calculating greenhouse gas emissions

GUIDE

Calculating Greenhouse Gas Emissions

April 2003

2003-0003

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. John’s, Newfoundland Canada A1C 1B6 Tel (709) 724-4200 Fax (709) 724-4225

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

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 Canada’s 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 user’s sole risk, regardless of any fault or negligence of CAPP and Altus Environmental Engineering Ltd.

April 2003 Estimating Greenhouse Gas Emissions

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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 Contents

Overview ....................................................................................................................................i

1 CAPP Guide to Baselines and Calculating Greenhouse Gas Emissions .............. 1-1

1.1 Introduction.................................................................................................. 1-1 1.2 Establishing a Base Year............................................................................. 1-3 1.3 Emissions from Non-operated Facilities .................................................... 1-3 1.4 Baseline Adjustment.................................................................................... 1-4 1.5 Global Warming Potential Factors ............................................................. 1-5 1.6 Short-Form Emissions Calculation Method............................................... 1-6 1.7 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

1.8 Fugitive Emission Estimates Derived from the GFC Method................1-27 1.9 Emissions from Cogeneration Systems....................................................1-33 1.10 Emissions from Off-shore Operations......................................................1-35 1.11 Conversion Factors....................................................................................1-37

2 Benchmarking........................................................................................................... 2-1 2.1 Introduction.................................................................................................. 2-1 2.2 Reporting Basis............................................................................................ 2-3 2.3 Calculating the Product Energy Intensity (PEI) ........................................ 2-5 2.4 Calculating the Product Carbon Intensity (PCI) ........................................ 2-6

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

3.1 Introduction.................................................................................................. 3-1 3.2 Reporting Success Stories ........................................................................... 3-1 3.3 Sample Calculations .................................................................................... 3-1


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Tables

Table 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 industry’s 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 Operations

Source GHG Oil Battery

Gas Well GGS Sweet

GP Sour GP

Gas venting from petroleum storage (tanks) CH4 X

Casing gas venting CH4 X

Fugitive emissions (equipment & piping) CH4 X X X X X

Fugitive emissions (equipment & piping) CO2 X

Gas instrument and injection pump venting CH4 X X X

Engine gas starter venting CH4 X X X X

Glycol dehydrator reboiler venting CH4 X X X X

Glycol dehydrator stripping gas venting CH4 X X X

Venting of CO2 from gas sweetening CO2 X

Combustion: boilers and heaters CO2, CH4, N2O X X X X X

Combustion: engines and turbines CO2, CH4, N2O X X X X X

Combustion: flaring and incineration CO2, CH4, N2O X X X X X

Maintenance: piping/equipment blowdown CH4 X X X X X

Operations: well blowdown, equipment failure

CH4 X X X X X

Indirect emissions: electricity purchase 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 company’s 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 company-operated facilities on a gross production basis. The reasoning for this is:

• 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.


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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. The


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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 company’s 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 “Canada’s National Action Program on Climate Change”, 1995, page 6.

Table 1-2: Global Warming Potential (GWP) Factors

Gas 100 year GWP

CO2 1

CH4 (methane) 21.0

N2O (nitrous oxide) 310

Hydrofluorocarbons: HFC-23 11700

Hydrofluorocarbons: HFC-125 2800

Hydrofluorocarbons: HFC-134a 1300

Hydrofluorocarbons: HFC-152a 140

PFCs: Tetrafluoromethane (CF4) 6500

PFCs: Hexafluoromethane (C2F6) 9200

Sulphur Hexafluoride: SF6 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.


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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.


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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 company’s 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.


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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 user’s 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);


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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 CO2 g/m3 fuel

N2O g/m3 fuel

CH4 g/m3 fuel

NOx g/m3 fuel

CO2E g/m3 fuel

Uncontrolled

With low NOx burners

1891

0.0347

0.0101

0.0363 4.413

2.207

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 Canada’s “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 Model Thermal Efficiency (HHV)

CO2 % CO ppm (g/kWh)

NOx ppm (g/kWh)

VOCs ppm (g/kWh)

PM (g/kWh)

Cleaver Brooks CB 75 – 78 % 200 (0.232)

100 (0.186)

40 (0.025)

(0.015)

CB-LE 200 (0.232)

20 – 60 (.037-.108)

40 (0.025)

(0.015)

CBW 200 (0.232)

100 (0.186)

40 (0.025)

(0.015)

FLX 0 – 50 40 – 60

5 200 (0.232)

100 (0.186)

40 (0.025)

(0.015)

IWT 200 (0.226)

110 (0.201)

IWT w/ FLR

Saskatoon prior to 1995

74 – 77 % 9 > 50 ppm

80 ppm

after 1995 75 – 78 % 9 0 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.


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Table 1-5: Energy Content of Fuels

Fuel Energy Content HHV (Gigajoules)

Natural gas (per 103 m3) 37.4

Natural gas, raw/unprocessed (per 103m3) 46.0

Liquid ethane (per m3) 18.5

Liquid propane (per m3) 25.4

Liquid butane (per m3) 28.7

NGL (natural gas liquids, per m3) 27.5

Crude oil, light & medium (per m3) 38.5

Crude oil, heavy (per m3) 41.4

Crude oil, bitumen (per m3) 42.8

Aviation gas (per m3) 33.5

Motor gasoline (per m3) 34.7

Kerosene (per m3) 37.7

Diesel fuel (per m3) 38.7 Taken from ERCB 91-A and Environment Canada’s “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 = 360 / 365 [days/yr] = 0.986

Output rating = 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/yr


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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 5

Inlet 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 CO2 /m3 gas

N2O g/m3 gas

CH4 g/m3 gas

CO2E g/m3 gas

Reciprocating engine:

2-cycle lean burn

4-cycle lean burn

4-cycle rich burn turbo-charged

1769

1769

1769

0.765*

0.984*

0.533*

23.31

20.09

3.69

2496

2496

2012

Gas Turbine 1769 0.077* 0.138 1796

Large bore diesel engines (> 600 hp)

2.744 kg/l 0.0004 kg/l 0.00014 kg/l 2.871 kg/l

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.


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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 Carburetor Setting

CO2 g/kWh

NOx g/kWh

CO g/kWh

CH4 g/kWh

Excess Air Ratio

AT25GL Standard 580.8 1.34 3.02 9.39 1.74 AT27GL Standard

Ultra lean

526.9 2.01 1.68

2.28 2.01

6.03 4.16

1.74 2.00

VHP G, GSI Lowest manifold* Equal NOx & CO Catalytic conv.

Standard**

581.29 581.29 581.29 581.29

11.39 16.09 17.43 29.5

42.91 16.09 12.07 2.01

2.61 2.61 2.28 1.68

0.97 0.99 0.99 1.06

VHP 3524 GSI Equal NOx & CO 576.13 18.77 18.77 1.14 0.99 VHP 7044 GSI Catalytic conv.

Standard** 573.7 20.12

30.84 17.43 2.68

1.07 0.80

0.99 1.06

VHP 5794 GSI Equal NOx & CO Catalytic conv.

Standard**

568.7 18.1 19.44 29.5

17.43 14.75 4.02

3.42 3.29 2.75

0.99 0.99 1.06

VHP GL Standard 592.3 2.01 3.55 6.03 1.74 VGF Model G Lowest manifold*

Equal NOx & CO Catalytic conv.

Standard**

575.0 16.09 20.12 21.46 37.55

37.55 20.12 13.41 1.07

2.28 2.28 2.28 1.41

0.97 0.98 0.99 1.12

VGF Model GSID Catalytic conv. 575.0 21.46 10.73 1.68 0.99 VGF GL, GLD

11:1 CR Std.: high speed

turbo T.A. Luft emissions

575.0 3.49 1.68

2.35 2.13

5.7 4.09

1.53 1.59

VGF GL 8.7:1 CR Std.: high speed turbo

575.0 2.68 2.28 4.09 1.53

VSG G, GSI, GSID

Lowest manifold * Equal NOx & CO Catalytic conv.

Standard**

566.8 13.41 18.71 20.12 33.53

50.95 18.77 16.09 1.21

3.42 3.42 3.08 2.28

0.97 0.98 0.99 1.10

F1197G G Lowest manifld* Equal NOx & CO Catalytic conv.

Standard**

13.41 18.77 18.1 29.5

52.3 18.77 22.79 1.74

3.35 2.61 2.61 1.27

0.97 1.0

0.99 1.06

F8176 G Lowest manifold* Equal NOx & CO Catalytic conv.

Standard**

11.39 17.43 16.09 24.14

50.96 17.43 20.12 1.74

2.61 2.28 2.28 2.28

0.97 1.0

0.99 1.06

*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 Power kW

Speed rpm

% O2 NOX g/kWh

CO2 g/kWh

HC g/kWh

3412 SITA 447 1800 1.5 22.4 436

3508 SITA 384 1200 7.7 2.68 574

3508 SITA 470 1400 8.0 2.68 590

3512 SITA 604 1200 8.2 2.68 579

3512 SITA 705 1400 7.7 2.68 595

3516 SITA 809 1200 8.3 2.68 567

3516 SITA 943 1200 7.9 2.68 581

3606 SITA 1242 1000 12.3 0.94 347

3608 SITA 1659 1000 12.3 0.94 347

3612 SITA 2487 1000 12.3 0.94 347

3616 SITA 3315 1000 12.3 0.94 347

G398 TALCR 522 1200 2.0 24.54 1.48

G398 TAHCR

Catalyst

522

522

1200

1200

2.0

0.5

20.38

12.61

1.21

2.15

G398 TAHCR 32C

(low emissions)

522 1200 6.2 6.71 1.88

HC is hydrocarbons.

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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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, NOX 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 CO2 g/m3 fuel

N2O g/m3 fuel

CH4 g/m3 fuel

CO2E g/m3 fuel

Sales or processed 1853 0.004* 13.6 2,140

Raw or unprocessed 2281 0.004* 10.85 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 multiplied


1-17

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 hydro-electricity), 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 Generation

Province 1990 CO2E kg/MWh

1995 CO2E kg/MWh

1996 CO2E kg/MWh

1999 CO2E kg/MWh

2000 CO2E kg/MWh

2001 CO2E kg/MWh

British Columbia * * * * 42 56

N.E. B.C. (supplied by ATCO)

1130 1089 1058 1089 1074 1040

Alberta (average) 1000 1035 1025 1007 1020 1005

ATCO (Alberta) 1074 1040

EPCOR (Alberta) 820 790

TransAlta (Alberta) 1070 1070

Saskatchewan 750 860 860 880 917 910

Manitoba * 12 12 11 25.3 29.0

Ontario 280 130 150 240 283.7 303.8

Quebec * * * 1.4 2.09 14.5

Nova Scotia * * * 780 864 852.5

New Brunswick * * * 546 * *

Newfoundland * * * 190 136 277.8 * 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.


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Table 1-11: Fugitive Emissions Factors in Vapour Service

Fitting Gas Facilities: kg/hr/fitting

Oil Facilities: kg/hr/fitting

Valves (sweet gas) 0.04351 0.01417

Valves (sour gas) 0.00518

Flanges/Connectors (sweet) 0.00253 0.00079

Flanges/Connectors (sour) 0.00031

Compressor seals 0.80488 0.80488

PRVs (vented to atmosphere) 0.12096 0.12096

Open-ended lines 0.00373 0.00373

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) = Σ(Na x Fa) 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 Operating Pressure = 140 kpag

Operating Pressure = 240 kpag

Transmitter 0.12 0.2

Controller 0.6 0.8

I/P Transducer 0.6 0.8

P/P Positioner 0.32 0.5

I/P Positioner 0.4 0.6

Chem. inj. pumps (diaphragm) 0.4 0.6

Chem. injection pumps (piston) 0.04 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 2-2, 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., Level-Trol 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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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 CH4 Emission factor Tonnes CH4 / 106 m3 gas processed

Gas pump without a flash separator 0.2264

Gas pump with a flash separator 0.0054

Electric pump without a flash separator 0.0588

Electric pump with a flash separator 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 GRI’s 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 required


1-23

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 Description (Solution gas is off stock tanks)

THC Emission Factor m3/m3 of oil production

Conventional Oil Solution gas (no treater in process) 5.0

Solution gas (with treater in process) 3.2

Solution gas (with gas boot in process)

0.45

Primary Heavy Oil Casing gas produced:

Casing gas vented (63.2%)

59.2

37.4

Solution gas produced:

Solution gas vented (38.7%):

1.0

0.38

Thermal Heavy Oil Casing gas produced:

Casing gas vented (4.7%):

53.9

2.53

Solution gas produced:

Solution gas vented (0%)

8.3

0.0

Crude Bitumen Casing gas produced:

Casing gas vented (18%):

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,


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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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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.) Mv = 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 4.3-4)

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

http://www.epa.gov


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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) Mv = 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 = 23

Using

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:


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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/yr

Table 1-15: Generic or Average Connector Counts by Equipment/Process Type

Equipment/Process Light Oil Facilities

Heavy Oil Facilities

Gas Production

Gas Plants

Offshore Platforms

Overall Onshore Average

Well 53 44 60 195 52

Header 389 108 105 145 310 187

Heater 146 147 197 147

Separator 111 41 160 48 299 90

Filter 122 269 122

Chiller 94 94

Meter 91 55 160 383 102

Dehydrator 119 155 105 210 126

Fractionation 81 81

Sulphur 109 144 127

Compressor 163 195 129 417 162

Vapour Recovery 78 162 78

Scrubber 105 120 81 177 102

Flare 114 221 376 168


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Table 1-16: Generic or Average Valve Counts by Equipment/Process Type



Gas Production

Gas Plants

Offshore Platforms


Well 13 8 16 61 12

Header 109 17 26 38 82 48

Heater 28 22 45 25

Separator 24 10 30 17 81 20

Filter 19 42 19

Chiller 25 25

Meter 21 13 41 84 25

Dehydrator 26 31 25 46 27

Fractionation 23 23

Sulphur 34 42 38

Compressor 34 31 26 88 30


Scrubber 22 24 23 39 23

Flare 35 71 74 53


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Table 1-17: Generic or Average Open-ended Line Counts by Equipment/Process Type



Gas Production

Gas Plants

Offshore Platforms


Well 2 3 3 20 3

Header 4 4 4 4 14 4

Heater 3 4 4 4

Separator 3 2 5 3 11 3

Filter 3 8 3

Chiller 1 1

Meter 4 2 13 10 6

Dehydrator 5 3 5 4

Fractionation 2 2

Sulphur 7 3 5



Scrubber 3 2 2 5 2

Flare 5 1 11 3

Table 1-18: Generic or Average Compressor Seal Counts by Equipment/Process Type



Gas Production

Gas Plants

Offshore Platforms



Vapour Recovery 2

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.


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Table 1-19: Generic or Average PRV Counts by Equipment/Process Type



Gas Production

Gas Plants

Offshore Platforms


Well 1 1

Header 3 2 3

Heater 2 2 2

Separator 1 3 1 2

Filter 2 0

Chiller 0

Meter 2 2 4 2

Dehydrator 2 1 2

Fractionation 1 1

Sulphur 0

Compressor 3 4 3 4

Vapour Recovery 1 0

Scrubber 2 1 2

Flare 1 0

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.


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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) kWh


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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 isn’t 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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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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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 ºR (ºF+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 Mobile Source Emission Factor kg CO2E/litre

Diesel oil Tankers 2.856

Fuel Oil Tankers 3.223

Turbo fuel Helicopter 2.629

Aviation gas Sea plane 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


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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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Form GHG – SF Rev. 3 Calculation of Greenhouse Gas Emissions

Company/Facility: ___________________________ Reporting Year: _______ Prepared by: _______________________________ Date: _____________ 1 Combustion Emissions: Line # Description

(on a gross basis for company operated facilities only) CO2E factor

CO2E tonnes/yr

1.1 Total natural gas burned: _______________ 103 m3/yr x 2.06n = 1.2 Total propane liquid burned: _____________103 m3/yr x 1,644.0m = 1.3 Total diesel fuel burned: _______________103 m3/yr x 2,871.0 = 1.4 Total raw flared gas volumea: _______________103 m3/yr x 2.51 = 1.5 Total electricity purchased in Alberta:___________MWh/yr x 1.005 = 1.6 Total electricity purchased in B.C.:_____________MWh/yr x 0.056 = 1.7 Total electricity purchased in N.E. B.C.:_________MWh/yr x 1.040 = 1.8 Total electricity purchased in Sask.:____________MWh/yr x 0.910 = 1.9 Total electricity purchased in Man.:___________MWh/yr x 0.029 =

1.10 Total electricity purchased in Ontario:______MWh/yr x 0.304 = 1.11 Subtotal (Add Lines 1.1 to 1.10): =

2 Fugitive and other Methane Lossesb: Line # Description

(on gross thru-put basis for company operated facilities) Emission

Factor CO2E

tonnes/yr 2.0 Measured vented gas volumec: _______103 m3/yr x _______d x 14.25 = 2.1 Light oil sales: _________________ 103 m3/yr x 38.0e = 2.2 Conventional heavy oil sales: ____________103 m3/yr x 529.4f = 2.3 Thermal recovery heavy oil sales: _________103 m3/yr x 27.8g = 2.4 Sweet gas plant sales: _______________ 103 m3/yr x 0.0694m = 2.5 Sour gas recovery plant sales:____________103 m3/yr x 0.0576m = 2.6 Sour gas plant sales: ________________ 103 m3/yr x 0.0634m = 2.7 Straddle plant NGL sales: ____________ 103 m3/yr x 1.52m = 2.8 Subtotal (Add Lines 2.0 to 2.7): =

3 CO2 Vented from Sour Gas Processing: Line # Description

(on a gross basis for company operated facilities) CO2 mole fraction

CO2 tonnes/yr

3.1 Sour gas processed: _____________ 103 m3/yr x 1.86 x h = 3.2 Sour gas processed: _____________ 103 m3/yr x 1.86 x h = 3.3 Total CO2 in inlet gas stream (Add Lines 3.1 + 3.2): = 3.4a Sweet gas sales from sour plants:___________103m3/yr x 0.0372i = 3.4b Sweet gas sales from sour plants:___________103m3/yr x ____j = 3.4c CO2 injected downhole: ___________103m3/yr x _______ k x 1.86l = 3.5 Total CO2 Vented: Lines 3.3 - (3.4a+b+c): Subtotal =


1-39

4 Total CO2E Emissions: Add Lines 1.11 + 2.8 + 3.5 = ______________ tonnes/yr / 1000 = ___________ ktonnes/yr Notes: a Includes flared gas from solution gas burning, process upsets, and well testing. b Except for line 2.0, listed emission factors include methane emissions from pipe fitting leaks,

solution gas venting, and instrument venting. c 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. d This is the methane content (volume or mole fraction) of the vented gas. e 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.

f 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.

g 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 = Solution gas vented in m3/m3 oil production CGv = Casing gas vented in m3/m3 oil production MC = Methane content in volume fraction GWP = Global Warming potential for methane = 21.0 h Inlet gas CO2 content in volume or mole fraction. i Generic pipeline specification for CO2. j CO2 slippage to pipeline sales if different than “i” above. k CO2 content (volume or mole fraction) of acid gas being injected downhole. l Density of CO2 (in tonnes/103m3) at 15oC and 101.3 kpaa.


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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).


1-41

Form GHG – SS Calculation of Greenhouse Gas Reductions from Projects

Company: Facility: LSD: Contact: Title: Phone: Project Title: Description: Start-up Date: MMDDYY Duration: years

1.0 Fuel Gas Conservation (Combustion) t CO2E/yr Method 1.1 Reduction from boilers: ______103 m3/yr x 1.903 = _________ ______ 1.2 Reduction from recip. engines: ______103 m3/yr x 2.496 = _________ ______ 1.3 Reduction from turbines: ______103 m3/yr x 1.796 = _________ ______ 1.4 Reduction from flare make-up: ______103 m3/yr x 2.140 = _________ ______ 2.0 Fuel Gas Conservation (Venting) MMF 2.1 Reduction from LDAR survey: _____103 m3/yr x _____ x 14.25 = _________ ______ 2.2 Reduction from gas instruments:_____103 m3/yr x _____ x 14.25 = _________ ______ 2.3 Reduction from chemical pumps_____103 m3/yr x _____ x 14.25 = _________ ______ 2.4 Reduction from dehy. pumps: _____103 m3/yr x _____ x 14.25 = _________ ______ 2.5 Reduction from gas stripping: _____103 m3/yr x _____ x 14.25 = _________ ______ 3.0 Raw Gas Conservation (Combustion) 3.1 Reduction from flaring: ______103 m3/yr x 2.51 = _________ ______ 3.2 Reduction from flaring: ______103 m3/yr x ______ (CEF) = _________ ______ 4.0 Raw Gas Conservation (Venting) MMF 4.1 Reduction from LDAR survey: _____103 m3/yr x _____ x 14.25 = _________ ______ 4.2 Reduction from dehy. reboiler stack: _____103 m3/yr x _____ x 14.25 = _________ ______ 4.3 Reduction from process venting: _____103 m3/yr x _____ x 14.25 = _________ ______ 5.0 CO2 Venting Conservation (from Gas Sweetening) 5.1 Reduction in acid gas incineration, venting or flaring: ________103 m3/yr x _______ CO2 mole fraction x 1.86 = _________ ______ 6.0 Purchased Electric Power Conservation PEEF 6.1 Reduction in motor power:____ hp x _____ hrs/yr x 0.000746 x _____ = _________ ______ 6.1 Reduction in other power: ____ kW x ____ hrs/yr x 0.001 x _____ = _________ ______ 7.0 Increase in Energy Use 7.1 Increase in boiler fuel gas: ______103 m3/yr x 1.903 = _________ ______ 7.2 Increase in recip. engine fuel gas:______103 m3/yr x 2.496 = _________ ______ 7.3 Increase in turbine fuel gas: ______103 m3/yr x 1.796 = _________ ______ 7.4 Increase in flared gas: ______103 m3/yr x 2.51 or x ____ (CEF) = _________ ______ 7.5 Increase in electrical motors:____hp x ____ hrs/yr x 0.000746 x _____7 = _________ ______ 7.6 Increase in electric power:____ kW x ____ hrs/yr x 0.001 x _____7 = _________ ______


1-42

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.


2-1

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 company’s 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.


2-2

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 1998

1999

Sask. 1998

1999

B.C. 1998

1999

Natural Gas in 106 m3/yr 172,644

175,279

6,002 21,100 21,200

Light & med. crude 103 m3/yr

35,243 31,332 13,777 2,766 2,420

Heavy crude 103 m3/yr 14,532 14,210 9,376 0 14 Bitumen crude 103 m3/yr 16,364 14,171 Synthetic crude 103 m3/yr 17,871 18,767

Condensate 103 m3/yr 393 419 Pentanes plus 103 m3/yr 8,586 8,493 17 476 434

Ethane 103 m3/yr 10,768 12,987 0 140 0 Propane 103 m3/yr 5,674 5,729 40 512 252 Butane 103 m3/yr 2,729 2,902 20 309 197 NGLs 103 m3/yr 19,087 19,501 280

Sulphur in 103 tonnes/yr 7,186 7,473 941 925 Vented gas in 106 m3/yr. 151 238

Flared raw gas in 106 m3/yr.

1,893 1,624 578 199 120

Flared processed gas: 106 m3/yr.

26 60

Raw Fuel gas in 106 m3/yr. 9,793 10,020 895 599 644 Processed Fuel gas in 106

m3/yr. 2,784 3,131

ATCO power GWhr 4,352 4,566 TransAlta power GWhr 3,225 3,197

Electric power purchased GWhr

7,577 7,763 1,242 1,300 39 37

Total Production in 106 m3OE

289 287 30 0 25 24

Total energy used GJ 586 597 65 5 32 30 PEI in GJ/m3OE 2.03 2.082 2.155 1.293 1.243

Data obtained from “Alberta Energy Resources Industries, EUB 99-3, Statistical Series” The industry average PEI (across 3 provinces) was 1.985 GJ/m3OE in 1998 and 2.016 GJ/m3OE in 1999.

Companies are encouraged to benchmark similar types of operations as follows: sweet gas gathering and processing, sour gas gathering and processing, light and medium crude oil production, conventional heavy oil production, thermal heavy oil production, crude bitumen production and oil sands.


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2.2 Reporting Basis

Both benchmarking performance indicators and success stories should be reported in company Action Plans to be submitted to the Climate Change Task Group Secretariat. As a minimum, both PEI and PCI must be reported on a company basis (simplified forms are included to assist companies).

The following criteria should be used when calculating performance indicators:

1. The CAPP Climate Change Voluntary Challenge Principles (see Section 1.4 of Guide) are applicable to the issue of benchmarking.

2. Benchmarking will apply to company operated facilities only and will be based on gross facility throughput, not production share.

3. If possible, benchmarking should be done at the facility level, where a facility includes all contributing wells, gathering systems, storage, metering and treating components. Total company benchmarking is the total of all company emissions or energy used divided by total sales production. Fuel gas and vented volumes are included from the well, battery, gas gathering and plant level. However, product sales are only included at the end of the processing cycle (in this case the gas plant). This example assumes that the gas receipts into the gas plant include all the production from the gas gathering and battery levels.

4. If companies choose to further breakdown data to compare facilities that are more practically comparable, that breakdown would be (where HHV is the Higher Heating Value of the product): − Light and medium oil production (energy content HHV = 38.5GJ/m3); − Heavy crude oil production (energy content HHV = 41.4 GJ/m3); − Sweet natural gas production (no H2S present (HHV = 37.4GJ/103m3)); − Sour natural gas production with sulphur recovery(any facility where H2S

in the gas must be removed to meet pipeline specification (natural gas product with HHV = 37.4GJ/103m3));

− Sour natural gas production without sulphur recovery(any facility where H2S in the gas is removed and flared (natural gas product with HHV = 37.4GJ/103m3)); and,

− Crude bitumen production (energy content HHV = 42.8GJ/m3). 5. At this time, no effort will be taken to break production down using royalty

definitions, so, for example, there is no “shallow natural gas“ designation. 6. Benchmarking will be reported in metric units: PEI in GJ/m3 of oil equivalent

of product sold; PCI in tonnes of CO2E/m3 of oil equivalent of product sold. 7. As the Global Warming Potential of each GHG is subject to change,

companies doing the Detailed Emissions Calculations Method, should report GHG inventories in terms of separate masses of CO2, CH4, and N2O to more easily facilitate recalculating CO2E PCI over time.

8. Energy used will include electricity purchased, fuel combusted, flared gas, well testing and energy used by the service sector (i.e., if the operator provides the fuel or were directly billed for the fuel used). Third party energy or fuel use will not be included nor will commercial air travel as these uses will be


2-4

accounted for elsewhere. Fuel combusted in head office buildings and fleet vehicles will also be excluded.

9. If vented gas is reported to the regulator as flared gas, this value will be included in the PEI calculation and PCI even if it is not burned. This will ensure industry practice matches regulatory practice.

10. Factors to convert different facilities’ products to an oil equivalent volume would be based on the product’s energy or heating value rather than on a product price basis. Refer to Table 2-2 for the applicable conversion factors.

11. Fugitive emissions will not be included in the PEI calculations, but will be included in the CO2 inventory and PCI.

12. Reporting should draw heavily on data that is available or reported to regulators (e.g., electricity usage statements and Alberta Energy and Utility Board “S” reports). Emissions inventories and energy indexes associated with any international operations (outside Canada) should be reported separately.

13. Vented CO2 and non-combusted CH4 emissions need to be reported in the PCI calculation. Vented sources of CO2 include sweetening, upgrading (mainly Syncrude, Suncor and Husky). Fugitive CO2 and any fire flood or enhanced oil recovery venting is considered to be negligible and will therefore not be considered.

Table 2-2: Oil Equivalent (OE) Conversion Factors (on an energy equivalent basis)

Product m3OE Conversion

Light oil in m3 1.0

Heavy crude in m3 1.075

Crude bitumen in m3 1.111*

Natural gas in 1000 m3 0.971

Liquid ethane in m3 0.48

Liquid propane in m3 0.66

Liquid butane in m3 0.75

Liquid condensate C5+ in m3 0.85

NGL in m3 (gas plant NGL sales) 0.72

NGL in m3 (straddle plant production) 0.69

Solid sulphur in tonnes 0.24 *Heavy oil operators are advised to use their own specific bitumen HHV (higher heating value) in order to determine their own m3OE factor as bitumen heating values may vary greatly between fields. Use the following formula to determine your own m3OE factor: m3OE = (Specific Bitumen HHV in GJ/m3 ) / 38.5


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2.3 Calculating the Product Energy Intensity (PEI)

The equation used to calculate the PEI is shown below:

Equation #16

PEI (GJ/m3 OE) = gas flared (GJ) + fuel burned (GJ) + electric power purchased (GJ)

m3 oil + m3 OE gas + m3 OE NGL + m3 OE sulphur

All the volumes in the denominator of the above equation refer to sales volumes sent to market or product deliveries and exclude quantities of sweetened gas used for on-site fuel. Shrinkage and metering error are also excluded from PEI and PCI calculations.

Form GHG - PEI, at the end of this Section, may be used to calculate the Production Energy Intensity.

Industry average PEI values for 1995 are shown in Table 2-3. CAPP will endeavour to update these values in the future.

Table 2-3: Upstream Oil and Gas Industry Average PEI Values (1995 values)

Process / Product Type Industry Average PEI GJ/m3OE

Sweet natural gas 1.4

Sour gas / natural gas 2.2

Sulphur recovery / natural gas 3.7

Light oil 2.12

Conventional heavy oil / crude 1.2

CSS Thermal heavy oil / bitumen 8.5*

SAGD Thermal heavy oil / bitumen 6.6*

Straddle plant / NGLs 3.4 * Year 2001 weighted average data obtained from CAPP survey prepared by Clearstone Engineering. CSS is cyclic steam stimulation and SAGD is steam assisted gravity drainage


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2.4 Calculating the Product Carbon Intensity (PCI)

The equation used to calculate the PCI is shown below:

Equation #17 PCI (tonnes CO2E/m3 OE) = CO2 vented (tonnes) + CO2E combustion (tonnes) + CO2E from electric power purchased (tonnes) + CO2E methane losses (tonnes) m3 oil + m3 OE gas + m3 OE NGL + m3 OE sulphur

The CO2E values shown in the above equation can be obtained from calculation performed on Form GHG - SF, found at the end of the previous Section. All the volumes in the denominator of the above equation refer to sales volumes sent to market or product deliveries and exclude quantities of sweetened gas used for on-site fuel.

Year 2001 data analysis show that the weighted average PCI for CSS and SAGD thermal heavy oil were 0.57 CO2E/m3OE and 0.37 CO2E/m3OE respectively. Form GHG - PCI may be used to calculate the PCI. This form follows the GHG – SF form at the end of the previous Section.


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Form GHG - PEI Rev. 1

Calculation of Production Energy Intensity (Part 1)

Company: _________________________________ Reporting Year: _______ Prepared by: _______________________________ Date: _____________ 1 Energy Consumption: Line # Description

(on a gross basis for company operated facilities only) Energy factor

GJ/year x 103

1.1 Total natural gas burned: _______________ 106 m3/yr x 37.4 = 1.2 Total propane liquid burned: ____________ 103 m3/yr x 25.4 = 1.3 Total diesel fuel burned: ______________103 m3/yr x 38.7 = 1.4 Total flared gas volume: _____________ 106 m3/yr x 46.0a = 1.5 Total electricity purchased:____________103 MWhr/yr x

(all provinces facilities operate in) 3.6

= 1.10 Subtotal =

2 Production Sales: Line # Description

(on gross thru-put basis for company operated facilities) m3OE Factor

m3OE/yr x 103

2.1 Light oil sales: ____________ 103 m3/yr x 1.0 = 2.2 Liquid condensate C5+ sales: ___________ 103 m3/yr x 0.85 = 2.3 Conventional heavy oil sales: ____________103 m3/yr x 1.075 = 2.4 Thermal recovery bitumen sales: _________103 m3/yr x 1.111 = 2.5 Sweet gas plant sales: ______________ 106 m3/yr x 0.971 = 2.6 Sulphur recovery gas plant sales:_____________106 m3/yr x 0.971 = 2.7 Sour gas plant sales: ________________ 106 m3/yr x 0.971 = 2.8 Gas plant NGL sales: ____________ 103 m3/yr x 0.720 = 2.9 Straddle plant NGL sales ____________ 103 m3/yr x

or straddle plant C2 (ethane) sales ____________ 103 m3/yr x plus straddle plant C3 sales ____________ 103 m3/yr x

0.69 0.48 0.66

2.10 Elemental sulphur sales: ____________ 103 tonnes/yr x 0.240 =

2.11 Subtotal = 3 Calculating PEI: Line # Description Quantity

3.1 Total energy used (Line 1.10 above) = 3.2 Total product sales (Line 2.11 above) = 3.3 PEI = Line 3.1 / Line 3.2 = GJ/m3OE

Notes: a Assumes flare gas content of 80% CH4, 15% C2H6 and 5% C3H8. Companies should calculate their own flare gas HHV based on their specific raw gas composition.


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Form GHG - PCI

Rev. 1 Calculation of Production Carbon Intensity

Company: _________________________________ Reporting Year: _______ Prepared by: _______________________________ Date: _____________ 1 CO2E Inventory Totals: Line # Description Note: values transferred from form GHG - SF

(on a gross basis for company operated facilities only) Quantity tonnes/yr

1.1 Total CO2E combustion emissions: Line 1.10 from Form GHG - SF: = 1.2 Total CO2E methane losses: Line 2.8 from Form GHG - SF: = 1.3 Total CO2 vented emissions: Line 3.5 from Form GHG - SF: = 1.4 Subtotal =

2 Production Sales: Line # Description

(on gross thru-put basis for company operated facilities) m3OE Factor

m3OE/yr x 103

2.1 Light oil sales: ________________ 103 m3/yr x 1.0 = 2.2 Liquid condensate C5+ sales: ___________ 103 m3/yr x 0.85 = 2.3 Conventional heavy oil sales: ____________103 m3/yr x 1.075 = 2.4 Thermal recovery bitumen sales: _________103 m3/yr x 1.111 = 2.5 Sweet gas plant sales: ______________ 106 m3/yr x 0.971 = 2.6 Sulphur recovery gas plant sales:_____________106 m3/yr x 0.971 = 2.7 Sour gas plant sales: ________________ 106 m3/yr x 0.971 = 2.8 Gas plant NGL sales: ____________ 103 m3/yr x 0.720 = 2.9 Straddle plant NGL sales ____________ 103 m3/yr x 0.69 =

or straddle plant C2 sales ___________103 m3/yr x 0.48 = plus straddle plant C3 sales __________ 103 m3/yr x 0.66 =

2.10 Elemental sulphur sales: ____________ 103 tonnes/ yr x 0.240 =

2.11 Subtotal = 3 Calculating PCI: Line # Description Quantity

3.1 Total CO2E emissions (Line 1.4 above) = 3.2 Total product sales (Line 2.11 above) x 1000 = 3.3 PCI = Line 3.1 / Line 3.2 = tonnes CO2E/m3OE


3-1

3 How to Build a Success Story

3.1 Introduction

Success stories are one means of capturing and reporting activities that member companies have undertaken to reduce greenhouse gas (GHG) emissions. Switching energy sources, improving the efficiency with which the current energy source is utilized, or reducing methane venting and fugitive emissions each have the potential to reduce net GHG emissions. These successes should be reported in your company Action Plan/Progress Report and to CAPP for inclusion in its overall industry progress report.

When calculating success stories, it is crucial to consider both the emissions prevented and the new emissions produced. There are few situations where a change in operation will have no new emissions. An example would be where a facility is decommissioned and the emissions reduce to zero. However, if a gas plant shuts down and the site remains active as a compressor station, emissions from the compressor station will be present and must be accounted for.

3.2 Reporting Success Stories

CAPP has provided this section to guide members in the steps necessary for reporting success stories.

The benefits of completing this exercise include:

• Collecting detailed project information that will validate its qualification for “early action credit” by governments;

• Validation of emission reductions claimed to-date (i.e., to the public and environmental groups);

• Creation of a list of reduction options that can be shared within the industry; • Ability to compare the cost of industry initiatives with third party CO2

offsets/credits; and, • Communication of new technologies that are available. Member companies are asked to pass on information collected for reduction options to CAPP. This information will be consolidated and published as a source of information to all CAPP members.

Success stories can also be used to calculate the increased revenue to the company by taking the amount of methane conserved from Form GHGRO – 02, Revision 2 and calculating the total value of methane conserved.

3.3 Sample Calculations

Calculations are done using factors from Chapter 1, Baselines and Calculating GHG Emissions.


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• Replacing electric submersible oil pumps with progressive cavity pumps in oil operations results in a saving of about 50 percent of the energy required for the submersible oil pumps. The energy used for the submersible oil pumps in Alberta would be calculated as follows: Power in kW = 30 hp x 360/365 days per year x 0.7457 KW/hp = 22.06 kW

CO2E = 22.06 kW x 24hrs/day x 365 d/yr. / 1000 MW/KW x 0.991 t/MWhr

= 191.5 tonnes CO2E/yr.

Power Saved = 15 hp x 360/365 days per year x 0.7457 KW/hp = 11.03 kW

CO2E Saved = 11.03 kW x 24 hr/day x 365 d/yr. / 1000 x 0.991 t/MWhr

= 95.76 tonnes/year

Net savings per pump = 95.76 tonnes CO2E/year

• Replacing two electric motors (in Alberta) with 2 high efficiency electric motors reduces electric energy consumption by 10 percent (saving of 37Mwhr/month). Units are in operation 363 days/year. CO2E = 37 Mwhr/month x 363/365 x 0.991 t/Mwhr x12 months/year

= 437.6 tonnes/year reduction

• Methane losses from glycol dehydrator are reduced through better operation

by 100 m3/day. The dehydrator is in operation 205 days/year.

Total methane loss reduction = 100 m3/d x 205 d/yr. =20,500 = 20.5 x 103 m3/yr

CO2E tonnes/yr. = 20.5 x 0.8 (methane content) x 0.678 t/103m3 x 21GWP (CO2/CH4)

= 233.5 tonnes/year reduced

(Where 0.8 is the assumed methane content of the natural gas used as instrument gas.)


3-3

Table 3-1: Checklist

Summary CAPP Voluntary Climate Change Challenge Action Element Checklist

Company Name _______________________________ Annual Oil Production ____________________________ Company Contact Name ________________________ Annual Gas Production ____________________________ Phone Number _______________________________ Action Plan Element Timing FAX Number _________________________________ Implemented est. time frame

During period to be implemented Action Elements 2001 2002 2003 Details/Comments (optional)

1. ENERGY EFFICIENCY a) Fuel Based -Increase fuel efficiency of gas processing equipment -Reduce fuel gas use through plant rationalization -Reduce fuel consumption -Shut down well flares and line heaters -Install new fuel controls -Install lean burn compressors / engines -Save fuel consumption by oil battery consolidation -Optimize combustion in facility boilers -Save fuel through reducing stack top temperature of of tail gas incinerator -Re-engineer continuous burning flare to an ignition on demand system -Save fuel by upgrading power boiler instrumentation -Treat compressor engines with zirconium ceramic to enhance performance b) Electricity Based -Install variable frequency drive on screw type compressor to use motor horsepower proportionately with compressor throughput -Power and fuel saved through installing variable speed


3-4

Action Plan Element Timing Implemented est. time frame During period to be implemented

Action Elements 2003 2004 2005 Details/Comments (optional)

1. ENERGY EFFICIENCY b) Electricity Based continued drives on steam condensing system and Bailey control system -Install high efficiency electric motors -Increase pumping unit eff. by installing high efficiency motors & conducting dynamometer surveys -Install high efficiency electric motors -Power consumption reductions -Increase suction pressure at compressor to reduce electrical power consumption -Reduce electrical load from plant rationalization -Install variable frequency drive on reciprocating compressor driver allowing 50% turndown on compressor throughput and power requirements when demanded -Reduce field pumping power by measuring motor thermal current on beam-pump units and closely matching motor horsepower connection to rod pump requirements - motor efficiency & power factor maxed. -Replace electric submersible oil pumps with progressive cavity pumps -Install maximum applicable power factor correction capacitors -Reduce power consumption by installing variable frequency drives on process cooling fans -Horsepower optimization on wells and field compressors c) Other -Replace three 60hp plunger pumps with one surplus 140hp unit - variable frequency drive will be installed if turndown is required


3-5

Action Plan Element Timing Implemented est. time frame During period to be implemented


1. ENERGY EFFICIENCY C) Other continued -Substitute CNG as fleet fuel -Conduct energy efficiency audit

2. ACID GAS and EOR INJECTION -Inject CO2 for enhanced oil recovery -Inject acid gas to deep well -Re-inject sour gas for pressure maintenance and CO2 reduction

3. COGENERATION AT OIL FACILITY (solution gas as fuel) -Use solution gas to power turbine and recover waste heat for process heat

4. SOLUTION AND VOC GAS CAPTURE (eliminates flare, vent, or fugitive emissions) -Collect previously flared solution gas at oil battery -Eliminate practice of venting low pressure gas in order to remove produced water from wellbore at low gas production wells - previously vented gas now produced to gathering system by using portable compressor to reduce line pressure -Reduced injection of methane in wells and satellites reducing methanol vented from gas powered pumps -Captured glycol dehydrator pump methane emissions -Replace instrument gas with instrument air -Institute comprehensive leak detection/repair program -Capture and recompress natural gas from large gathering lines when depressuring for maintenance - previously this gas was vented -Conserve flared gas


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Action Plan Element Timing Implemented Est. time frame During period To be implemented


4. SOLUTION AND VOC GAS CAPTURE continued -Reduce flaring/venting from testing and start-up practices -Use IFPEXOL process to remove water from gas stream; eliminates glycol dehydrator emissions -Install vapour recovery units -Install solution gas compressor to conserve solution gas -Install gas boots and incinerator to burn vent gas off oil and condensate tanks -Install compressor dehydration and sales line to conserve solution gas from oil wells -Recover previous flare solution gas from oil facilities -Reduce flaring by improved gas plant pigging practices -Tied in two wells and eliminated need for flaring -Install stock tank vapour collection system to flare previously vented gas -Switched compressor starters from gas to air -Consolidate oil battery eliminating flaring of soln gas -Install sour solution gathering system (oil batteries) -Collect previously flared solution gas -Replace gas driven pumping unit with electrical driver -Sections of pipeline are purged with nitrogen rather than methane -Capture and burn methane gas emissions -Upgrade vapour recovery by adding sales oil cooling

5. OTHER (Education, Awareness, etc.) -Initiate energy efficiency training for operators

calculating greenhouse gas emissions

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