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GUIDE

Calculating Greenhouse Gas EmissionsApril 2003

2003-0003

The Canadian Association of Petroleum Producers (CAPP) represents 140 companies that explore for, develop and produce natural gas, natural gas liquids, crude oil, oil sands, and elemental sulphur throughout Canada. CAPP member companies produce more than 97 per cent of Canadas natural gas and crude oil. CAPP also has 125 associate members that provide a wide range of services that support the upstream crude oil and natural gas industry. Together, these members and associate members are an important part of a $65-billion-a-year national industry that affects the livelihoods of more than half a million Canadians.

Review by March 2004 Replaces CAPP Pub #2000-0004 Global Climate Change, Voluntary Challenge Guide Docs # 55904

Disclaimer This guide was prepared by the Canadian Association of Petroleum Producers (CAPP) and Tom Michelussi, Altus Environmental Engineering Ltd. While it is believed that the information contained herein is reliable under the conditions and subject to the limitations set out, CAPP does not guarantee its accuracy. The use of this guide and any information contained will be at the users sole risk, regardless of any fault or negligence of CAPP and Altus Environmental Engineering Ltd.

2100, 350 7th Ave. S.W. Calgary, Alberta Canada T2P 3N9 Tel (403) 267-1100 Fax (403) 261-4622

230, 1801 Hollis Street Halifax, Nova Scotia Canada B3J 3N4 Tel (902) 420-9084 Fax (902) 491-2980

905, 235 Water Street St. Johns, Newfoundland Canada A1C 1B6 Tel (709) 724-4200 Fax (709) 724-4225

Email: [email protected] Website: www.capp.ca

Overview This guide follows the fifth version of the CAPP Global Climate Change Voluntary Challenge Guide and signifies a shift towards a more streamlined document. This guide, Calculating Greenhouse Gas Emissions, provides CAPP members with a standardising approach to benchmarking and estimating greenhouse gas emissions. Establishing a comprehensive corporate greenhouse gas inventory is the first step in developing a Greenhouse Gas Strategy and an Action Plan for submission to the VCR. In the six years that CAPP has been providing guidance, the Voluntary Challenge and Registry has continued to mature. The Voluntary Challenge and Registry was privatized in 1998, a president and Council of Champions were appointed and staff hired. The role of the new organization (called VCR, Inc.) is to provide a more rigorous framework for companies to follow in preparing their Action Plans. The components identified in this Guide will allow CAPP member companies to better understand the information that needs to be provided that will result in the Action Plan being seen as a high-quality, comprehensive document, yet provide the flexibility to establish a company-specific report. With each version, the focus of the CAPP Guide has changed. The first two versions were primarily developed to simplify preparation of a Climate Change Action Plan, thereby encouraging more CAPP member companies to participate in the Voluntary Challenge and Registry (VCR). The third and fourth versions, issued in April 1997 and June 1999, were the first attempts to provide a detailed format that would allow companies to use either a detailed or a short form method to calculate emissions. The fifth version provided specific information on emissions from various process equipment. CAPP's Environment, Health and Safety Stewardship initiative is defined as a responsible approach to business that lets companies succeed while preserving the environment and enhancing quality of life. This is more important all the time, as industrial activity now crosses borders, affects economies, and influences culture as never before. By working closer with society and governments to address issues that concern us all, private enterprise can make our common world a better place. Established as a voluntary program in 1999, Stewardship became mandatory this year. The reporting criteria for the Stewardship benchmarking data on greenhouse gas emissions are based on the VCR reporting criteria.

CAPP acknowledges the considerable assistance of Altus Environmental Engineering Ltd. in the development of this document.

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Table of ContentsOverview ....................................................................................................................................i 1 CAPP Guide to Baselines and Calculating Greenhouse Gas Emissions .............. 1-1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 Introduction.................................................................................................. 1-1 Establishing a Base Year............................................................................. 1-3 Emissions from Non-operated Facilities .................................................... 1-3 Baseline Adjustment.................................................................................... 1-4 Global Warming Potential Factors ............................................................. 1-5 Short-Form Emissions Calculation Method............................................... 1-6 Detailed Emissions Calculation Method.................................................... 1-8 1.7.1 Boilers and Heaters ......................................................................... 1-9 1.7.2 Natural Gas Fired Drivers............................................................. 1-13 1.7.3 Flaring of Natural Gas .................................................................. 1-16 1.7.4 Electric Power Generation Emission Factors.............................. 1-17 1.7.5 Methane Emissions from Fugitive Losses................................... 1-18 1.7.6 Methane Emissions from Instrumentation Venting .................... 1-20 1.7.7 Methane Losses from Glycol Dehydrators.................................. 1-22 1.7.8 Methane Emissions from Oil Batteries ........................................ 1-23 1.7.9 Methane Emissions from Plant Tank Venting ............................ 1-25 1.7.10 Methane Losses from Non-Routine Venting............................... 1-26 1.7.11 CO2 Venting from Sour Gas Processing Facilities ..................... 1-26 Fugitive Emission Estimates Derived from the GFC Method................ 1-27 Emissions from Cogeneration Systems.................................................... 1-33 Emissions from Off-shore Operations...................................................... 1-35 Conversion Factors.................................................................................... 1-37 Introduction.................................................................................................. 2-1 Reporting Basis............................................................................................ 2-3 Calculating the Product Energy Intensity (PEI) ........................................ 2-5 Calculating the Product Carbon Intensity (PCI) ........................................ 2-6 Introduction.................................................................................................. 3-1 Reporting Success Stories ........................................................................... 3-1 Sample Calculations .................................................................................... 3-1

1.8 1.9 1.10 1.11 2 2.1 2.2 2.3 2.4 3 3.1 3.2 3.3

Benchmarking........................................................................................................... 2-1

How to Build a Success Story ................................................................................. 3-1

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TablesTable 1-1: Potential Sources of GHG Emissions from Upstream Operations...............................1-2 Table 1-2: Global Warming Potential (GWP) Factors ....................................................................1-5 Table 1-3: Emission Factors for Boilers, Heaters and Furnaces Based on Fuel Usage ................1-9 Table 1-4: Emission Levels Provided by Boiler Manufacturers.................................................. 1-10 Table 1-5: Energy Content of Fuels .............................................................................................. 1-11 Table 1-6: Emission Factors for Natural Gas and Diesel Drivers based on Fuel Usage............ 1-13 Table 1-7: Emission Data for Waukesha Reciprocating Engines................................................ 1-14 Table 1-8: Emission Data for CAT Reciprocating Engines......................................................... 1-15 Table 1-9: Emission Factors for Flaring Natural Gas .................................................................. 1-16 Table 1-10: Greenhouse Gas Emissions Associated with Power Generation............................. 1-18 Table 1-11: Fugitive Emissions Factors in Vapour Service ........................................................ 1-19 Table 1-12: Gas Consumption Rates (in m3/hr) for Standard (high bleed) Pneumatic Instruments ................................................................................................................................................. 1-20 Table 1-13: Average Methane Emission Factors for Dehydration.............................................. 1-22 Table 1-14: Factors Used to Estimate Gas Venting and Flaring Rates ....................................... 1-23 Table 1-15: Generic or Average Connector Counts by Equipment/Process Type..................... 1-29 Table 1-16: Generic or Average Valve Counts by Equipment/Process Type ............................ 1-30 Table 1-17: Generic or Average Open-ended Line Counts by Equipment/Process Type ......... 1-31 Table 1-18: Generic or Average Compressor Seal Counts by Equipment/Process Type.......... 1-31 Table 1-19: Generic or Average PRV Counts by Equipment/Process Type .............................. 1-32 Table 1-20: Fuel Emission Factors (for mobile sources) ............................................................. 1-36 Table 2-1: Upstream Oil and Gas Production and Energy Use in 1998 and 1999 ........................2-2 Table 2-2: Oil Equivalent (OE) Conversion Factors (on an energy equivalent basis)..................2-4 Table 2-3: Upstream Oil and Gas Industry Average PEI Values (1995 values) ...........................2-5 Table 3-1: Checklist...........................................................................................................................3-3

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1

CAPP Guide to Baselines and Calculating Greenhouse Gas Emissions 1.1 Introduction This guide has been developed to assist CAPP member companies in standardising their approach for estimating greenhouse gas (GHG) emissions from combustion, fugitive, process venting and indirect sources. To validate our industrys commitment to the Voluntary Challenge program, it is important that CAPP member companies establish the amount of GHG produced at their operated facilities. To assist in this task, three standardised calculation methods to determine GHG emissions are explained in this guide: 1) Short-form Emissions Calculation Method - This simplified method will enable companies to determine combustion and fugitive emissions on a company or facility basis with a minimum amount of effort. 2) Detailed Emissions Calculation Method - This utilises specific equipment emissions factors to determine combustion and fugitive emissions on a facility and equipment/process basis. 3) Generic Fitting Count (GFC) Fugitive Emissions Calculation Method This method uses an average or generic fitting count per equipment process to determine the total number of fittings that will be used for fugitive emission calculations. The possible sources for greenhouse gas emissions from upstream petroleum operations include: combustion of natural gas, propane, and diesel; process venting of methane; fugitive emissions of methane; process venting of CO2 and indirect emissions from the purchase of electricity generated from fossil fuel combustion. Table 1-1 on the following page lists potential sources of greenhouse gas emissions from the different stages of upstream oil and gas production and processing.

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Table 1-1: Potential Sources of GHG Emissions from Upstream OperationsSource Gas venting from petroleum storage (tanks) Casing gas venting Fugitive emissions (equipment & piping) Fugitive emissions (equipment & piping) Gas instrument and injection pump venting Engine gas starter venting Glycol dehydrator reboiler venting Glycol dehydrator stripping gas venting Venting of CO2 from gas sweetening Combustion: boilers and heaters Combustion: engines and turbines Combustion: flaring and incineration Maintenance: piping/equipment blowdown Operations: well blowdown, equipment failure Indirect emissions: electricity purchase GHG CH4 CH4 CH4 CO2 CH4 CH4 CH4 CH4 CO2 CO2, CH4, N2O CO2, CH4, N2O CO2, CH4, N2O CH4 CH4 X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X Oil Battery X X X X X X X X Gas Well GGS Sweet GP Sour GP

CO2, CH4, N2O

X

X

X

X

X

GGS is a gas gathering system; Sweet GP is a sweet gas plant; Sour GP is sour gas plant.

The estimation method used to determine facility or corporate greenhouse gas emissions will depend on the detail of data available and the availability of human resources to complete the work. The level of accuracy of emissions calculated will be dependent on: The calculation methodology used (short form or detailed method). The accuracy of input energy data (fuel gas volume, flare volume, power consumption). The composition of the fuel gas. The detail of equipment data available (manufacturer, model, utilization). The operating condition of equipment and how representative the manufacturer data is to current conditions.

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Of the three greenhouse gases associated with combustion emissions, the CO2 emission factor is considered to be the most stable or accurate. The amount of CH4 and N2O formed will fluctuate based on combustion chamber properties and condition of equipment. Emission factors associated with determining fugitive or vented losses of methane are considered to be the least accurate. These types of losses are dependent on the condition of plant equipment (due to age/maintenance) and the operating procedures in place (e.g., is venting avoided in daily operations). The use of the attached emission factors for fugitive and venting losses can be in error by as much as 50percent compared to undertaking on-site methane loss surveys using gas detection equipment. Once greenhouse gas emissions are established, the Production Carbon Intensity (PCI) may be determined on a company or facility basis. CAPP member companies have agreed to use the PEI (Production Energy Intensity) and PCI as standardized GHG performance indicators. If companies prefer to use modified versions of PEI or PCI, these altered performance measures should not be referred to as PEI or PCI (for consistency within the industry). Refer to Section 2, Benchmarking for more information on the PEI and PCI. All facility, production and energy data used in calculations are on a gross operated basis and not on a net Company basis. 1.2 Establishing a Base Year The development of a companys baseline greenhouse gas emissions is essential to the determination of subsequent reductions in overall emissions and future progress. According to the Voluntary Challenge and Registry (VCR) Registration Guide (May 1999), baselines should, where possible, be based on 1990 data, as this is the internationally recognized benchmark. To obtain a copy of this guide, contact the VCR office at: phone (613)565-5151; fax (613)565-5743; or e-mail: [email protected] However, when data is unavailable, it is acceptable to use the earliest year after 1990 for which data is available. Companies using a base year other than 1990 should explain the rationale for doing so. 1.3 Emissions from Non-operated Facilities This Guide was written to address calculation methodologies for companyoperated facilities on a gross production basis. The reasoning for this is: April 2003

The operator has the best access to all the necessary input data. Data is more easily verified. The operator is responsible for the management, operation and the efficiency of the facility. Double counting of emissions and success stories is eliminated.Estimating Greenhouse Gas Emissions

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The true efficiency of the facility (on an energy and emission basis) can be determined by calculating PEI and PCI. Regulatory and emissions trading schemes focus on control rather than ownership.

Some companies have voiced interest in determining their GHG emissions based on production ownership/allocation at a given production or processing site. This is a complicated process. In order to accomplish this, the operating company would have to determine the GHG emissions at each production (well) and processing (plant) site and then allocate these emissions based on ownership at each site. Equity ownership may change from the well to the processing facility. If companies wish to report their equity ownership based GHG emissions, they may do so separately from their operated (or company controlled) GHG emissions. 1.4 Baseline Adjustment It is recognized that the ownership of wells, gathering systems and facilities may change frequently between companies from year to year. In order to reflect a more accurate comparison of year-to-year emission performance, it may be advantageous for some companies to adjust their baseline and other historic emissions. The intent of adjusting baseline emission inventories is to compare current year emissions on a common asset base (provided those assets were in operation during the baseline year). To standardize the adjustment of emissions, the current operator of a facility/asset would be responsible for reporting emissions from that facility/asset from all past years, regardless of which company operated that facility/asset in those years. If a facility is purchased, then past emissions must be added to the total company GHG inventory and if a facility is sold, then past emissions are subtracted from the inventory. If historic GHG data is unavailable for a purchased facility, an estimate of past GHG emissions can still be determined. Historic fuel, flare and production data is available for all major Alberta facilities from Alberta Energy and Utilities Board (AEUB) publications such as the ST-13A, while historic electrical usage can be estimated by comparing past and present production levels. Since fugitive emissions are largely independent of production volumes (provided plant processes remain unchanged), current fugitive emission estimates for a given facility may be used for previous years. Depending on whether vapour recovery schemes have been implemented currently, historic venting volumes may be significantly higher. All assumptions and calculation methodologies should be recorded for reference and/or verification purposes. If a company shuts down a facility (and does not sell that facility), then that company reports emissions from that facility for all the years that facility was in operation. Baseline adjustment is usually done when major assets such as gas plants or large oil processing facilities change ownership/operatorship. TheApril 2003 Estimating Greenhouse Gas Emissions

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benefits of undertaking adjustments at a well level are normally negligible unless a large change is made. The above explanation of baseline adjustment is consistent with the World Business Council for Sustainable Development (WBCSD) Greenhouse Gas Protocol. This procedure is optional and not required by the VCR for submission of an Action Plan. It is left up to the company, whether baseline adjustment will be used. If baseline emissions are adjusted, they must be identified as such. A description of the baseline adjustment procedure should also be provided in the companys VCR Action Plan. 1.5 Global Warming Potential Factors Global Warming Potential (GWP) factors are used to convert non-CO2 GHG to an equivalent CO2 mass (termed CO2E). These factors take into account the relative impact of different GHGs on the atmosphere and the differing lengths of time they reside in the atmosphere. The following table (1-2) lists GWP factors as shown in Canadas National Action Program on Climate Change, 1995, page 6.Table 1-2: Global Warming Potential (GWP) Factors Gas CO2 CH4 (methane) N2O (nitrous oxide) Hydrofluorocarbons: HFC-23 Hydrofluorocarbons: HFC-125 Hydrofluorocarbons: HFC-134a Hydrofluorocarbons: HFC-152a PFCs: Tetrafluoromethane (CF4) PFCs: Hexafluoromethane (C2F6) Sulphur Hexafluoride: SF6 100 year GWP 1 21.0 310 11700 2800 1300 140 6500 9200 23900

Since HFCs are used as refrigerants, while PFCs and SF6 are used as manufacturing aids in the metal and semi-conductor industry, the greenhouse gases of concern to upstream petroleum industry are CO2, CH4 and N2O. The major sources of these greenhouse gas emissions are the combustion of fossil fuels and fugitive losses.April 2003 Estimating Greenhouse Gas Emissions

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In equation form, the conversion to carbon dioxide equivalent mass is: Equation 1 CO2E (tonnes) = CO2 tonnes x 1.0 + CH4 tonnes x 21 + N2O tonnes x 310 In order to improve reporting consistency, total emission reductions should be reported in terms of CO2E tonnes. As the GWPs may be revised from time to time, it is recommended that methane and N2O emissions be reported separately to permit simple recalculation of CO2E in the event of a change in GWP values. VOCs and NOX are not direct greenhouse gases. These gases react/breakdown in the atmosphere to form ozone which is a direct GHG. As VOCs and NOx are not included in the national GHG emissions inventory, their respective GWP factors have not been included in Table 1-2. Example 1: Determining CO2E emissions Determine the CO2E emissions from venting 3 tonnes of CO2 from gas sweetening plus 2 tonnes of methane. Using Equation 1, we get 3 + (2 x 21.0) = 45 tonnes of CO2E to the atmosphere in terms of GHG effect. To simplify calculations, CO2E combustion emissions factors (which include CO2, N2O and methane emissions) are also included throughout this guide. 1.6 Short-Form Emissions Calculation Method This simplified method may be used to determine greenhouse gas emissions on a company or facility basis with minimum effort. The data that must be collected includes: A complete list of company operated facilities; Type and annual volume of fuel combusted; Type and annual volume of products marketed (gross sales volumes); Amount of electricity purchased from utilities in each province of operation; Annual volume of flare gas burned; and Annual amount of CO2 vented from gas sweetening operations.

These are required for company-operated facilities only and are based on gross facility throughput not on a net basis. Product sales and fuel data can be obtained from the AEUB (Alberta Energy and Utilities Board) reported data as found on the S-20 (plant data), S-2 (well production data) and S-8 (gas gathering data) forms. The Alberta-based forms are available on the EUB website. Similar forms are used in other provinces. Electrical usage in MWhr/year may be obtained from utility invoices or from the utility directly.April 2003 Estimating Greenhouse Gas Emissions

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Care should be taken not to double count product sales volumes in determining total corporate product sales. That is, if a company operates a processing facility such as a gas plant along with the associated well and field gathering system, then the fuel and flare consumption at all three sites must be included, but the product sales should only be counted at the end point or gas plant (provided all dispositions from the well and gathering system end up at the gas plant). If a company only operates the well and gathering system, then again all fuel and flare data must be included, but only the product sales at the end point (or gas gathering system) should be included. In general terms, the operating company must include fuel and flare volumes from all operated facilities, but should only include product sales from the end point facility. By ensuring that double counting of product sales is avoided, the overall corporate PEI and PCI are determined in a consistent method throughout the industry. Facility product gas sales volumes should not include flare volumes or fuel gas volumes used on-site. Gas shrinkage and metering differences should also be omitted from the product sales volumes. Since the Short-Form fugitive emission factors are production based, using this method will not capture any site specific reductions made to reduce methane releases. Users should also be aware that the simplified Short-Form method could result in higher emissions since factors used are typical industry values. If a given facility produces more than one product, then the fugitive emission factor for the highest volume product should be used to determine the fugitive emissions for that facility. For example, only the Short-Form fugitive emission factor for oil would be used at an oil processing facility even though natural gas was also conserved and sold at the same facility. Short-Form production-based fugitive emission factors take into account losses from pipe fittings, gas operated field instrumentation, and solution gas venting. The Short-Form combustion emission factor of 2.03 tonnes CO2E/103m3 fuel combusted is a combined factor that assumes 50 percent of the fuel is burned in boilers/heaters, 30 percent is burned in reciprocating engines, 19 percent is burned in gas turbines, and 1 percent is burned in flares. To determine a specific combustion factor that better reflects your companys operations, refer to note n) in Form GHG-SF which follows this Section. Form GHG - SF should be completed when using the simplified Short-Form method to calculate greenhouse gas emissions inventory. Form GHG - SS should be completed when calculating emission reductions from specific projects.April 2003 Estimating Greenhouse Gas Emissions

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1.7

Detailed Emissions Calculation Method This method may be used to determine GHG emissions from individual plant equipment and processes and is considered more accurate than the Short-Form method as the emissions factors used are specific to equipment type and combustion process. This methodology is also very useful in calculating emission reductions or increases associated with facility additions or process modifications. The following sections outline GHG emissions calculation procedures for various plant equipment and processes. Computer programs that utilize similar emissions factors/methods/references are available from petroleum industry associations such as API (American Petroleum Institute), GRI (Gas Research Institute), government departments (U.S. Environmental Protection Agency or EPA), and various engineering firms specializing in air emissions. It is the users responsibility to determine the validity or appropriateness of any software being considered for use in determining emission quantities. Generic combustion emission factors used in this Guide were taken from EPA AP-42, 1995, 1998 and 2000 edition while typical fugitive emission factors were taken from a recent study completed for CAPP by Clearstone Engineering entitled CH4 and VOC Emissions from the Canadian Upstream Oil and Gas Industry, December 1998. All emissions factors listed in this guide were published by recognized regulatory bodies and technical experts and are considered appropriate for emissions inventory work. Emissions factors derived from specific equipment performance testing or equipment manufacturers are considered to be the most accurate and should be used where available/appropriate. Unless otherwise noted, all combustion emission factors listed in this guide are associated with natural gas combustion. The data necessary to complete the detailed emissions calculation method (DECM) at a facility includes: Power rating of all major combustion equipment (boilers, heaters, engines, turbines); Total annual fuel gas, propane and diesel (metered volumes) combusted, along with the fuel gas composition/analysis; Total annual volume of flare gas burned, along with a composition/analysis of the flare gas; Total annual gross product sales volumes by product type (i.e., light oil, heavy oil, natural gas, ethane, propane, butane, C5+, sulphur, etc.); Total annual electrical power purchased from utility companies; Total number of pipe fittings in gas service (for fugitive emission calculations) obtained from site inspection or Piping and Instrumentation Drawings (PIDs);Estimating Greenhouse Gas Emissions

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Total number of gas operated controllers and instruments (high and low bleed types); Total number of gas compressors, types and number of cylinders (for reciprocating units); Gas processing data to determine methane losses from gas dehydration (using GRI GlyCalc or Hysim); and Inlet raw gas composition showing CO2 concentration, inlet gas total volumes, sales gas CO2 concentration, and sales gas total volume.

Once all the above data is collected, the emission factors listed in the following sections may be used to calculate total greenhouse gas emissions for each facility. Actual (i.e., metered) fuel and electrical consumption data must be used to determine final greenhouse gas emissions from energy use. 1.7.1 Boilers and Heaters When natural gas is burned, the following combustion products are emitted in the flue gas: CO2; CO; NOx; N2O and unburned methane. Of these gases, CO2, N2O and methane are considered to be greenhouse gases. Table 1-3 lists emission factors for boilers, heaters, and furnaces, based on fuel usage. In Table 1-3, the N2O factor of 0.03 g/m3 fuel was taken from EPA AP-42, "Compilation of Air Pollutant Emission Factors", January 1995 (updated March 1998), Table 1.4-2. The EPA-42 emission factors were corrected for a gas net heating value of 37.4 MJ/m3.Table 1-3: Emission Factors for Boilers, Heaters and Furnaces Based on Fuel Usage Heater/Boiler Input Uncontrolled With low NOx burners CO2 g/m3 fuel 1891 N2O g/m3 fuel 0.0347 0.0101 CH4 g/m3 fuel 0.0363 NOx g/m3 fuel 4.413 2.207 CO2E g/m3 fuel 1903 1895

Since the formation of NOx is dependant on combustion conditions such as burner design, combustion temperature and combustion chamber design, the use of specific emission factors for NOx is recommended (where available). Table 1-4 lists model specific emission factors obtained from several manufacturers. The emission factors listed in Table 1-4 refer to new or well-maintained equipment burning clean natural gas. Poorly maintained equipment can be 20 percent less thermally efficient and have much higher emission factors (i.e. up to 30 percent higher in terms of g/kWh).

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As many heaters and boilers are rated in terms of heat output (i.e., GJ/hr.), a fuel heating value is required to determine the amount of fuel used. If site-specific fuel heating values are unavailable, the average values listed in Table 1-5 may be used. Table 1-5 was taken from ERCB 91-A and Environment Canadas Inventory Methods Manual for Estimating Canadian Emissions of Greenhouse Gases, Table 5.4 page 38. All values in Table 1-5 are gross or higher heating values (HHV). A simplified equation for determining boiler emissions is: Equation 2 Emissions = Fuel usage x Emission factor x Utilisation = [Output rating / (Efficiency x HHV of fuel)] x Emission factor x Utilisation Please refer to Example 2 which follows the next table.Table 1-4: Emission Levels Provided by Boiler Manufacturers Manufacturer Cleaver Brooks Model CB CB-LE Thermal Efficiency (HHV) 75 78 % CO2 % CO ppm (g/kWh) 200 (0.232) 200 (0.232) 200 (0.232) 0 50 200 (0.232) 200 (0.226) NOx ppm (g/kWh) 100 (0.186) VOCs ppm (g/kWh) 40 (0.025) PM (g/kWh) (0.015) (0.015)

20 60 40 (.037-.108) (0.025) 100 (0.186) 40 60 100 (0.186) 110 (0.201) 40 (0.025) 40 (0.025)

CBW

(0.015)

FLX 5

(0.015)

IWT

IWT w/ FLR Saskatoon prior to 1995 after 1995 74 77 % 9 > 50 ppm 0 80 ppm

75 78 %

9

59 ppm

All values in Table 1-4 are based on natural gas combustion. For N2O use 0.015 x NOx value. For equipment that does not list a CO2 emission factor, use the CO2 factors found in Table 1-3. April 2003 Estimating Greenhouse Gas Emissions

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Table 1-5: Energy Content of Fuels Fuel Natural gas (per 103 m3) Natural gas, raw/unprocessed (per 103m3) Liquid ethane (per m3) Liquid propane (per m3) Liquid butane (per m3) NGL (natural gas liquids, per m3) Crude oil, light & medium (per m3) Crude oil, heavy (per m3) Crude oil, bitumen (per m3) Aviation gas (per m3) Motor gasoline (per m3) Kerosene (per m3) Diesel fuel (per m3) Energy Content HHV (Gigajoules) 37.4 46.0 18.5 25.4 28.7 27.5 38.5 41.4 42.8 33.5 34.7 37.7 38.7

Taken from ERCB 91-A and Environment Canadas Inventory Methods Manual for Estimating Canadian Emissions of Greenhouse Gases. HHV is higher heating value.

The heating value of unprocessed gas is considered to be greater than that of sweet gas as it may contain quantities of ethane, propane, butane and C5+. Assuming an average composition of 80 percent CH4, 15 percent C2H6 and 5 percent C3H8+, a gross heating value of 46 MJ/m3 is calculated. Given this composition, the amount of CO2 produced for stoichiometric combustion is 1.25 times greater than if methane only was being burned (i.e., 2.33 kg/sm3). This data may be used when calculating emissions for raw gas combustion/flaring; however, companies should use their specific gas compositions to determine flared gas emission factors. To calculate a CO2 emission factor for a specific mixed gas composition such as: aCH4 + bC2H6 + cC3H8 + dC4H10 + eC5H12 + fCO2, where a to f are mole fractions of the natural gas components, the following formula may be used:

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Equation 3 [(a + 2b + 3c + 4d + 5e + f) x 44.01] / 23.64 = kg CO2/sm3 fuel burned where: 44.01 = molecular weight of CO2; and,23.64 = the volume (in m3) occupied by 1 kmole of gas at 15oC and 101.325 kPaa

The above equation assumes complete combustion of hydrocarbon components and therefore should be used for equipment such as boilers, heaters and incinerators. Another important factor in calculating fuel usage is thermal efficiency. The typical efficiency (based on HHV) of boilers/heaters with a rated output of > 375 kW is 80 percent; if < 375 kW use 70 percent (taken from manufacturer data available from Saskatoon Boilers, Cleaver Brooks and Volcano Boilers). Example 2 Determine the CO2E emissions of a natural gas fired boiler rated at 100 MMBtu/hr (output) and which is operated 360 days per year. Solution: Use Equation 2 to solve this problem. Utilisation Output rating = 360 / 365 [days/yr] = 0.986 = 100 x 106 [Btu/hr] x 0.2931 [MW/106 Btu/h] = 29.31 MW Fuel usage = (Output rating x Utilization) / (Efficiency x HHV of fuel) = (29.31 x 0.986) / (0.80 x 37.4) = 0.966 m3/second = 0.966 m3/second x 31.536 x 106 [seconds/yr] = 30.46 x 106 m3/year GHG Emissions = 30.46 x 106 [m3/yr] x 1.903 [kg/m3] = 57.96 x 106 kg/yr = 58 ktonnes CO2E/yrApril 2003 Estimating Greenhouse Gas Emissions

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1.7.2 Natural Gas Fired Drivers The amount of GHG emitted from natural gas fired drivers varies depending on the combustion process involved. Exhaust from a reciprocating engine tends to contain more Nox (N2O), and unburned hydrocarbon (as compared to a turbine driver). Table 1-6 shows emissions factors for both types of drivers for various combustion designs. These factors have been revised and will result in lower emissions than the previous CAPP factors. The CO2, NOx and CH4 emission factors in Table 1-6 were taken from the Compilation of Air Pollutant Emission Factors, EPA AP-42, 5th Edition, January 1995 (updated April and July 2000), Table 3.2-1 and 3.1-2a. A simplified equation for determining turbine or engine emissions is: Equation 4 Emissions = Input fuel volume x Emission factor If fuel volume is not available for each driver, then the engine power rating, utilization and gas heating value may be used to estimate individual fuel volumes. Equation 5 may be used to determine fuel usage in 103 m3. Equation 5Inlet Fuel = (Driver ouput in kW / Efficiency ) x Hours operated x 0.0036 / Fuel HHV in GJ/103 m3

where 0.0036 is the conversion factor for kW to GJ (i.e., 3.6 GJ = 1000 kW)Table 1-6: Emission Factors for Natural Gas and Diesel Drivers based on Fuel Usage Driver Type Reciprocating engine: 2-cycle lean burn 4-cycle lean burn 4-cycle rich burn turbo-charged Gas Turbine Large bore diesel engines (> 600 hp) 1769 1769 1769 1769 2.744 kg/l 0.765* 0.984* 0.533* 0.077* 0.0004 kg/l 23.31 20.09 3.69 0.138 0.00014 kg/l 2496 2496 2012 1796 2.871 kg/l CO2 /m3 gas N2O g/m3 gas CH4 g/m3 gas CO2E g/m3 gas

Taken from EPA AP-42, 1995 and 2000; diesel emission factors were taken from EPA AP-42 Supplement C, 1996. * Estimated to be 1.5 percent of total NOX. April 2003 Estimating Greenhouse Gas Emissions

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Manufacture specific emission factors for reciprocating engines are given in Table 1-7 and Table 1-8. For missing CO2 factors, use factors from Table 1-4.Table 1-7: Emission Data for Waukesha Reciprocating Engines

Model AT25GL AT27GL VHP G, GSI

VHP 3524 GSI VHP 7044 GSI VHP 5794 GSI

VHP GL VGF Model G

VGF Model GSID

VGF GL, GLD 11:1 CRVGF GL 8.7:1 CR

Carburetor Setting Standard Standard Ultra lean Lowest manifold* Equal NOx & CO Catalytic conv. Standard** Equal NOx & CO Catalytic conv. Standard** Equal NOx & CO Catalytic conv. Standard** Standard Lowest manifold* Equal NOx & CO Catalytic conv. Standard** Catalytic conv. Std.: high speed turboT.A. Luft emissionsStd.: high speed turbo

CO2 g/kWh 580.8 526.9 581.29 581.29 581.29 581.29 576.13 573.7 568.7

592.3 575.0

575.0 575.0 575.0 566.8

NOx g/kWh 1.34 2.01 1.68 11.39 16.09 17.43 29.5 18.77 20.12 30.84 18.1 19.44 29.5 2.01 16.09 20.12 21.46 37.55 21.46 3.49 1.68 2.68 13.41 18.71 20.12 33.53 13.41 18.77 18.1 29.5 11.39 17.43 16.09 24.14

CO g/kWh 3.02 2.28 2.01 42.91 16.09 12.07 2.01 18.77 17.43 2.68 17.43 14.75 4.02 3.55 37.55 20.12 13.41 1.07 10.73 2.35 2.13 2.28 50.95 18.77 16.09 1.21 52.3 18.77 22.79 1.74 50.96 17.43 20.12 1.74

CH4 g/kWh 9.39 6.03 4.16 2.61 2.61 2.28 1.68 1.14 1.07 0.80 3.42 3.29 2.75 6.03 2.28 2.28 2.28 1.41 1.68 5.7 4.09 4.09 3.42 3.42 3.08 2.28 3.35 2.61 2.61 1.27 2.61 2.28 2.28 2.28

Excess Air Ratio 1.74 1.74 2.00 0.97 0.99 0.99 1.06 0.99 0.99 1.06 0.99 0.99 1.06 1.74 0.97 0.98 0.99 1.12 0.99 1.53 1.59 1.53 0.97 0.98 0.99 1.10 0.97 1.0 0.99 1.06 0.97 1.0 0.99 1.06

VSG G, GSI, GSID

F1197G G

F8176 G

Lowest manifold * Equal NOx & CO Catalytic conv. Standard** Lowest manifld* Equal NOx & CO Catalytic conv. Standard** Lowest manifold* Equal NOx & CO Catalytic conv. Standard**

*Lowest manifold setting refers to best power setting. ** Standard settings refer to best economy setting. All data in this Table is based on max. horsepower and engine speed. For N2O factor, use 0.015 x NOx value.

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Table 1-8: Emission Data for CAT Reciprocating Engines Model 3412 SITA 3508 SITA 3508 SITA 3512 SITA 3512 SITA 3516 SITA 3516 SITA 3606 SITA 3608 SITA 3612 SITA 3616 SITA G398 TALCR G398 TAHCR Catalyst G398 TAHCR 32C (low emissions)HC is hydrocarbons.

Power kW 447 384 470 604 705 809 943 1242 1659 2487 3315 522 522 522 522

Speed rpm 1800 1200 1400 1200 1400 1200 1200 1000 1000 1000 1000 1200 1200 1200 1200

% O2 1.5 7.7 8.0 8.2 7.7 8.3 7.9 12.3 12.3 12.3 12.3 2.0 2.0 0.5 6.2

NOX g/kWh 22.4 2.68 2.68 2.68 2.68 2.68 2.68 0.94 0.94 0.94 0.94 24.54 20.38 12.61 6.71

CO2 g/kWh 436 574 590 579 595 567 581 347 347 347 347

HC g/kWh

1.48 1.21 2.15 1.88

Thermal efficiencies (based on fuel HHV) for reciprocating engines are typically in the range of 28 31 percent for naturally aspirated engines and 31 36 percent for lean burn engines (per Waukesha engine specifications). Gas-fired turbine thermal efficiencies (based on fuel HHV) are typically in the range of 24 30 percent, based on Solar and GE manufacturer data.

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Estimating Greenhouse Gas Emissions

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1.7.3 Flaring of Natural Gas According to EPA AP-42 (Page 9.2-1), smokeless flares that utilize steam injection produce negligible amounts of N2O since combustion gas temperatures usually do not exceed 650oC (1200oF). However, most upstream facilities do not have flares with steam injection and so flame temperatures are approximately 1000oC. At this temperature, NO X does form, although there is limited sample data to say what this amount is. Lab scale tests (M. Strocher, Alberta Research Council, 1996 Investigations of Flare Gas Emissions in Alberta) show that NOX is present in the flare gas emissions in the amount of approximately 10 mg/m3. This equates to an emission factor of 0.276 g NOX/m3 fuel gas. A 98 percent combustion efficiency was used to determine the amount of unburned methane in the flue gas stream for Table 1-9. The use of 98 percent combustion/destruction efficiency is in accordance with current recommendations as set in the Alberta EUB, G60 Flaring Guideline. These factors may change pending technical studies currently sponsored by CAPP to investigate the efficiency of flares. These studies are expected to be complete by December 2003.Table 1-9: Emission Factors for Flaring Natural Gas Natural Gas Type Sales or processed Raw or unprocessed CO2 g/m3 fuel 1853 2281 N2O g/m3 fuel 0.004* 0.004* CH4 g/m3 fuel 13.6 10.85 CO2E g/m3 fuel 2,140 2,510

* Estimated to be 1.5 percent of NOX.

Example 3 Determine the CO2E emissions from the annual flaring of 2,500 x 103 m3 of raw gas. Solution CO2E Emissions = 2,500 x 103 x 2.510 [tonnes CO2E/ 103 m3 gas] = 6,275 tonnes CO2E = 6.28 ktonnes CO2E/yr If the raw gas being flared is substantially different in composition from the average used in the above table (ie 80% CH4. 15% C2H6, 5% C3H8), then Equation 3 should be used to calculate a more representative gas combustion factor. This is especially true when flaring sour gas. When using Equation 3 for determining CO2 from flaring, the hydrocarbon mole fractions must be multipliedApril 2003 Estimating Greenhouse Gas Emissions

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by 0.98 since this is the combustion efficiency. Similarly, the methane emission factor for flaring would be the methane mole fraction multiplied by 0.02 and then by 678.4 (i.e., methane density in g/m3). It is recommended that specific gas analysis and Equation 3 be used when calculating emissions from well test flaring. Gas compositions can vary significantly between wells.

1.7.4 Electric Power Generation Emission Factors The generation of electricity will produce GHG emissions (except for hydroelectricity), as fuel must be burned in order to generate steam required to drive the turbine generators. The amount of emissions produced per kilowatt-hour is dependent on the type of fuel used and the efficiency of the equipment utilized for power generation. For this reason, electric power generation emissions factors vary from province to province and year to year. The data listed in Table 1-11 was obtained from utility companies operating in various provinces. Upstream facilities in North Eastern BC (i.e., Fort St. John area) purchase electricity from Alberta and so should use the ATCO Electric emission factor. Remote northern facilities that generate electricity from diesel generators should use the emission factor for diesel combustion (2,871 kg CO2E/m3 fuel). The emission factor listed in Table 1-10 for Alberta is a weighted average using ATCO Electric, TransAlta, and EPCOR. It should be understood that the emission factors listed in Table 1-10 will change annually as utility companies vary the method of power generation. Table 1-10 does not include line losses.

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Table 1-10: Greenhouse Gas Emissions Associated with Power GenerationProvince British ColumbiaN.E. B.C. (supplied by ATCO)

1990 CO2E kg/MWh * 1130 1000

1995 CO2E kg/MWh * 1089 1035

1996 CO2E kg/MWh * 1058 1025

1999 CO2E kg/MWh * 1089 1007

2000 CO2E kg/MWh 42 1074 1020 1074 820 1070

2001 CO2E kg/MWh 56 1040 1005 1040 790 1070 910 29.0 303.8 14.5 852.5 * 277.8

Alberta (average) ATCO (Alberta) EPCOR (Alberta) TransAlta (Alberta) Saskatchewan Manitoba Ontario Quebec Nova Scotia New Brunswick Newfoundland

750 * 280 * * * *

860 12 130 * * * *

860 12 150 * * * *

880 11 240 1.4 780 546 190

917 25.3 283.7 2.09 864 * 136

* No data available It is recommended that the electrical emission factors specific for each reporting year be used to determine the indirect ghg emissions for each year.

A simplified equation for determining emissions from electrical purchases is: Equation 6 Emissions = (Power usage in MWh for the year) x (CO2E Emission factor) Note: 1 MWh = 3.6 GJ 1.7.5 Methane Emissions from Fugitive Losses Fugitive losses refer to non-intentional vapour losses from pipe fittings and rotating equipment seals. Table 1-11 lists factors that may be used to estimate methane releases from equipment leaks in natural gas piping systems.April 2003 Estimating Greenhouse Gas Emissions

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Table 1-11: Fugitive Emissions Factors in Vapour Service Fitting Valves (sweet gas) Valves (sour gas) Flanges/Connectors (sweet) Flanges/Connectors (sour) Compressor seals PRVs (vented to atmosphere) Open-ended lines Gas Facilities: kg/hr/fitting 0.04351 0.00518 0.00253 0.00031 0.80488 0.12096 0.00373 0.80488 0.12096 0.00373 0.00079 Oil Facilities: kg/hr/fitting 0.01417

Factors for Table 1-11 were taken from "A Detailed Inventory of CH4 and VOC Emissions from Upstream Oil and Gas Operations in Alberta", CAPP, Vol. II, D.J. Picard, March 1992, Table 6, page 75. They can also be found in A Detailed Inventory of CH4 and VOC Emissions From Upstream Oil and Gas Operations in Canada, Volume II, Table 14, page 79 (by Clearstone Engineering, December 3, 1998). Example 4 Determine the CO2E emissions from a sweet solution gas piping system that contains 2 centrifugal compressors, five 8 flanges, ten 4 flanges, three 8 valves and eight 4 valves. The piping pressure is 400 psi and the gas contains 60 percent methane (i.e., by weight). Solution The fugitive emissions factors are independent of pipe fitting size and line pressure. There are a total of 2 compressor seals, 15 flanges and 11 valves. Using Equation 7 and Table 1-11 we get: Methane loss = [(2 x 0.805) + (15 x 0.0025) + (11 x 0.0435)] x 0.6 x 8760 hr/yr = 11,174 kg CH4/yr = 11.17 tonnes CH4/yr CO2E = 11.17 x 21.0 = 234.6 tonnes CO2E/yr

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A simplified equation for determining fugitive emissions is: Equation 7 Total Methane Emissions (in kg/yr) = (Na x F a) x W x 8,760 hr/yr Where: Na = total number of fittings of type a Fa = fugitive emissions factor (in kg/hr/fitting) for fitting a W = weight fraction of methane in gas = [(mole fraction CH4) x 16.04] / [Molecular Weight of mixed gas] where 16.04 is the molecular weight of methane 1.7.6 Methane Emissions from Instrumentation Venting When natural gas is used to operate instrumentation and valves for process control, methane gas is vented (unless a recovery system is in place) during the normal operation of this equipment. The following table lists the gas losses for standard instruments (common prior to 1985) in regulating or throttling service. Losses for on/off service will be much lower.Table 1-12: Gas Consumption Rates (in m3/hr) for Standard (high bleed) Pneumatic Instruments Instrument Type Transmitter Controller I/P Transducer P/P Positioner I/P Positioner Chem. inj. pumps (diaphragm) Chem. injection pumps (piston) Operating Pressure = 140 kpag 0.12 0.6 0.6 0.32 0.4 0.4 0.04 Operating Pressure = 240 kpag 0.2 0.8 0.8 0.5 0.6 0.6 0.06

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In regulating service, the controller continuously receives a process feedback signal which is used to maintain a process variable such as level, pressure or temperature. The above data was taken from "Options for Reducing Methane and VOC Emissions from Upstream Oil and Gas Operations", D.J. Picard/Clearstone Engineering and S. Sarkar/Fluor Daniel Canada, CAPP, December 1993, Table 22, page 2-4. An example of a high bleed controller is the Fisher 4150K and 4160K (pressure controllers and transmitters), which can vent up to 0.8 m3/hr. The Fisher 2500 Series pneumatic controllers and transmitters used for level control (e.g., LevelTrol applications) can vent from 0.2 to 1.0 m3/hr. An average emission value of 0.1996 m3/hr/instrument controller is sited in A Detailed Inventory of CH4 and VOC Emissions from Upstream Oil and Gas Operations in Canada, Volume 2, page 83, Table 16 (by Clearstone Engineering). New low bleed instruments are now available from various manufacturers. The Fisher 4195 (i.e., gauge pressure indicating controller) is a low bleed, steady-state bleed controller that vents approximately 0.1 and 0.14 m3/hr at 103 and 210 kPag respectively. The Fisher 2680 series liquid level controller is a low bleed controller, which vents 0.03 m3/hr. The Fisher series 2660 (i.e., liquid level controller), 2100 (i.e., electric liquid level switch) and 4660 (i.e., high-low pressure pilot) are no bleed or no vent controllers that have no bleed while in the steady state. Gas losses in actuating service are about 0.03 m3/hr for these units. Becker Precision Equipment also supplies the following no bleed (at steady-state) instruments: VRP-B-A (with DPS-2 sensor) & VRP-B-C: double acting pilot pressure control; VRP-SB-A & VRP-SB-C: single acting pilot pressure control; HPP-3-A (with DPS-2) & HPP-3-C: double acting pneumatic positioner; HPP-3E-A (with DPS-2) & HPP-3E-C: double acting electro-pneumatic positioner; HPP-SB-A: single acting pneumatic positioner; and, HPP-SB-C, HPP-SB-E-A, HPP-SB-E-C: single acting electro-pneumatic positioner.

Other process equipment such as ESD (emergency shut down) valves and solenoids only vent during shutdown. The vent rate used for emission estimates should be 0.03 m3/hr for each shutdown event.

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Estimating Greenhouse Gas Emissions

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1.7.7 Methane Losses from Glycol Dehydrators Glycol dehydrators are used to remove water from natural gas streams. When the liquid glycol contacts the natural gas, it absorbs the water from the gas stream along with a small amount of hydrocarbons such as methane. When the glycol is regenerated to remove the absorbed water, the hydrocarbons are also removed. This regeneration process includes flashing off excess methane by reducing process pressure in a flash separator and then boiling off the water by heating the glycol to about 190oC in the glycol reboiler. Methane liberated from the glycol in the flash separator is usually recovered and injected back into the process. However, if a flash separator is not present, then a significant amount of methane will be liberated with the water vapour in the glycol reboiler. If the reboiler vent is allowed to discharge to atmosphere, then all the liberated methane will be lost to the atmosphere as a greenhouse gas emission. If detailed process data such as: wet gas composition; wet gas flow rate, temperature and pressure; and glycol flow rate are available, then computer software such as GRI GLYCalc may be used to determine methane emissions from the glycol dehydrators. If such detailed process data is unavailable, then general emission factors as shown in Table 1-13 can be used to estimate methane losses.Table 1-13: Average Methane Emission Factors for Dehydration Dehydration Mode of Operation Gas pump without a flash separator Gas pump with a flash separator Electric pump without a flash separator Electric pump with a flash separator CH4 Emission factor Tonnes CH4 / 106 m3 gas processed 0.2264 0.0054 0.0588 0.0045

The above Table excludes methane losses from stripping gas addition. When a flash separator is present, it is assumed that flash gas is recovered and not vented.

Data for Table 1-13 was based on GLYCalc model results taken from GRI report No. GRI 98/0073, Investigation of Condenser Efficiency for HAP Control from Glycol Dehydrator Reboiler Vent Streams: Analysis of Data from the EPA Questionnaire and GRIs Condenser Monitoring Program. In order to decrease the water content of the regenerated glycol (i.e., to achieve dryer gas specs), some gas production operators add stripping gas (i.e., dry natural gas) to the reboiler. Without the presence of any hydrocarbon recovery system on the reboiler vent, this additional gas is lost to the atmosphere. Although the amount of stripping gas lost is dependent on the dew point depression requiredApril 2003 Estimating Greenhouse Gas Emissions

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and the glycol circulation rate used, typical losses can be from 0.0047 to 0.0281 m3 / m3 gas processed. In terms of mass, this is 3.178 to 19.061 tonnes CH4 / 106 m3 gas processed. These rates are based on glycol dehydrator design rates quoted by glycol manufacturers. If a condensing coil is present in the reboiler vent stack, heavier hydrocarbons such as benzene will be condensed from the vapour; however, methane losses will remain unchanged. 1.7.8 Methane Emissions from Oil Batteries To estimate hydrocarbon vapour volumes generated at well batteries, the factors listed in Table 1-14 may be used.Table 1-14: Factors Used to Estimate Gas Venting and Flaring Rates Emission Source Conventional Oil Description (Solution gas is off stock tanks) Solution gas (no treater in process) Solution gas (with treater in process) Solution gas (with gas boot in process) Primary Heavy Oil Casing gas produced: Casing gas vented (63.2%) Solution gas produced: Solution gas vented (38.7%): Thermal Heavy Oil Casing gas produced: Casing gas vented (4.7%): Solution gas produced: Solution gas vented (0%) Crude Bitumen Casing gas produced: Casing gas vented (18%): THC Emission Factor m3/m3 of oil production 5.0 3.2 0.45

59.2 37.4 1.0 0.38 53.9 2.53 8.3 0.0 12.9 2.3

The above data was taken from "A Detailed Inventory of CH4 and VOC Emissions From Upstream Oil and Gas Operations in Alberta", Picard, CAPP,April 2003 Estimating Greenhouse Gas Emissions

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Volume II, March 1992, Table 8, page 80. The solution gas emissions factors in Table 1-10 are used to estimate the amount of gas that flashes from the oil when it first enters the stock tank. Vented gas percentages shown in Table 1-10 were taken from A Detailed Inventory of CH4 and VOC Emissions from Upstream Oil and Gas Operations in Canada, Volume 2, Table 10, page 52 and Table 11, page 58 (by Clearstone Engineering, December 3, 1998). The solution gas and casing gas volumes listed in Table 1-14 were obtained from testing of numerous field production batteries, and represent average values. If available, it is best to use your own site-specific hydrocarbon composition/analysis and gas/oil ratio to determine solution gas and casing gas volumes. Refer to note g on the short form, GHG-SF, at the end of this section. Since these factors give total hydrocarbon vapour quantities, the fraction of methane in the solution gas must be known to calculate the methane losses. In the absence of site-specific data, an average tank vent CH4 content of 27.4 percent by volume may be used. This value is the average obtained from two published studies (API 1997 and Picard 1992). The total methane emissions that contribute to GHG emissions will depend on whether the gas is vented to atmosphere, flared, or recovered for sales. Example 5 Determine the methane losses in terms of CO2E for 2 oil batteries, both of which produce 100 m3/day of light oil. Battery A has a treater in its process and collects and flares all vapours off its stock tanks. Battery B has no treater and vents its stock tanks to atmosphere. The mole percent methane in both solution gases is 80 percent. Solution Battery A = [Fuel Volume] x [Flaring Combustion CO2E Emission Factor]= [100 (m3/day) x 365 (days) x 3.2 (m3/m3] x [2.57 (tonnes/103m3)] / 1000

= 300.2 tonnes CO2E/yr. Battery B = [Methane Emissions in kg] x [GWP factor]= [100 (m3/d) x 365 (days) x 5.0 (m3/m3) x 0.80 x 0.678 (kg/m3)] x [21.0]/103

= 2,078 tonnes CO2E/yr. The above example illustrates that burning the solution gas produces much less greenhouse gas than venting.

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Estimating Greenhouse Gas Emissions

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1.7.9 Methane Emissions from Plant Tank Venting Hydrocarbon vapour breathing and working losses from tankage can be calculated using EPA's computer program "TANKS", or the equations in EPA AP-42 Section 4.3-1. Calculators should ensure that they are using the most recent EPA updates, thus checking the EPA website (www.epa.gov) is recommended. It should be noted that generally, very little methane would be liberated from liquid hydrocarbon sales storage (i.e., after processing). If the liquid composition shows no methane content, no methane emissions will be released from tankage vented to atmosphere. The only significant losses of methane from tankage occur when the initial crude production decreases in pressure from the inlet separator conditions to atmospheric pressure in the well-site or oil battery storage tanks. See the previous section (1.7.8) for more information on this topic. Breathing loss is the expulsion of vapour from a tank through vapour expansion and contraction, caused by changes in temperature and barometric pressure. Breathing losses for vertical cylindrical shells venting to atmosphere with fixed roofs can be calculated using the following equation: Equation 8 LB = 2.26 x 10-2Mv(P/(PA - P))0.68 x D1.73 H0.51DT0.5FPCKC where: LB = fixed roof breathing loss (lb./yr.) M v = molecular weight of vapour in storage tank PA = average atmospheric pressure at tank location (psia) P = true vapour pressure at bulk liquid conditions (psia) D = tank diameter (ft.) H = average tank vapour space height, including roof volume correction (ft.) DT = average ambient diurnal temperature change (oF) FP = paint factor (= 1.0 for white in good condition) C = adjustment factor for small diameter tanks (see EPA AP-42, Figure 4.34) For tank diameter of 20 feet, C = 0.9 For tank diameter of 30 feet or greater, C = 1.0 KC = product factor For crude oil, KC = 0.65

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For all other organic liquids, KC = 1.0 The combined vapour loss from filling and emptying a tank is called working loss. For fixed roof tanks venting to atmosphere, the working losses may be estimated using the following equation: Equation 9 LW = 2.40 x 10-5 x MvPVNKNKC where: LW = fixed roof tank working loss (lb./yr) M v = molecular weight of vapour in storage tank P = true vapour pressure at bulk liquid temperature (psia) V = tank capacity (U.S. gallons) N = number of tank turnovers per year (dimensionless) where: N = (total through-put per year) / (tank capacity)KN = turnover factor (see EPA AP-42, Figure 4.3-7). KN = 1.0 for N = 36 or less

KC = product factor For crude oil, KC = 0.65 For all other organic liquids, KC = 1.0 1.7.10 Methane Losses from Non-Routine Venting Natural gas or methane venting losses due to equipment failure or releases through pressure safety valves (PSVs) open to atmosphere may be calculated using the following equation. Equation 10 tCO2E from Gas Venting = (Natural gas vented volume in 103m3) (mole fraction methane) 0.6784 [tonnes/103m3] 21 [GWP] 1.7.11 CO2 Venting from Sour Gas Processing Facilities Sour gas contains both H2S and CO2. These gases are removed from the natural gas inlet stream in order to meet pipeline sales gas specifications (i.e., 2 mole percent CO2). After H2S is removed from the inlet gas stream it may be recovered as elemental sulphur or burned to produce SO4. The removed CO2 is sent to the incinerator or flare, but since it is non-combustible, it becomes an atmospheric release of CO2.

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This CO2 released to the atmosphere may be estimated using the following formula: Equation 11 tonnes CO2 released = [ (MF x VI) - (SMF x VS) ] x 1.8612 / 1000 where: MF = mole or volume fraction CO2 in inlet gas VI = volume inlet gas in m3/yr @ STP conditions SMF = sales gas spec. for mole fraction, CO2 = 0.02 typically VS = volume sales gas in m3/yr @ STP conditions 1.8612 = density of CO2 in tonnes/103 m3 at STP conditions An alternate method to calculate CO2 vented is based on the amount of CO2 being sent to the acid gas incinerator. The following formula may be used for this method. Equation 12 CO2 released (in tonnes/yr) = (MFS x AGV) x 1.8612 / 1000 where: MFS = mole fraction CO2 in acid gas to incinerator inlet AGV = acid gas volume to incinerator inlet in m3/yr @ STP conditions 1.8 Fugitive Emission Estimates Derived from the GFC Method Although the Detailed Method gives the best results, it requires substantial effort to collect the actual number of valves and fittings from a given site/facility (either by site inspection or the review of facility PIDs). The Short Form method is quite simple to use; however, since it uses production-based fugitive emission factors, it usually results in high emissions volumes. In order to improve the accuracy of the Short Form method for fugitive emissions without a substantial increase in effort, the new Generic Fitting Count (GFC) may be used. By using a generic or average fitting count for specific equipment/processes, the fugitive emissions calculated will be based on the number of fittings without the need to count fittings at a specific site. The generic fitting counts presented here were taken from an API fugitive emission study of 20 different facilities in 1993. Reference should be made to API Publication 4589, Dec. 1993, Fugitive Hydrocarbon Emissions from Oil and Gas Production Operations.

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Table 1-15 to Table 1-19 list the generic or average fitting counts determined from this API study. The fitting counts in these Tables do not distinguish how many fittings are in liquid or vapour service. Equipment with both liquid and gas fittings such as separators and dehydrators can be considered to have 50 percent of their fittings in gas service (i.e., as an approximation). Example 6 Use the Generic Fitting Count to calculate the annual fugitive emissions from a sweet gas plant that has: 1 inlet separator 2 reciprocating compressors 1 dehydrator 1 fractionation tower 2 scrubbers 1 sales gas meter

The plant operates 360 days per year, has 1 PRV relieving to atmosphere and has 85 percent methane content (by weight) in its gas. Solution Using Table 1-15, the total number of gas connectors is: (48 x 0.5) + 2(129) + (105 x 0.5) + (81 x 0.5) + 2(81 x 0.5) + 160 = 617 where 0.5 is used for the inlet separator, dehy, fractionator and scrubbers since half of the connectors are in gas service. Using Table 1-16, the total number of gas valves is: (17 x 0.5) + 2(26) + (25 x 0.5) + (23 x 0.5) + 2(23 x 0.5) + 41 = 149 Using Table 1-17, the total number of open-ended gas lines is: (3 x 0.5) + 2(2) + (3 x 0.5) + (2 x 0.5) + 2(2 x 0.5) + 13 = 23Using

Table 1-18, the number of compressor seals is: 2(3) = 6 The number of PRVs vented to the atmosphere is 1. Therefore, using the fugitive emission factors from Table 1-11 and Equation 7, the total fugitive emissions are:April 2003 Estimating Greenhouse Gas Emissions

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= [(617 connectors x 0.00253 kg/hr/connector) + (149 valves x 0.04351 kg/hr/valve) + (23 open-ended lines x 0.00373 kg/hr/OEL) + (6 seals x 0.80488 kg/hr/seal) + (1 PRV x 0.12096 kg/hr/PRV) ] x 24 hr/day x 365 days/yr x 360/365 x 0.85 = [1.56 + 6.48 + 0.09 + 4.83 + 0.12] x 8760 x 0.986 x 0.85 = 13.08 x 8760 x 0.986 x 0.85 = 96,030 kg CH4/yr = 96 tonnes CH4/yr = 96 x 21 (GWP factor) = 2,017 tonnes CO2E/yrTable 1-15: Generic or Average Connector Counts by Equipment/Process TypeEquipment/Process Light Oil Facilities 53 389 146 111 41 Heavy Oil Facilities 44 108 Gas Production 60 105 147 160 122 94 91 119 55 155 160 105 81 109 163 195 78 105 114 120 81 221 144 129 417 162 177 376 383 210 48 145 Gas Plants Offshore Platforms 195 310 197 299 269 Overall Onshore Average 52 187 147 90 122 94 102 126 81 127 162 78 102 168

Well Header Heater Separator Filter Chiller Meter Dehydrator Fractionation Sulphur Compressor Vapour Recovery Scrubber Flare

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Table 1-16: Generic or Average Valve Counts by Equipment/Process TypeEquipment/Process Light Oil Facilities 13 109 28 24 10 Heavy Oil Facilities 8 17 Gas Production 16 26 22 30 19 25 21 26 13 31 41 25 23 34 34 31 10 22 35 24 23 71 42 26 88 41 39 74 84 46 17 38 Gas Plants Offshore Platforms 61 82 45 81 42 Overall Onshore Average 12 48 25 20 19 25 25 27 23 38 30 10 23 53

Well Header Heater Separator Filter Chiller Meter Dehydrator Fractionation Sulphur Compressor Vapour Recovery Scrubber Flare

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Table 1-17: Generic or Average Open-ended Line Counts by Equipment/Process TypeEquipment/Process Light Oil Facilities 2 4 3 3 2 Heavy Oil Facilities 3 4 Gas Production 3 4 4 5 3 1 4 2 5 13 3 2 7 2 5 3 3 5 2 2 1 3 2 12 8 5 11 10 5 3 4 Gas Plants Offshore Platforms 20 14 4 11 8 Overall Onshore Average 3 4 4 3 3 1 6 4 2 5 3 3 2 3

Well Header Heater Separator Filter Chiller Meter Dehydrator Fractionation Sulphur Compressor Vapour Recovery Scrubber Flare

Table 1-18: Generic or Average Compressor Seal Counts by Equipment/Process TypeEquipment/Process Light Oil Facilities 1 Heavy Oil Facilities Gas Production 2 Gas Plants 3 Offshore Platforms 2 2 Overall Onshore Average 2

Compressor Vapour Recovery

Since the fugitive emission factor for compressor seals is quite high, it is advisable to use the actual number of seals at your specific facility. Generally, centrifugal compressors have one seal per unit, while reciprocating compressors have one seal per cylinder.April 2003 Estimating Greenhouse Gas Emissions

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Table 1-19: Generic or Average PRV Counts by Equipment/Process TypeEquipment/Process Light Oil Facilities 1 3 2 1 3 2 2 1 2 Heavy Oil Facilities Gas Production Gas Plants Offshore Platforms Overall Onshore Average 1 3 2 2 0 0 2 2 2 1 4 1 2 2 1 0 3 4 3 1 2 1 1 4 0 2 0

Well Header Heater Separator Filter Chiller Meter Dehydrator Fractionation Sulphur Compressor Vapour Recovery Scrubber Flare

Table 1-19 should be used with caution. Although the number of PRVs shown per equipment is reasonable, it is unlikely that this number of PRVs will be vented to atmosphere at Canadian facilities. Operations staff should be consulted about how many PRVs actually vent to atmosphere at their facility. Operations staff should also review all allocated generic fitting counts prior to finalizing fugitive emission calculations. After determining the number of equipment/processes that exist at a specific facility (i.e., through examination of Process Flow Diagrams or interviews with Operations), the number of fittings per process (in Table 1-15 to Table 1-19) may be used to determine the total number of fittings. Using this total fitting count along with the fugitive emission factors listed in Table 1-11, the total fugitive emission losses can be calculated. This GFC procedure does not take into account venting from gas operated field instrumentation and controllers. These losses must be determined separately.April 2003 Estimating Greenhouse Gas Emissions

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1.9

Emissions from Cogeneration Systems With the increasing demand for electrical power and the need to improve facility thermal efficiencies, many large processing facilities are considering the installation of cogeneration equipment. Cogeneration is the simultaneous production of two useful forms of energy, electrical and thermal, in a common process. Processing facilities with both a high demand for thermal and electrical energy demand will benefit the most with the installation of a cogeneration system. The typical cogeneration system uses natural gas for combustion in a gas turbine, which turns a generator to produce electricity. The hot exhaust gases from the gas turbine are then diverted to a waste heat recovery boiler, which produces steam for other plant processes. Since both electricity and useful heat is produced from the combustion of the natural gas, a combined system thermal efficiency of 45 to 55 percent can be achieved versus a typical gas turbine HHV efficiency of 30 percent. Thermal efficiency can be defined as the amount of useful work or energy recovered compared to the total amount of fuel energy consumed. Sources of GHG emissions from a cogeneration system are: Combustion of natural gas for the gas turbine. Combustion of natural gas for supplemental heating in the waste heat boiler (if needed). Fugitive methane emissions from equipment and pipe fittings.

Example 7 Calculate theoretical cogeneration GHG Emissions: Solution Using a turbine thermal efficiency of 30 percent and a cogen system thermal efficiency of 45 percent, the amount of waste heat recovered (for steam generation) is: [ ( 1.0 kWh / 0.30 ) x 0.45 ] 1 kWh = 0.50 kWh Therefore, for every kWh of electrical power produced, there is 0.50 kWh of waste heat available for use. This assumes there is no supplemental fuel required in the waste heat recovery unit (or boiler). Since combustion from gas turbines yields an emission factor of 0.590 kg CO2E/kWh output, the per unit emissions would be: = 0.590 kg CO2E / (1.0 + 0.5) kWhApril 2003 Estimating Greenhouse Gas Emissions

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= 0.393 kg CO2E /kWh of total energy output (electric power + heat combined) This factor excludes emissions from auxiliary equipment such as boiler feedwater pumps. Therefore, the theoretical cogen emission factor is 0.393 kg CO2E /kWh of total energy output (excluding auxiliary equipment emissions). Example 8 Calculate the theoretical GHG emissions saved producing cogen power. Solution The amount of GHG saved when electricity is produced using cogen versus conventional thermal coal combustion (as in Alberta) is: Incremental emissions for using natural gas as a fuel versus coal: 1.005 0.590 = 0.415 kg CO2E/kWh. Incremental emissions from producing process heat from waste heat versus gas combustion (at 80 percent boiler thermal efficiency): 0.229 kg CO2E/kWh. Incremental fugitive methane losses from a gas turbine unit versus a gas fired boiler. Since the number of fittings in these two pieces of equipment is almost identical, the difference in fugitive emissions will also be negligible.

Therefore the net greenhouse gas emission savings are: (0.415 ) + ( 0.50 kWh x 0.229 ) = 0.530 kg CO2E/kWh electricity produced from cogen. The above greenhouse gas emissions savings (0.530 kg CO2E/kWh) assume that coal fired electrical power generation will be backed out. This isnt necessarily the case however. Arguments can be made that only newer gas fired power generation will be backed out or turned down. Since emissions from gas fired power generation are in the order of 0.590 kg CO2E/kWh, the net greenhouse gas emissions savings from cogen would then only be: 0.50 x 0.229 = 0.115 kg CO2E/kWh electricity produced from cogen. The allocation of GHG emissions from the purchase of cogeneration electrical power and/or steam/heat will depend on the agreement for CO2 credits made between the cogen facility investor, operator and consumer. As explained earlier, if no supplemental fuel is added to the waste heat recovery unit or boiler, 0.590 kg CO2E are released for every kWh of electrical power generated and 0.0 kg CO2E are released for every kWh of waste heat recovered for use.

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Estimating Greenhouse Gas Emissions

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Published data from the U.S. Dept. of Energy list the GHG emissions from natural gas combined cycle electrical generation (i.e., cogeneration) to be: 0.0000068 kg CH4/kWh and 0.432 kg CO2/kWh. This compares to our above calculated combined emission factor of 0.393 kg CO2E /kWh. Therefore, if no manufacturer specific emission factors are available, 0.432 kg CO2E per combined kWh (heat and power) can be used for estimating emissions from cogeneration facilities. Operators of cogen Facilities should use Equation 13 to report direct GHG emissions. Equation 13 Direct cogen emissions in tonnes = (gas-fired turbine output power in MW) (# hrs operated in year) (0.59 [tonnes CO2E/MWh]) + (heat recovery boiler makeup fuel in 103m3/yr) (1.903 [tonnes CO2E/103m3]) Purchasers of cogen power or steam should use Equation 14 to report indirect GHG emissions. Equation 14 Indirect cogen emissions (gas-fired combined cycle) in tonnes = (purchased cogen power in MWh) (0.432 [tonnes CO2E/MWh]) + (purchased cogen steam heat in GJ/yr / 3.6 [GJ/MWh]) (0.432 [tonnes CO2E/MWh]) The 0.432 kg CO2/kWh factor was extracted from the U.S. Dept. of Energy Instructions for Form EIA-1605 Voluntary Reporting of Greenhouse Gases Appendix C Adjusted Electricity Emission Factors by State. DOE EIA Form 1605 9b), Sector Specific Issues (volumes 1 and 2), 1997. 1.10 Emissions from Off-shore Operations Greenhouse gas emission sources from offshore production facilities include: Combustion of fuel for gas turbines or engines; Combustion of fuel for process heaters and boilers; Combustion from flaring; Methane losses from venting (production and process); Methane losses from fugitives; Storage tank venting; Offloading of crude product; and, Combustion from mobile sources (marine and aircraft).

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Estimating Greenhouse Gas Emissions

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Except for the last two items, all of these emission sources have already been discussed earlier. The amount of methane lost during offloading operations will depend on the process configuration at the facility and the final methane content of the offloaded crude. It is expected that off-loading losses of methane will be negligible. The methodology of estimating off-loading hydrocarbon losses is explained in detail in EPA AP-42 (1995 Edition), Section 5.2-7 (Transportation and Marketing of Petroleum Liquids). The following Equation 15 was taken from EPA AP-42 and can be used to estimate loading losses: Equation 15 LL = 1.493 S P M ( 1 ( eff / 100) ) T Where: LL = loading losses in kg/m3 liquid loaded S = 0.2 for submerged loading onto ships 0.5 for submerged loading onto barges P = true vapour pressure of liquid loaded in psia (pounds per square inch absolute) M = vapour molecular weight T = bulk temp of liquid loaded in R (F+460) eff = overall reduction efficiency of loading losses EPA AP-42 does not list specific emission factors for mobile off-land mobile sources. Specific emission factors may be obtained from the equipment manufacturer. In the absence of these specific factors, emission factors associated with fuel type may be used. These are listed in Table 1-20.

Table 1-20: Fuel Emission Factors (for mobile sources) Fuel Type Diesel oil Fuel Oil Turbo fuel Aviation gas Mobile Source Tankers Tankers Helicopter Sea plane Emission Factor kg CO2E/litre 2.856 3.223 2.629 2.443

Above factors taken from Environment Canada Inventory Methods Manual for Estimating Canadian Emissions of Greenhouse Gases, May 6, 1994, pages D45.5-5 and D49.1-5 April 2003 Estimating Greenhouse Gas Emissions

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1.11

Conversion Factors 1 Million Btu/hr = 293.07 kW 2544.4 Btu/hr = 1 hp 1 hp = 0.7457 kW 1 kilowatt hour = 1 kWh = 3.6 MJ 1 megawatt hour = 1 MWh = 3.6 GJ 1 kpa = 0.145 psi 1 m3 = 6.2898 barrels 1 ktonne = 1000 tonnes = 1 x 106 kg Density of fuel gas assumed to be 0.6784 kg/m3 @ 15oC and 101.33 kpa. Density of carbon dioxide = 1.861 kg/m3 @ 15oC and 101.33 kpa. 1 kilojoule = 1 kJ = 1 x 103 J 1 megajoule = 1 MJ = 1 x 106 J 1 Gigajoule = 1 GJ = 1 x 109 J 1 Terajoule = 1 TJ = 1 x 1012 J

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Estimating Greenhouse Gas Emissions

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Form GHG SF

Rev. 3

Calculation of Greenhouse Gas EmissionsCompany/Facility: ___________________________ Reporting Year: _______ Prepared by: _______________________________ Date: _____________

1 Combustion Emissions:Line #1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10 1.11

Description(on a gross basis for company operated facilities only) Total natural gas burned: _______________ 103 m3/yr x Total propane liquid burned: _____________103 m3/yr x Total diesel fuel burned: _______________103 m3/yr x Total raw flared gas volumea: _______________103 m3/yr x Total electricity purchased in Alberta:___________MWh/yr x Total electricity purchased in B.C.:_____________MWh/yr x Total electricity purchased in N.E. B.C.:_________MWh/yr x Total electricity purchased in Sask.:____________MWh/yr x Total electricity purchased in Man.:___________MWh/yr x Total electricity purchased in Ontario:______MWh/yr x Subtotal (Add Lines 1.1 to 1.10):

CO2E factor2.06n 1,644.0m 2,871.0 2.51 1.005 0.056 1.040 0.910 0.029 0.304 = = = = = = = = = = =

CO2E tonnes/yr

2 Fugitive and other Methane Lossesb:Line #2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

Description(on gross thru-put basis for company operated facilities) Measured vented gas volumec: _______103 m3/yr x _______d x Light oil sales: _________________ 103 m3/yr x Conventional heavy oil sales: ____________103 m3/yr x Thermal recovery heavy oil sales: _________103 m3/yr x Sweet gas plant sales: _______________ 103 m3/yr x Sour gas recovery plant sales:____________103 m3/yr x Sour gas plant sales: ________________ 103 m3/yr x Straddle plant NGL sales: ____________ 103 m3/yr x Subtotal (Add Lines 2.0 to 2.7):

Emission Factor14.25 38.0e 529.4f 27.8g 0.0694m 0.0576m 0.0634m 1.52m =

CO2E tonnes/yr= = = = = = = =

3 CO2 Vented from Sour Gas Processing:Line #3.1 3.2 3.3 3.4a 3.4b 3.4c 3.5April 2003

Description

CO2 mole

fraction (on a gross basis for company operated facilities) h Sour gas processed: _____________ 103 m3/yr x 1.86 x 3 3 h Sour gas processed: _____________ 10 m /yr x 1.86 x Total CO2 in inlet gas stream (Add Lines 3.1 + 3.2): = Sweet gas sales from sour plants:___________103m3/yr x 0.0372i Sweet gas sales from sour plants:___________103m3/yr x ____j 3 3 k CO2 injected downhole: ___________10 m /yr x _______ x 1.86l Total CO2 Vented: Lines 3.3 - (3.4a+b+c): Subtotal =Estimating Greenhouse Gas Emissions

CO2 tonnes/yr= = = = =

1-38

4 Total CO2E Emissions:Add Lines 1.11 + 2.8 + 3.5 = ______________ tonnes/yr / 1000 = ___________ ktonnes/yr

Notes:a b

Includes flared gas from solution gas burning, process upsets, and well testing. Except for line 2.0, listed emission factors include methane emissions from pipe fitting leaks, solution gas venting, and instrument venting. Do not include production associated with measured methane losses in line 2.1 to 2.7, provided measured values include all losses listed under note b above. This is the methane content (volume or mole fraction) of the vented gas. This factor assumes solution gas venting of 3.2 m3/m3 oil production (with 80 percent methane content by volume) and fugitive emissions from pipe fittings to be 1.5 tonnes CO2E/1000 m3 oil production. For different conditions, use formula in note g below. This factor assumes casing plus solution gas venting of 37.8 m3/m3 oil production (with 98 percent methane content by volume) and fugitive emissions from pipe fittings to be 1.5 tonnes CO2E/1000 m3 oil production. For different conditions, use formula in note g below. This factor assumes casing plus solution gas venting of 2.53 m3/m3 oil production (with 73 percent methane content by volume) and fugitive emissions from pipe fittings to be 1.5 tonnes CO2E/1000 m3 oil production. For different conditions, use the following formula to determine a new emission factor: [ (SGv + CGv) x MC x 0.6784 kg/m3 x GWP ] + 1.5 where: SGv CGv MC GWP = = = = Solution gas vented in m3/m3 oil production Casing gas vented in m3/m3 oil production Methane content in volume fraction Global Warming potential for methane = 21.0

c

d e

f

g

h

Inlet gas CO2 content in volume or mole fraction. Generic pipeline specification for CO2. CO2 slippage to pipeline sales if different than i above. CO2 content (volume or mole fraction) of acid gas being injected downhole. Density of CO2 (in tonnes/103m3) at 15oC and 101.3 kpaa.Estimating Greenhouse Gas Emissions

i j

k l

April 2003

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m

Average value obtained from A Detailed Inventory of CH4 and VOC Emissions from Upstream Oil and Gas Operations in Canada, by Clearstone Engineering, Dec. 3, 1998.n

Assumes that 50 percent of total combustion fuel is used for boilers/heaters, 30 percent for reciprocating engines, 19 percent for turbines and 1 percent for flares (does not include solution gas flaring). To determine a combustion emission factor specific to your operations, use the following equation: (FFBoiler x 1.90) + (FFTurbine x 1.796) + (FFRecip x 2.496) + (FFFlare x 2.14) where FF is Fuel Fraction (of total fuel used).

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Estimating Greenhouse Gas Emissions

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Form GHG SS Calculation of Greenhouse Gas Reductions from ProjectsCompany: Contact: Project Title: Description: Start-up Date:1.0 1.1 1.2 1.3 1.4

Facility: Title:

LSD: Phone:

MMDDYY

Duration:

yearst CO2E/yr Method _________ ______ _________ ______ _________ ______ _________ ______

Fuel Gas Conservation (Combustion)Reduction from boilers: ______103 m3/yr x 1.903 = Reduction from recip. engines: ______103 m3/yr x 2.496 = Reduction from turbines: ______103 m3/yr x 1.796 = Reduction from flare make-up: ______103 m3/yr x 2.140 =

2.02.1 2.2 2.3 2.4 2.5

Fuel Gas Conservation (Venting)

MMF_________ _________ _________ _________ _________ ______ ______ ______ ______ ______

Reduction from LDAR survey: _____103 m3/yr x _____ x 14.25 = Reduction from gas instruments:_____103 m3/yr x _____ x 14.25 = Reduction from chemical pumps_____103 m3/yr x _____ x 14.25 = Reduction from dehy. pumps: _____103 m3/yr x _____ x 14.25 = Reduction from gas stripping: _____103 m3/yr x _____ x 14.25 =

3.03.1 3.2

Raw Gas Conservation (Combustion)Reduction from flaring: Reduction from flaring: ______103 m3/yr x 2.51 = ______103 m3/yr x ______ (CEF) = _________ _________ ______ ______

4.04.1 4.2 4.3

Raw Gas Conservation (Venting)

MMF______ ______ ______

Reduction from LDAR survey: _____103 m3/yr x _____ x 14.25 = _________ Reduction from dehy. reboiler stack: _____103 m3/yr x _____ x 14.25 = _________ Reduction from process venting: _____103 m3/yr x _____ x 14.25 = _________

5.05.1

CO2 Venting Conservation (from Gas Sweetening)Reduction in acid gas incineration, venting or flaring: ________103 m3/yr x _______ CO 2 mole fraction x 1.86 = _________ ______

6.06.1 6.1

Purchased Electric Power Conservation

PEEF______ ______

Reduction in motor power:____ hp x _____ hrs/yr x 0.000746 x _____ = _________ Reduction in other power: ____ kW x ____ hrs/yr x 0.001 x _____ = _________

7.07.1 7.2 7.3 7.4 7.5 7.6

Increase in Energy UseIncrease in boiler fuel gas: ______103 m3/yr x 1.903 = _________ Increase in recip. engine fuel gas:______103 m3/yr x 2.496 = _________ 3 3 Increase in turbine fuel gas: ______10 m /yr x 1.796 = _________ Increase in flared gas: ______103 m3/yr x 2.51 or x ____ (CEF) = _________ Increase in electrical motors:____hp x ____ hrs/yr x 0.000746 x _____7 = _________ Increase in electric power:____ kW x ____ hrs/yr x 0.001 x _____7 = _________ ______ ______ ______ ______ ______ ______

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Estimating Greenhouse Gas Emissions

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8.0

Total Greenhouse Gas Reduction(Add sections 1 to 6 and subtract section 7) _________

Notes: 1. Insert the following codes for volume quantification Method: M for measured, MB for mass balance, EF for emission factor and E for estimated. 2. Attach calculations and assumptions made in quantifying volumes. 3. Attach fuel gas or raw gas compositions. 4. LDAR is leak detection and repair 5. MMF is mole fraction of methane in the gas. 6. CEF is custom emission factor based on specific gas composition 7. PEEF is provincial electrical emission factor: 1.005 for Alberta; 0.056 for BC; 0.910 for Sask.; and 0.304 for Ontario. 8. tCO2E is tonnes carbon dioxide equivalent.

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Estimating Greenhouse Gas Emissions

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2

Benchmarking 2.1 Introduction At a workshop held July 18, 1995, representatives from 34 CAPP member companies discussed and agreed to the methods and conventions outlined in this section when calculating the benchmarking of energy used and greenhouse gas (GHG) emissions per unit of production. On January 23, 1996, another workshop was held and attending CAPP member companies agreed that as a minimum, both Production Energy Intensity (PEI) and Production Carbon Intensity (PCI) would be reported (on a company basis) in their Climate Change Action Plans/Progress Reports. Benchmarking is a process commonly used in industry as a method to readily and reasonably compare one operation, facility, or plant with another. Although the PEI and PCI may be used to compare similar facilities, they cannot be used to gauge the performance of one company with respect to another since product mixes can vary substantially. Therefore, PEI and PCI calculated on a company basis only should be used to measure a companys performance over time (i.e., with respect to a base year). Benchmarking over time (i.e., comparison with base year results) can provide a measure of the effectiveness of any improvements taken within the operation itself and against the performance of its peers. By determining the amount of energy used or emissions released to produce a unit volume of product for sale, be it oil, natural gas, natural gas liquids (NGLs) or sulphur, the upstream petroleum industry can demonstrate its effectiveness in reducing energy use while consumer demand for its products increases.1 The upstream petroleum industry also is faced with the dilemma of increasing energy used per unit of production (resulting in additional emissions of greenhouse gases) as oil or gas reservoirs decline, but also given the likely mix of product in the future, i.e., more heavy oil, sour gas and crude bitumen production. Reinjection of produced water associated with crude oil production, or injecting water to maintain reservoir pressure as a field declines, requires more energy, as does adding field compression to move natural gas from wells to a processing plant.

1

The National Energy Board Report Canadian Energy Supply & Demand 1993-2010 Current Technical Case forecasts that Canada's energy requirements will increase over the period 1990 to 2000 due to Canada's increasing population and probably improved economic growth. Estimated growth of Canada's natural gas production is 52.9 percent, crude oil growth is 34.4 percent, and natural gas liquids growth is 92.1 percent. Much of this increase in natural gas will be exported to the United States and will serve to reduce U.S. GHG emissions and improve air quality.

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Estimating Greenhouse Gas Emissions

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Table 2-1 below shows upstream oil and gas production along with energy use in each province of operation.Table 2-1: Upstream Oil and Gas Production and Energy Use in 1998 and 1999 Description Alberta 19986 3

1999

Sask. 1998

1999

B.C. 1998

1999

Natural Gas in 10 m /yr Light & med. crude 103 m 3/yr Heavy crude 103 m 3/yr Bitumen crude 103 m3/yr Synthetic crude 103 m3/yr Condensate 103 m3/yr Pentanes plus 103 m3/yr Ethane 103 m3/yr Propane 103 m3/yr Butane 103 m3/yr NGLs 103 m 3/yr Sulphur in 103 tonnes/yr Vented gas in 106 m3/yr. Flared raw gas in 106 m 3/yr. Flared processed gas: 106 m 3/yr. Raw Fuel gas in 106 m3/yr. Processed Fuel gas in 106 m 3/yr. ATCO power GWhr TransAlta power GWhr Electric power purchased GWhr Total Production in 106 m 3OE Total energy used GJ PEI in GJ/m 3OE

172,64 4 35,243 14,532 16,364 17,871 393 8,586 10,768 5,674 2,729 19,087 7,186 151 1,893 26 9,793 2,784 4,352 3,225 7,577 289 586 2.03

175,27 9 31,332 14,210 14,171 18,