal. This represents approximately 20% of total U.S. anthropogenic (manmade) emissions, based on methane emission estimates reported by the U.S. EPA for major anthropogenic sources7 (see Figure 4-1). Figure 4-2 presents methane emissions for the natural gas industry by industry segment. The transmission/storage segment accounts for the largest portion of emissions (37%) with the processing segment contributing the least (12%). Other 6% Figure 4-1. Contribution of Major Methane Sources to Total U.S. Anthropogenic Emissions Distribution 37% Figure 4-2. Summary of Methane Emissions 6 ------- The largest emission sources for each industry segment are presented in Table 4-1. Fugitive emissions are the largest contributor to methane emissions from natural gas processing, transmission and storage. Nearly 90% of these emissions result from leaks on compressor components such as the suction, discharge and blowdown valves, pressure relief valves, and compressor seals. Fugitive emissions from all compressor components are approximately 80 Bscf (1.6 Tg), while fugitive emissions from all other compressor station components, such as yard piping and filter-separators, are approximately 10 Bscf (0.19 Tg). Compressor and generator engine exhausts are responsible for slightly more than 25 Bscf (0.48 Tg) of methane emissions. TABLE 4-1. LARGEST EMISSION SOURCES BY INDUSTRY SEGMENT Annual Methane Emissions Percent of (Tg) Segment Segment Source Total Production Pneumatic devices 31 0.60 37 Fugitive emissions 17 0.33 21 Dehydrators 14 0.28 17 Other 21 0.41 25 Processing Fugitive emissions 24 0.47 67 Compressor exhaust 7 0.13 19 Other 5 0.10 14 Transmission/Storage Fugitive emissions 68 1.30 58 Blow and purge 19 0.36 16 Pneumatic devices 14 0.27 12 Compressor exhaust 11 0.22 10 Other 5 0.10 4 Distribution Underground pipeline leaks 42 0.80 54 Meter and pressure regulating 27 0.53 35 stations Customer meters 6 0.11 8 Other 2 0.04 3 TOTAL* 314 Bscf 6.04 Tg individual sources may not sum exactly to total shown due to roundoff errors. Fugitive emissions from pipelines are approximately 48 Bscf (0.93 Tg), of which 42 Bscf (0.80 Tg) is from distribution piping. Distribution piping systems actually emit 51 Bscf (0.98 Tg), but approximately 18% of the natural gas leaked is oxidized in the soil by methanotrophs. Approximately 22 Bscf (0.42 Tg) is leaked from cast iron mains which constitute only 6% of the total miles of distribution main pipelines. However, most cast iron leaks are very small and since 7 ------- the oxidation rate varies inversely with leak rate, only 60% of the leaks (13 Bscf or 0.25 Tg) reach the surface. The two largest methane emission sources in natural gas production are pneumatic control devices and fugitives. Prior to this study, pneumatic devices were not considered a major emission source. Approximately one-third of these devices continuously bleed natural gas to the atmosphere. Pneumatic devices are the largest source of methane emissions in the production segment, accounting for 31 Bscf (0.60 Tg). Total fugitive emissions from production equipment are large even though the average leak rate is small, because of the large number (approximately 80 million) of valves, connectors and other pipe fittings on equipment located at production sites across the country. 4.2 Emissions from Incremental Increases in Gas Sales Consumption of natural gas has increased since the base year of 1992. To determine the effect that this increase and future increases will have on emissions, a study was conducted to determine the percent increase in emissions resulting from an incremental increase in natural gas production and sales.8 The study found that increases in throughput would, in many cases, produce increases in emissions. However, the average increase in emissions would be proportionally smaller than the increase in system throughput. The study examined the consequences of increasing gas sales by 5, 15, and 30% under three scenarios: uniform, winter peak, and summer peak load profiles. All segments of the gas industry were examined to determine the percent increase in equipment that would be needed to meet the increased demand. The percent increase in emissions was then estimated based on changes in the current system that would be required to accommodate the increase in gas sales. The GRI/EPA's emission estimate was used to calculate the percent increase in emissions that would result from an incremental increase in natural gas sales for several scenarios examined in the study. The most realistic scenario assumed that the system would be expanded using the latest technologies, whereas the most conservative scenario assumed that the expanded system mirrors the existing system. Generally, as the system expands, the emission rate for the expansion would be less, as a percent of throughput, than for the base system. Emissions from a system load increase (an increase in consumption of gas) of 30% would emit at only one-third to two-thirds of the base emission rate. For example, if gas production increased by 30% (6 to 7 trillion cubic feet per year), emissions from the system expansion would be between 30 and 70 Bscf. These emissions, when divided by the incremental production, are equivalent to an emission rate between 0.4 and 1.0% of incremental production. This is much lower than the 1.4% of production emitted from the current base system for 1992. The reason emissions are lower for an incremental increase in gas sales is that the current system has excess capacity and any additional equipment that would have to be installed to meet increased demand would use current and lower emitting technology. A few examples of 8 ------- these technologies are no-bleed pneumatic devices, turbine compressor engines, and plastic pipe instead of steel and cast iron mains. 4.3 Emissions and Fuel Switching The estimate of methane emissions from natural gas operations was used in an analysis to determine if the potential for global warming could be reduced by switching from coal or oil to natural gas. Emissions from coal and oil were estimated from other sources. Other than C02 and methane, emissions from other greenhouse gases from the fuel cycle of fossil fuels are negligible. Methane, however, is a more potent greenhouse gas than C02. The approach used was to determine the emissions of methane and C02 for the complete fuel cycle of natural gas, oil, and coal, and to convert the methane emissions to equivalent C02 using the Global Warming Potential (GWP). The GWP is an index that relates the impact of releasing quantities of the various greenhouse gases to the release of an amount of C02 that would produce the same impact on global warming. Currently, there is a great deal of uncertainty in the time period associated with the GWP of methane. Typical time periods range from 50 to 500 years, which correspond to GWP values of 34 and 6.5, respectively. This means that one pound of methane is equivalent to between 6.5 and 34 pounds of C02. Equivalent C02 emissions from the fuel cycle of natural gas were calculated to be 132 lbs/106 Btu (60 kg/106 Btu) for a GWP of 6.5 and 152 lb/106 Btu (69 kg/106 Btu) for a GWP of 34. Even for a GWP of 34, the analysis showed that, compared to natural gas, oil has 1.2 times the impact on global warming and coal has 1.5 times the impact. 5.0 CONCLUSIONS Based on data collected, methane emissions from natural gas operations are estimated to be 314 ± 105 Bscf (6.04 ± 2.01 Tg) for the 1992 baseline year. This is approximately 1.4 ± 0.5% of gross natural gas production. This study also determined that the ratio of methane emitted per gas production rate for an incremental increase in natural gas sales would be between 1.19% and 1.38% of total gas production, compared to 1.4% of production for the baseline case. Results from this study were used to compare greenhouse gas emissions from the fuel cycle for natural gas, oil, and coal using the GWPs recently published by the IPCC.3 The analysis showed that natural gas contributes significantly less to global warming per unit of energy than coal or oil, which supports the fuel switching strategy suggested by IPCC and others. This study, like other efforts in developing emission inventories, had to address the following typical but never-the-less difficult problems: • Collecting demographic information; • Developing methods for measuring and calculating emissions; 9 ------- • Extrapolating a limited amount of data to a large, diverse national population; and • Determining the accuracy of the final estimates. The most difficult of these is evaluating the accuracy. Accuracy targets were established for each source category that would be needed to achieve the overall accuracy goal of the study. A sampling procedure with checks for bias was then established, data were collected, and the precision of the emission estimate was rigorously calculated for each category, as well as for the national estimate. During the course of the study, equipment population in the gas industry was collected and new methods were developed for measuring emissions from a variety of sources. Unique methods were developed using tracer gas techniques, and a new "Hi-Flow" instrument was developed that provides a quick, cost-effective method for measuring the leak rate of valves, seals, pneumatic devices, and connectors. 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,1 a voluntary program sponsored by EPA's Office of Air and Radiation in cooperation with the American Gas Association to implement cost-effective emission reductions and to report reductions to the EPA. Since this program was begun after the 1992 baseline year, any reductions in methane emissions from this program are not reflected in this study's total emissions. In conclusion, the project reached its accuracy goal and provides an accurate estimate of methane emissions for 1992 gas industry practices. The results can be used to construct U.S. methane inventories and analyze fuel switching strategies. 6.0 REFERENCES 1. U.S. Environmental Protection Agency, Natural Gas STAR: The Second Year, EPA- 430-F-96-010, Office of Air and Radiation, Winter 1995/1996. 2. Harrison, M.R., L.M. Campbell, T.M. Shires, and R.M. Cowgill. Methane Emissions from the Natural Gas Industry, Volume 2: Technical Report, Final Report, GRI- 94/0257.1 and EPA-600/R-96-080b, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 3. World Meteorological Organization. Climate Change 1995 The Science of Climate Change. Intergovernmental Panel on Climate Change, United Nations Environment Programme, 1996. 10 ------- 4. U.S. Environmental Protection Agency. Options for Reducing Methane Emissions Internationally, Volume 1: Technological Options for Reducing Methane Emissions, Report to Congress, EPA-430-R-93-006, U.S. Environmental Protection Agency, Office of Air and Radiation, Washington, DC, July 1993. 5. Harrison, M.R., H.J. Williamson, and L.M. Campbell. Methane Emissions from the Natural Gas Industry, Volume 3: General Methodology, Final Report, GRI-94/0257.20 and EPA-600/R-96-080c, Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 6. Lott, R., M. Webb, and T. Howard. "New Techniques Developed for Measuring Fugitive Emissions," Pipeline and Gas, pp. 33-38, October 1995. 7. U.S. Environmental Protection Agency. Anthropogenic Methane Emissions in the United States: Estimates for 1990. Report to Congress, EPA-430-R-93-003, U.S. Environmental Protection Agency, Office of Air and Radiation, Washington, DC, April 1993. 8. Columbia Gas. An Engineering Estimate of the Incremental Change in Methane Emissions with Increasing Throughput in a Model Natural Gas System, Final Report, GRI-94/0257.32, American Gas Association and the Gas Research Institute, March 1993. 11 ------- APPENDIX A Conversion Table A-l ------- Unit Conversion Table English to Metric Conversions = 19.23 g methane = 0.01923 Tg methane = 19,230 metric tonnes methane = 28.32 million standard cubic meters 907.2 kg 0.4536 kg 0.02832 m3 = 28.32 liters = 3.785 liters = 158.97 liters = 2.540 cm 0.3048 m 1.609 km 0.7457 kW 0.7457 kW-hr = 1055 joules 293 kW-hr 430 g/GJ 1.8 T (°C) + 32 = 51.71 mm Hg Global Warming Conversions Calculating carbon equivalents of any gas: MMTCE = (MMT of gas) x ( MW> carbonx (GWp) ^ MW, gas ) 1 scf methane 1 Bscf methane 1 Bscf methane 1 Bscf 1 short ton (ton) 1 lb 1 ft3 lft3 1 gallon 1 barrel (bbl) 1 inch 1 ft 1 mile 1 hp 1 hp-hr 1 Btu 1 MMBtu 1 lb/MMBtu T(°F) 1 psi A-2 ------- Calculating C02 equivalents for methane: MMT of CO equiv. = (MMT CH.) x ' MW, C02^ MW, CH, x (GWP) where MW (molecular weight) of C02 = 44, MW carbon =12, and MW CH4= 16. Notes scf = Standard cubic feet. Standard conditions are at 14.73 psia and 60°F. Bscf = Billion standard cubic feet (109 scf). MMscf = Million standard cubic feet. Mscf = Thousand standard cubic feet. Tg = Teragram (1012 g). Giga(G) = Same as billion (109). Metric tonnes = 1000 kg. psig = Gauge pressure. psia = Absolute pressure (note psia = psig + atmospheric pressure). GWP = Global Warming Potential of a particular greenhouse gas for a given time period. MMT = Million metric tonnes of a gas. MMTCE = Million metric tonnes, carbon equivalent. MMT of C02 eq. = Million metric tonnes, carbon dioxide equivalent. ------- TECHNICAL REPORT DATA .1. (Please read Instructions on the reverse before compter || | ||| 1|||||| 11II1 III II11II 1. REPORT NO. 2. EPA-600/R-96-080 3. ii I in i linn 11 ii i in i mi in PB97-142 921 4. TITLE ANO SUBTITLE Methane Emissions from the Natural Gas Industry, Volumes 1-15 (Volume 1: Executive Summary) 5. REPORT DATE June 1996 6. PERFORMING ORGANIZATION CODE 7. author(s) L. Campbell, M. Campbell, M. Cowgill, D. Ep- person, M. Hall, M. Harrison, K. Hummel, D.TVIyers, T. Shires, B. Stapper, C. Stapper, J. Wessels, and * 8. PERFORMING ORGANIZATION REPORT NO. DCN 96-263-081-17 9. PERFORMING ORGANIZATION NAME AND ADDRESS Radian International LLC P. O. Box 201088 Austin, Texas 78720-1088 10. PROGRAM ELEMENT NO. 11. CONTRACT/GRANT NO. 5091-251-2171 (GRI) 68-D1-0031 (EPA) 12. SPONSORING AGENCY NAME ANO ADDRESS EPA, Office of Research and Development Air Pollution Prevention and Control Division Research Triangle Park, NC 27711 13. TYPE OF REPORT AND PERIOD COVERED Final; 3/91-4/96 14. SPONSORING AGENCY CODE EPA/600/13 16.supplementary notes EPA project officer is D. A. Kirchgessner, MD-63, 919/541-4021. Cosponsor GRI project officer is R. A. Lott, Gas Research Institute, 8600 West Bryn Mawr Ave., Chicago, IL 60631. (*)H. Williamson (Block 7). i6. ABSTRACT-phe 15-volume report summarizes the results of a comprehensive program to quantify methane (CH4) emissions from the U. S. natural gas industry for the base year. The objective was to determine CH4 emissions from the wellhead and ending downstream at the customer's meter. The accuracy goal was to determine these emissions within +/-0. 5% of natural gas production for a 90% confidence interval. For the 1992 base year, total CH4 emissions for the U. S. natural gas industry was 314 +/- 105 Bscf (6.04 +/- 2.01 Tg). This is equivalent to 1.4 +/- 0. 5% of gross natural gas production, and reflects neither emissions reductions (per the voluntary Ameri- Gas Association/EPA Star Program) nor incremental increases (due to increased gas usage) since 1992. Results from this program were used to compare greenhouse gas emissions from the fuel cycle for natural gas, oil, and coal using the global war- ming potentials (GWPs) recently published by the Intergovernmental Panel on Climate Change (IPCC). The analysis showed that natural gas contributes less to potential global warming than coal or oil, which supports the fuel switching strategy suggested by the IPCC and others. In addition, study results are being used by the natural gas industry to reduce operating costs while reducing emissions. 17. KEY WORDS AND DOCUMENT ANALYSIS a. DESCRIPTORS b.lDENTIFIERS/OPEN ENDED TERMS c. COSATI Field/Group Pollution Emission Greenhouse Effect Natural Gas Gas Pipelines Methane Pollution Prevention Stationary Sources Global Warming 13B 14G 04A 21D 15 E 07C 18. DISTRIBUTION STATEMENT Release to Public 19. SECURITY CLASS (ThisReport) Unclassified 21. NO. OF PAGES 20 20. SECURITY CLASS (Thispage) Unclassified 22. PRICE EPA Form 2220-1 (9-73) ------- |