Understanding the magnitude and sources of greenhouse

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1 Environmental Management Reprinted with permission from CEP, September Copyright 2005 American Institute of Chemical Engineers Ensuring Consistent Greenhouse Gas Emissions Estimates Karin Ritter American Petroleum Institute Susann rdrum Chevron Energy Technology Co. Theresa Shires URS Corp. Miriam Lev-On The LEVON Group, LLC These techniques can be used to estimate and report GHG emissions from a wide variety of diverse sources, thereby increasing global consistency. Understanding the magnitude and sources of greenhouse gas (GHG) emissions is a critical first step to managing them. Reliable GHG emission inventories developed in a consistent manner are fundamental for all GHG management schemes. For a large corporation with many divisions, facilities and operations, the key questions are: 1. Which company facilities and emission sources should be included? 2. How will the inventory account, if at all, for indirect emissions from operations outside the company facilities, but created in support of its operations? 3. What methods are available to estimate GHG emissions from a wide variety of sources? The tools discussed here are reliable, efficient and costeffective industry-endorsed methods for estimating and reporting GHG emissions, which may be combined with a data management system to create GHG emissions inventories. Although they were developed by the oil-and-gas industry for their operations, many of the recommended methodologies have broader applicability and could serve as useful guidance for numerous other industrial applications. Accounting and reporting guidelines It is important to understand the distinction between the accounting for and the reporting of emissions. Accounting addresses the recognition and consolidation of emissions from operations in which a parent company holds an interest, and linking the data to specific operations, sites, geographic locations, business processes and owners. Reporting deals with the presentation of greenhouse gas data in formats tailored to the needs of various uses for the reporting. A key issue is whether to report on the basis of operational control or equity share. Under the operational control approach, a company could report 100% of the GHG emissions from joint ventures over which it has operational control and none of the emissions from joint ventures it does not control. Operational control of a facility is the authority to introduce and implement operational and environmental, health and safety (EHS) policies at the joint venture. Under the equity share approach, GHG emissions are apportioned according to a company s economic interest in or the benefit it derives from a joint venture. This general rule applies unless specific contractual arrangements set other terms of operation. As a minimum, a company should include in its report direct GHG emissions that are consistent with its chosen approach to defining the organization s boundary (i.e., operational or equity share basis). Reporting indirect emissions from the import (consumption) of electricity, steam or hot water is optional, but if they are reported, they should be kept separate from direct emissions. In some situations, it might be relevant to report other indirect emissions, however, those should also be reported separately. Such situations may include, for example, third-party transport of materials up to custody transfer, outsourced operations such as maintenance, toll manufacturing, or processing by contractors September 2005 CEP

2 Table 1. Accounting and reporting principles for preparing GHG emissions inventories. A tiered approach to reporting, based on data availability and the intended use of the inventory, may be used. This allows companies with different quality objectives to consider the cost-effectiveness and relevance of quantifying each source category in the context of the facility s total GHG emissions. Table 1 summarizes important principles that should be incorporated into a GHG reporting system. Establishing an emissions inventory framework The first step in preparing a GHG emissions inventory is to establish the inventory boundaries and accounting framework i.e., deciding whether to include both direct and indirect emissions, and whether the inventory will be based on operational control or equity share. The next step is to identify the specific emission sources associated with each included facility and the appropriate methodologies for estimating these emissions. GHG emission sources can be classified into three major categories combustion devices, vented sources and fugitive sources (Table 2). The API Compendium provides techniques for determining GHG emissions from all of these sources. Quantification of GHG emissions can be complicated Relevance Completeness Consistency Transparency Accuracy Define boundaries that appropriately reflect the organization s GHG emissions and the decision-making needs of users. Account for all GHG emission sources and activities within the chosen organizational and operational boundaries. Any specific exclusion should be stated and justified. Consistent methodologies and measurements must be used to allow meaningful comparison of emissions over time. Any changes to the data, methods or other factors in the time series should be transparently documented. Address all relevant issues in a factual and coherent manner, based on a clear audit trail. Assumptions should be disclosed and appropriate references made to the calculation methodologies and data sources used. Ensure that GHG emissions are neither systematically over- nor under-estimated, as far as can be determined, and that uncertainties are quantified and reduced as far as practicable. Sufficient accuracy is needed to enable users to make decisions with reasonable assurance as to the integrity of the reported GHG information. Industry Guidelines and Tools With increased attention focused on the potential value and risk associated with GHG emissions, consistent, standardized methodologies for estimating these emissions are crucial to informed decision-making and to tracking progress toward emission-reduction targets. To that end, the worldwide oil-and-gas industry has voluntarily undertaken a significant project to improve global consistency in estimating GHG emissions and developed a set of tools to assist companies in this task. A collaborative effort among the American Petroleum Institute (API), the International Petroleum Industry Environmental Conservation Association (IPIECA), and the International Association of Oil and Gas Producers (OGP) developed the Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions (1). The API also published the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry (2). The API Compendium presents and illustrates the use of preferred and alternative approaches for calculating CO 2, CH 4 and N 2 O emissions from combustion, vented, fugitive and indirect sources. It includes decision trees to guide the user in selecting estimation techniques based on considerations of data availability, accuracy, and materiality (i.e., the significance of the source s emissions compared to the total emissions from the facility/entity). To augment the guidelines, Chevron developed an Excel-based computer program called the SANGEA Energy and Emissions Estimating System (3). Chevron transferred ownership of SANGEA to API, and the software is available from API to industry free of charge ( Although API neither endorses nor recommends any specific system, the availability of such a tool can help promote consistency in the development of GHG emission inventories. SANGEA applies methodologies from the API Compendium to assist in managing GHG emissions data. A modular system, it can be used to estimate energy utilization and GHG emissions from specific oil-and-gas industry sources as well as indirect emissions associated with energy purchases. Users can configure SANGEA for their information needs by entering data about the operational status and equity ownership for each location and by selecting the applicable calculation modules. They can set up the calculation methodologies to suit their needs, can choose from a variety of SI and English units for input and output data, and can use site-specific data or default fuel-composition information and default emission factors based on the API Compendium. Users can document the data sources associated with input values, including automatic confirmation that the necessary input data and documentation fields are complete and error messages if there are gaps that need to be addressed. Configuration information can be transferred from year to year, and modified to keep the inventory up-to-date as process changes occur. Previous global initiatives have developed generic frameworks for GHG emissions accounting and reporting. For example, a global collaboration between the World Resources Institute (WRI) and the World Business Council for Sustainable Development (WBCSD) is spearheading the GHG Protocol effort (4), while the International Standards Organization (ISO) is developing a threepart ISO standard to provide global specifications and guidance for both entities and projects on GHG emissions accounting and verification (5). However, at this time, none provides sufficient detail to estimate GHG emissions from diverse industry sources and operations. CEP September

3 Environmental Management Table 2. Classification of GHG emission sources. Category Examples of Sources Combustion Devices Stationary Sources Boilers, heaters, furnaces, flares, incinerators, thermal/catalytic oxidizers Mobile Sources Barges, ships, railcars and trucks for material transport; planes, helicopters and other company vehicles Indirect Emissions Off-site generation of electricity, hot water and steam for onsite power and heat Vented Sources Process Vents Other Venting Maintenance/ Turnaround n-routine Activities Fugitive Sources Fugitive Emissions Other n-point Sources Reactors, distillation columns, absorbers, strippers, and mixing tanks Storage tanks, gas-driven pneumatic devices, chemical injection pumps, loading racks, loading operations Vessel depressurizing, equipment cleaning, painting Discharges from pressure-relief valves and other emergency-shutdown devices Leaks from valves, flanges, pumps, connectors, compressor seals Wastewater treatment, waste handling operations by the wide variety of emission sources and the nature of the fuels consumed by industry. In many facilities, a very large fraction of the GHG emissions is due to burning hydrocarbon mixtures. Some of these fuels are highly variable in composition and cannot be well characterized by published emission factors. In addition, the quality of information available to characterize emissions and fuels may vary substantially among and within industry sectors. The API Compendium provides guidance on how to characterize these emissions, and the SANGEA system enables users to characterize fuels and estimate emissions in a manner consistent with the guidance. Defining data quality goals The method used to estimate GHG emissions from each source at a facility will depend on the information available about that source and the acceptable degree of uncertainty in the estimates based on the inventory s intended uses. For example, combustion sources generate a large majority of CO 2 emissions, and those can be accurately determined from measurements of fuel use and fuel composition. To estimate CH 4 and non-combustion CO 2 emissions, the use of emission factors and engineering calculations yields acceptable results. Direct measurement can also be used, but is usually Table 3. CO 2 emission estimation techniques for selected refining and petrochemical sources and their approximate accuracy. Tier C (±15 30%) Tier B (<±15%) Tier A (±5 10%) Combustion Sources Thermal input (fuel burned) Thermal input (fuel burned) Thermal input (fuel burned) estimated based on design based on metering* or energy based on metering* or energy rating of plant, hours operated, balances on heaters/boilers, balances on heaters/boilers, and default fuel factors fuel composition obtained from fuel composition obtained from occasional spot sampling frequent spot sampling FCC Coke Burn Thermal input (fuel burned) Coke burn rate calculated based Coke burn rate calculated based estimated based on design on process mass/energy balance on process mass/energy balance rating of plant, hours operated, and average coke composition and average coke composition and default coke factor based on spot samples based on spot samples OR OR Estimated directly from measured Estimated directly from measured CO and CO 2 concentrations in CO and CO 2 concentrations in exhaust (spot samples) and air/oxygen flowrate to regenerator exhaust (more-frequent spot samples) and air/oxygen flowrate to regenerator Flaring Engineering estimates of gas Process engineeng estimates of Flared volume estimated from flareflared using API flame-length flared volume based on known gas meters where available, known correlation and default factor purge rates, process unit flows to purge rates and best process for refinery gas flare and estimates of non-routine engineering estimates, average flareflaring based on plant logs; gas composition based on spot weighted average flare-gas samples throughout the year composition based on estimated (adjusted if non-routine flaring composition is significant) Hydrogen Plant Process mass balance based on Simple method outlined in API Complex method outlined in API (Process) estimated hydrogen production Compendium based on estimated Compendium i.e., process mass hydrogen production balance based on known reformer feed rate and composition *Metering may be performed at fuel headers rather than at individual combustion sources September 2005 CEP

4 costly and often yields little improvement in accuracy. The API Compendium describes methods for estimating GHG emissions, and the industry guidelines recommend how they should be applied to achieve various accuracy levels for different types of facilities. Where multiple approaches exist for estimating emissions, the methods can be grouped into three tiers, with Tier A providing the most accurate estimate, Tier B an intermediate level of accuracy, and Tier C the most general estimates. Table 3 illustrates the tiered approach to estimating CO 2 emissions from petroleum refinery and petrochemical plant sources. These uncertainty ranges are not meant to apply to individual sources. Rather, they are estimates of the uncertainty in the total emissions from a facility that would result from applying the set of estimation methods in a particular tier. Further details on the recommended approaches for each reporting tier and specific quantification methods can be found in Appendix B of the industry guidelines (1). The API Compendium does not require the use of specific techniques for estimating GHG emissions. However, it does suggest preferred and alternative approaches, and provides decision trees to help in selecting an estimation technique based on data availability and data quality goals. Estimating emissions from combustion Figure 1 is a decision tree for estimating CO 2 emissions from stationary combustion sources. The preferred approach involves measuring the fuel consumption rate (in terms of mass or volume) and the fuel composition, and then calculating CO 2 emissions based on fuel usage and carbon content. The basis of the fuel heating value ( gross, or high heating value [HHV], vs. net, or low heating value [LHV]) should be specified and used consistently to improve estimation accuracy. Table 4 provides recommended emission factors for common fuels. These emission factors are based on the conservative assumption that all the carbon in the fuel is converted to CO 2. Alternatively, a correction factor based on the fraction of carbon oxidized may be applied. (A more-extensive listing of fuel properties and emission factors for these and other fuels is available in Tables 3-5 and 4-1 of the API Compendium (6).) If such data are not available, manufacturer-supplied data, results of device-specific testing, or published emission factors may be used. For estimating CO 2 emissions, emission factors stated in terms of metric tons per quantity of fuel consumed or metric tons per energy consumption of a given fuel are generally more accurate than equipment-based emission factors. In most cases, the CH 4 emissions from combustion devices will be negligible. However, if they must be computed, the preferred approach is to use published emission factors that incorporate a default fuel composition and CH 4 destruction efficiency based on the equipment type (6). Preferred Approach Total volumes of fuels (by type) combusted Alternative Approaches (based on available information) Equipment manufacturer or test data available, using similar-quality fuel Equipment power output data and operating hours Is the fuelʼs composition known? Is the fuelʼs Higher Heating Value (HHV) known? Determine or estimate heating value and use emission factors in Table 4 to calculate emissions Substitute manufacturer- or test-specific data for emission factor Estimating emissions from process vents Vented emissions are releases to the atmosphere as a result of the process or equipment design or operational practices. They may be released through a variety of nonfired stacks and vents, and may be referred to as cold vents because of the absence of combustion. These emission sources tend to be very specific to the type of operation. Due to the wide variability of sources, there are no general emission factors or default values for estimating CO 2 and CH 4 emissions. Emission estimation requires a thorough knowledge of the process being evaluated, and in general involves mass balance or process simulation techniques that are based on measurements or estimates of process parameters such as the venting rate and concentrations. Estimating fugitive emissions Fugitive emissions include equipment leaks from valves, flanges, pump seals, compressor seals, relief valves, sampling connections, process drains, open-ended lines, and other components, as well as evaporative emissions from non-point sources such as wastewater treatment plants and impoundments. Numerous documents outline the estimation of fugitive emissions, some of which include CH 4. Data on fugitive equipment leaks of CO 2, however, are not generally presented, since CO 2 emissions are more commonly associated with combustion sources. It may be possible to adapt the estima- Calculate emissions based on fuel consumption and carbon content Use emission factors in Table 4 to calculate emissions Convert from power output basis to energy input basis Figure 1. Decision tree provides guidance for calculating CO 2 emissions from stationary combustion sources based on information availability. Source: (6) [Figure 4-1]. CEP September

5 Environmental Management Table 4. CO 2 emission factors (fuel basis HHV a ) for the combustion of common fuels. Emission Emission Fraction Factor, Factor, of Carbon Carbon Fuel m.t./10 6 Btu m.t./10 12 J Oxidized b Content, wt% Aviation Gas Crude Oil d Diesel/Gas Oil Distillate Fuel #1: 86.6 e #2: 87.3 e Electric Utility Coal e Flexicoker Low-Btu Gas Fuel Oil # e Jet Fuel Kerosene Liquefied Petroleum Gas (LPG) Motor Gasoline e Natural Gas Liquids Natural Gas wt% C e (Pipeline) c (92.5 wt% CH 4 ) Natural Gas (Flared) Petroleum Coke e Refinery Fuel Gas Residual Oil # e a CO 2 emission factors shown are based on the default assumption of 100% oxidation. To convert between emission factors based on higher and lower heating values, the assumed conversion for gaseous fuels is (EF HHV ) = (0.9) (EF LHV ), and for solid or liquid fuels is (EF HHV ) = (0.95) (EF LHV ). b The fraction of carbon fuel oxidized should be applied to the CO 2 emission factors. The API Compendium recommends using 100% fractional conversion for conservatism; however, companies may choose to apply the oxidation fractions above. Source: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 2001, DOE/EIA-0573(2001), December c Natural gas carbon coefficient is based on a weighted U.S. national average. d Baumeister, T., et al., Marks Standard Handbook for Mechanical Engineers, 8th ed., Section 7, Table 9, McGraw-Hill Book Co., New York, NY (1978). e rth American Combustion Handbook, Volume I: Combustion Fuels, Stoichiometry, Heat Transfer, Fluid Flow, 3rd ed., rth American Manufacturing, Cleveland, OH, (1986). Source: (6) [Table 4-1]. tion methods for CH 4 to operations where CO 2 equipment leaks might be of significance. Emission factors and correlation equations have been developed for estimating fugitive equipment-leak emissions. However, many of these require monitoring data and calculations at the component level. For most GHG equipment leaks, two simpler approaches are recommended: facility-level average emission factors equipment-level average emission factors. In most cases, the facility-level approach provides adequate estimates of fugitive GHG emissions. The user simply needs to know the type of facility and its throughput. The equipment-level approach allows the emissions estimate to be tailored to a particular facility based on the population of major equipment at the site. It requires more information, but results in a slightly more-accurate emissions estimate than the facility-level approach. It is especially useful for estimating GHG emissions for a planned facility. Figure 2 shows how to determine the level of detail required for fugitive emissions estimation based on the likely significance of fugitive equipment leaks as well as the availability of information from a leak detection and repair (LDAR) program. The choice of method will depend on the contribution of fugitive emissions to the overall GHG inventory. The preferred approach is to use the simplest method that meets the inventory accuracy needs and for which data are available. Table 5 presents facility-level and equipmentlevel emission factors for some oil-and-gas industry facilities that may also be relevant in the chemical process industries. (Additional emission factors for specific operations and equipment can be found in the API Compendium (6) and its references.) Creating emissions summaries In totaling facility emissions, the relative significance of each GHG compound can be assessed by its overall mass emissions or by its global warming potential (GWP) weighted value, as recommended by the Intergovernmental Panel on Climate Change (IPCC) (7). GWPs provide a convenient means of aggregating the combined effect of multiple greenhouse gases. netheless, it is important to keep track of the actual mass emissions of all the compounds emitted, in addition to the weighted sum. The inventory should note the GWP value used in the aggregation and allow for revisions to the total emission estimate should the IPCC adopt revised GWPs. GHG emission estimates based on GWP are often expressed in terms of CO 2 Equivalents or Carbon Equivalents. Although any units of mass may be used to convert GHG emissions to these equivalent bases, the most widely recognized units are metric tons and million metric tons (MMT). The conversion equations are: CO Equivalents, m.t. = 2 MMTCE = CO 2 Equivalents, m.t. MWCarbon MMT 6 MW 10 m.t.. of GHG Species ( MTi GWPi) () 1 i=1 ( 2) CO2 where MMTCE = million m.t. of carbon equivalent and MW = molecular weight (MW Carbon = 12; MW CO2 = 44) September 2005 CEP

6 Preferred Approach Is Leak Detection and Repair (LDAR) implemented at the facility? Alternative Approaches (based on the overall importance of the fugitive emissions to the facilityʼs inventory) Estimate emissions using the facility-wide approach Are the resulting emissions an important contributor to the facilityʼs overall emissions? Are the emission results for use in evaluating project-level emission results? OR Is there a requirement to use more-detailed estimation methods? Sample facility emission inventories Industrial operations and equipment vary significantly, depending on performance requirements and site-specific considerations. In general, GHG emissions will be determined by: intensity of energy usage degree of internal capture and reprocessing installation of end-of-pipe controls venting practices. The following two hypothetical examples (6) illustrate the type of emission estimates that can be obtained. Natural-gas processing plant. A natural-gas processing plant has a throughput of 800 million std. ft 3 of raw gas (70% CH 4, 3.5% CO 2,), and the finished product contains >90% CH 4 and <2% CO 2. The facility does not import any electricity. Table 6 lists the significant combustion and vented sources, and their CO 2 and CH 4 emissions are depicted in Figure 3. Refinery. A refinery has a capacity of 250,000 bbl/d of crude, and its onsite hydrogen plant has a capacity of 29 million std. ft 3 /d. Its combustion sources are fired with either refinery fuel gas or natural gas, and it imports 76,000 MW-h of electricity per year. CO 2 and CH 4 emissions are shown in Table 7 and Figure 4. Apply one of the component-level approaches in Appendix B of the API Compendium Use the facility-level emission estimate Estimate emissions using the equipmentlevel approach Figure 2. Decision tree provides guidance for selecting the level of detail needed for estimating fugitive emissions. Source: (6) [Figure 6-1]. Article continues on p. 36 Source Table 5. Facility-level and equipment-level average fugitive emission factors. Facility-Level Factors Gas processing plants Gas storage stations Gas transmission pipelines (leaks) Gas distribution pipelines (leaks) Refining c Emission Factor a 2.918E 02 m.t. CH 4 /10 6 scf 1.030E+00 m.t. CH 4 /10 6 m E+02 m.t. CH 4 /station 3.594E+00 m.t. CH 4 /mile-yr 2.233E+00 m.t. CH 4 /km-yr 2.117E 01 m.t. CO 2 /mile-yr 1.315E 01 m.t. CO 2 /km-yr CO 2 from oxidation of CH b 4 : 3.443E 03 m.t. CO 2 /mile-yr 2.139E 03 m.t. CO 2 /km-yr 1.611E+00 m.t. CH 4 /mile-yr 1.001E+00 m.t. CH 4 /km-yr 1.069E 01 m.t. CO 2 /mile-yr 6.640E 02 m.t. CO 2 /km-yr CO 2 from oxidation of CH b 4 : 5.611E 01 m.t. CO 2 /mile-yr 3.486E 01 m.t. CO 2 /km-yr 8.43E 05 m.t. THC/bbl feedstock 5.30E 04 m.t. THC/m 3 feedstock Equipment-Level Factors Gas processing plant compressors Reciprocating 8.95E 03 m.t. CH 4 /compressor-h Centrifugal 1.70E 02 m.t. CH 4 /compressor-h a The CH 4 emission factors can be adjusted based on the relative concentrations of CH 4 and CO 2 to estimate CO 2 emissions. b A portion of CH 4 emitted from underground pipeline leaks is oxidized to form CO 2. c Source: European Environment Agency (EEA), Joint EMEP/CORINAIR Atmospheric Emission Inventory Guidebook, Third Edition, EEA, Copenhagen, 2001, updated October Source: (6) [Table 6-1] Literature Cited 1. International Petroleum Industry Environmental Conservation Association (IPIECA), International Association of Oil and Gas Producers (OGP), and American Petroleum Institute (API), Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions, IPIECA, London, U.K., available at (Dec. 2003). 2. American Petroleum Institute, Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, Pilot Test Version, API, Washington, DC (2001). 3. rdrum, S., and A. Lee, Experience with a Corporate-Wide Energy and Greenhouse Gas Reporting System, presented at U.S. Dept. of Energy Second Annual Conference on Carbon Sequestration, Arlington, VA (May 5 8, 2003). 4. World Resources Institute (WRI) and World Business Council for Sustainable Development (WBCSD), The Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard, WRI and WBCSD, Washington, DC (Jan. 2004). 5. International Organization for Standardization, ISO 14064, Parts 1, 2, and 3: Specifications and Guidance for Estimating, Reporting and Verification of Greenhouse Gas Emissions from Entities and Projects, Draft International Standard, ISO, Geneva, Switzerland (Jan. 2005). 6. American Petroleum Institute, Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, API, Washington, DC, available at (Feb. 2004). 7. Intergovernmental Panel on Climate Change, IPCC Third Assessment Report: Climate Change 2001; Synthesis Report, A Contribution of Working Groups I, II and III to the Third Assessment Report of the Intergovernmental Panel on Climate Change, Watson, R. T., et al., eds., Cambridge University Press, Cambridge, U.K., and New York, NY, available at (2001). CEP September

7 Environmental Management Table 6. Combustion and vented sources for the natural-gas processing plant example. Activity Emissions, mt/yr Factor (total) CO 2 CH 4 Combustion Sources Auxiliary boilers* Btu/yr 122, Hot oil heaters* Btu/yr 71, Gas turbines for recompression* Btu/yr 168, Gas turbines for 213,559 MW-h/yr electricity generation* output 92, Emergency flare (acid gas, low pressure) scf/yr 5, Emergency flare (acid gas, high pressure) scf/yr 17, Vented Sources Dehydration vents (includes pump scf/yr emissions) gas processed 230 1,676 Gas processing Inlet: scf/yr and sour gas (3.5 mole% CO 2 ) treating Outlet: scf/yr (2.0 mole% CO 2 ) 298,908 1,400 Processing maintenance blowdowns 1 processing plant 1,030 *Natural-gas fired CO 2 Equivalents, m.t./yr 600, , , , , ,000 Carbon Dioxide Methane Nitrous Oxide 0 Combustion Vented Fugitive Indirect Emission Source Category Figure 3. Emissions summary for the natural gas plant example. CO 2 Equivalents, m.t./yr 3,000,000 2,500,000 2,000,000 1,500,000 1,000, ,000 Carbon Dioxide Methane Nitrous Oxide 0 Combustion Vented Fugitive Indirect Emission Source Category Figure 4. Emissions summary for the refinery example. Table 7. Emission sources for the refinery example. Activity Emissions, mt/yr Factor (total) CO 2 CH 4 Combustion Sources Power (steam) boilers Btu/yr 1,159, Process heaters Btu/yr 1,130, FCCU CO boiler Btu/yr 78, Internal-combustion engines* Btu/yr 35, Gas turbines* Btu/yr 377, Flaring, including maintenance and turnaround activities Btu/yr 153, Incinerators (sulfur recovery unit, tail gas treatment unit) Btu/yr 19, Vented and Other Direct Sources Hydrogen plant natural gas feed scf/yr 366,760 0 Hydrogen plant refinery fuel-gas feed scf/yr 231,641 Hydrogen plant butane feed scf/yr 7,308,776 FCCU regenerator Btu/yr coke consumed (coke contains ~91 wt% carbon) 1,972,547 Crude tanks bbl/yr 0 Fugitive emissions 0 0 Indirect Sources Imported electricity W-h/yr 32, *Natural-gas fired Refinery-fuel-gas-fired Final thoughts The estimation guidance and methodologies presented here the industry guidelines (1), the API Compendium (6), and the optional SANGEA data-management system constitute a credible and systematic means of developing GHG emission inventories as a prelude to addressing the climate change issue. By working toward a consistent approach for GHG emissions estimating, the foundation is laid for future cooperative efforts among companies and regulators to address this important issue. The oil-and-gas industry plans to continue the development and dissemination of these tools broadly, worldwide, and to provide workshops and training in the use of the methodologies. It will also continue to collaborate with governmental and intergovernmental organizations on further refinement and updates of this guidance as new technical information becomes available. CEP 36 September 2005 CEP

8 KARIN RITTER is a regulatory analyst with the American Petroleum Institute (1220 L Street NW, Washington, DC ; Phone: (202) ; Fax: (202) ; ritterk@api.org), where she manages API's stationary source emissions and air toxics programs. She directs numerous projects aimed at increasing the understanding of air emissions, including greenhouse gas emissions, from petroleum industry sources, and also leads API's air toxics regulatory response to government initiatives. She currently represents API on an international industry-wide effort to develop common reporting guidelines for greenhouse gas emission reduction projects. She holds a BS in urban and regional planning from McMaster Univ., Hamilton, Ontario, Canada. SUSANN NORDRUM, a staff engineer at Chevron Energy Technology Co. (100 Chevron Way, P.O. Box 1627 Richmond, CA ; Phone: (510) ; Fax: (510) ; sbnordrum@chevron.com), is Chevron's focal point for greenhouse gas emissions inventory issues, and a recognized industry expert in the field. She managed the project development and implemention of the SANGEA system, API's publicly available energy and greenhouse gas emissions estimating software. She currently chairs the API Greenhouse Gas Emissions Estimating Work Group, and the API SANGEA Users Group. She is also a lead author of the IPCC 2006 Guidelines for Inventory Development and is the co-chair of an industry-wide effort to develop common reporting guidelines for projects. She also created and implemented a process to incorporate environmental issues into Chevron's capital projects during the early design stages. She holds a bachelor s degree in chemical engineering from Michigan Technological Univ. THERESA SHIRES is a senior engineer and project manager with URS Corp. (9400 Amberglen Blvd., Austin, TX 78729; Phone: (512) ; Fax: (512) ; Terri_Shires@URSCorp.com). Her areas of expertise relate to greenhouse gas emissions invetory and protocol development, emissions verification, emission reduction strategies, and risk management decision support. She has worked as the lead technical consultant to the API Greenhouse Gas Emissions Estimating Workgroup, recently revising the Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry. She is currently supporting API in promoting worldwide, industry consensus on greenhouse gas emission estimation methods and developing common reporting guidelines for emission reduction projects. She holds a BS in chemical engineering from Texas A&M Univ. MIRIAM LEV-ON is executive director and co-founder of The LEVON Group, LLC (236 Marjorie Ave., Thousand Oaks, CA 91320; Phone: (805) ; Fax: (805) ; miriam@levongroup.net), an environmental consultancy and facilitation company that provides worldwide services in the areas of greenhouse gas emissions and climate change strategies. She helped establish and chaired the API GHG Emissions Working Group, leading the development of the API Compendium in 2001, and initiating the process toward harmonizing of GHG reporting methodologies for the oiland-gas industry. She is an expert reviewer of the 2006 IPCC national GHG guidelines, and a contributor to the WRI GHG Protocol, the ISO international standard and the DOE registry for voluntary reporting of GHG emissions. She holds a dual BS degree in chemistry and physics from the Hebrew Univ. of Jerusalem, and an MA and PhD in physical chemisty from the Univ. of California at Santa Barbara. CEP September