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NATIONAL INVENTORY REPORT, 1990-2005: GREENHOUSE GAS SOURCES AND SINKS IN CANADA

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ANNEX 12: EMISSION FACTORS

• A12.1 Fuel Combustion
  • A12.1.1 Natural Gas and NGLs
  • A12.1.2 Refined Petroleum Products
  • A12.1.3 Coal and Coal Products
  • A12.1.4 Mobile Combustion
• A12.2 Fugitive Emission Factors: Coal Mining
• A12.3 Industrial Processes
  • A12.3.1 Mineral, Chemical, and Metal Industries
  • A12.3.2 Consumption of Halocarbons
  • A12.3.3 Other and Undifferentiated Production
• A12.4 Solvent and Other Product Use
• A12.5 Agriculture
• A12.6 Biomass Combustion
  • A12.6.1 CO₂
  • A12.6.2 CH₄
  • A12.6.3 N₂O
• References

This annex summarizes the development and selection of emission factors used to prepare the national GHG inventory.

A12.1 Fuel Combustion

A12.1.1 Natural Gas and NGLs

A12.1.1.1 CO₂

CO₂ emission factors for fossil fuel combustion are dependent primarily on the properties of the fuel and, to a lesser extent, on the combustion technology.

For natural gas, there are two major qualities of fuel combusted in Canada: marketable fuel (processed for commercial sale) and non-marketable fuel (unprocessed for internal use). Emission factors have been developed for these two categories (Table A12-1) based on data from the chemical analysis of representative natural gas samples (McCann, 2000) and an assumed fuel combustion efficiency of 99.5% (IPCC/OECD/IEA, 1997). The emission factor for marketable fuel matches closely with previous factors based on energy contents reported in Statistics Canada's RESD (Jaques, 1992). The factor for non-marketable natural gas is higher than that for marketable fuels as a result of its raw nature, which includes ethane, propane, and butane in addition to methane in the fuel mix.

NGL (ethane, propane, butane) emission factors were developed based on chemical analysis data for marketable fuels (McCann, 2000) and an assumed fuel combustion efficiency of 99.5% (IPCC/OECD/IEA, 1997). The emission factors are lower than those developed on the assumption of pure fuels (Jaques, 1992) owing to the presence of impurities in the fuels.

A12.1.1.2 CH₄

Emissions of CH₄ from fuel combustion are technology dependent. Sectoral emission factors (Table A12-1) have been developed based on technologies typically used in Canada. The factors were developed based on a review of emission factors for combustion technologies (SGA, 2000). The emission factor for producer consumption of natural gas was developed based on a technology split for the UOG industry (CAPP, 1999) and technology-specific emission factors from the U.S. EPA report AP 42 (EPA, 1996).

Notes:

1 Adapted from McCann (2000).

2 SGA (2000).

3 EPA (1996).

4 CAPP (1999).

N/A = not applicable

A12.1.1.3 N₂O

Emissions of N₂O from fuel combustion are technology dependent. Emission factors (Table A12-1) have been developed based on technologies typically used in Canada. The factors were developed from a review of emission factors for and an analysis of combustion technologies (SGA, 2000).

A12.1.2 Refined Petroleum Products

A12.1.2.1 CO₂

CO₂ emission factors for fossil fuel combustion are dependent primarily on the properties of the fuel and, to a lesser extent, on the combustion technology.

Emission factors have been developed for each major class of RPP based on standard fuel properties and an assumed fuel combustion efficiency of 98.5% (Jaques, 1992). Emission factors are presented in Table A12-2 for the majority of the RPPs and in Table A12-3 for petroleum coke and still gas.

Notes:

1 Jaques (1992).

2 SGA (2000).

N/A = not applicable

The composition of petroleum coke is process specific. Factors have been developed for both catalytic cracker-derived cokes and coke used in upgrading facilities. These factors (Table A12-3) have been developed based on data provided by industry to CIEEDAC in their Review of Energy Consumption reports on the refining and upgrading industry (CIEEDAC, 2003, 2006). The bulk of the coke consumed by refineries is catalytic cracker derived, and the emission factor is an average of petroleum coke and catalytic cracker coke emission factors. Factors were provided by industry on a mass basis and were converted to a volumetric basis for comparability with the national energy data using the density of coke provided by Statistics Canada.

Notes:

1 CIEEDAC (2003)

2 CIEEDAC (2006).

3 Nyboer (2006).

Factors for still gas (Table A12-3) from refining operations and upgrading facilities were also developed based on data provided by industry (CIEEDAC, 2003, 2006).

A12.1.2.2 CH₄

Emissions of CH₄ from fuel combustion are technology dependent. Emission factors have been developed (Table A12-2) based on technologies typically used in Canada. The factors were developed from a review of emission factors for and an analysis of combustion technologies (SGA, 2000).

The emission factor for petroleum coke was assumed to be the same for both types. An emission factor for still gas is not available, according to the SGA (2000) study.

A12.1.2.3 N₂O

Emissions of N₂O from fuel combustion are technology dependent. Emission factors for RPPs with the exception of petroleum coke have been developed (Table A12-2) based on technologies typically used in Canada. The factors were developed from a review of emission factors for and an analysis of combustion technologies (SGA, 2000). Emission factors for petroleum coke (Table A12-4) were based on 2006 IPCC default emission factors and were calculated on an annual basis using energy conversion factors provided by CIEEDAC (2003).

Note:

1 IPCC (2006).

A12.1.3 Coal and Coal Products

A12.1.3.1 CO₂

CO₂ emission factors for coal combustion are dependent primarily on the properties of the fuel and, to a lesser extent, on the combustion technology.

Coal emission factors (Table A12-5) have been developed for each province based on the rank of the coal and the region of supply. Emission factors have been developed based on data from chemical analysis of coal samples for electric utilities, which comprise the vast majority of coal consumption, and a fuel combustion efficiency of 99.0% (Jaques, 1992). The factors for coal were reviewed in 1999 because the supply and quality of coal used may change over time. Based on this review, it was determined that updated factors should be used for the more recent years. The factors for the year 1990 are based on supply and quality data from 1988 (Jaques, 1992). For 1998 to the present, factors are based on 1998 coal quality and supply (McCann, 2000). The factors for 1991-1997 are based on both studies. In order to address the change in emission factors introduced by the 2000 study, a linear interpolation method was used to derive coal- specific emission factors for 1991-1997 using the 1990 (Jaques, 1992) and 1998 (McCann, 2000) emission factors as the end points.

Table A12-5: CO₂ Emission Factors for Coal and Coal Products

Click here to view Table A12-5

Coke and coke oven gas emission factors were developed based on industry data (Jaques, 1992). The emission factors for coke represent coke use in the cement, non-ferrous metal, and other manufacturing industries.

A12.1.3.2 CH₄

Emissions of CH₄ from fuel combustion are technology dependent. Emission factors for sectors (Table A12-6) have been developed based on technologies typically used in Canada. The factors were developed from a review of emission factors for and an analysis of combustion technologies (SGA, 2000).

Note:

1 SGA (2000).

A12.1.3.3 N₂O

Emissions of N₂O from fuel combustion are technology dependent. Emission factors for sectors (Table A12-6) have been developed based on technologies typically used in Canada. The factors were developed from a review of emission factors for and an analysis of combustion technologies (SGA, 2000).

A12.1.4 Mobile Combustion

A12.1.4.1 CO₂

CO₂ emission factors for mobile combustion are dependent on fuel properties and are the same as those used for stationary combustion for all fuels (Table A12-7).

Notes:

1 Jaques (1992).

2 SGA (2000).

3 McCann (2000).

4 ICF (2004).

5 Barton & Simpson (1994).

6 See Chapter 3.

* Tier 1 or advanced control emission factors are used for Tier 2 vehicle populations.

** Gasoline CH₄ and N₂O emission factors (by mode and technology) are used for ethanol.

A12.1.4.2 CH₄

Emissions of CH₄ from fuel combustion are technology dependent. Emission factors for sectors have been developed (Table A12-7) based on technologies typically used in Canada. The factors were developed from a review of emission factors for and an analysis of combustion technologies (SGA, 2000).

A12.1.4.3 N₂O

Emissions of N₂O from fuel combustion are technology dependent. Emission factors for sectors have been developed (Table A12-7) based on technologies typically used in Canada. The factors were developed from a review of emission factors for and an analysis of combustion technologies (SGA, 2000).

A12.2 Fugitive Emission Factors: Coal Mining

Fugitive emissions from coal mining are predominantly CH₄. These emissions result from the release of entrained CH₄ from coal formation during mining. The emission factors have been developed (Table A12-8) based on mine-specific and basin-specific data (King, 1994). The development of the factors is described in the fugitive emissions section (Section 3.3) of the inventory report.

Source:

Adapted from King (1994).

A12.3 Industrial Processes

A12.3.1 Mineral, Chemical, and Metal Industries

Emissions from industrial processes are process and technology specific. The development of the factors for each source (Table A12-9) is described in the Industrial Processes chapter of the inventory report (Chapter 4).

Table A12-9: Emission Factors for Industrial Process Sources

Click here to view Table A12-9

A12.3.2 Consumption of Halocarbons

The use of halocarbons in various applications, such as AC, refrigeration, aerosols, foam blowing, solvents, fire extinguishing, and semiconductor manufacturing (for PFCs only), can result in HFC/PFC emissions.

As mentioned in Chapter 4 of this report, detailed 1995 HFC activity data were not available. Therefore, a modified Tier 1, instead of Tier 2, methodology was used to estimate 1995 HFC emissions for the following use types: aerosols, foam blowing, AC OEM, AC servicing, refrigeration, and total flooding systems. Shown in Table A12-10 are the emission factors used in the modified Tier 1 estimation method and the assumptions made to derive and to use these factors.

Table A12-11 summarizes emission rates used to estimate 1996-2005 HFC emissions and 1995-2005 PFC emissions.

Table A12-11: Emission Rates for Consumption of HFCs and PFCs

Click here to view Table A12-11

A12.3.3 Other and Undifferentiated Production

The use of fossil fuels as feedstock or for other non-energy uses may result in emissions during the life of manufactured products. To estimate CO₂ emissions from non-energy use of natural gas, an emission factor of 1522 g CO₂/m³ was used (Cheminfo Services, 2005). Tables A12-12 to A12-15 show industry-average emission factors used to develop CO₂ emission estimates for non-energy applications of solid and liquid fuels.

Table A12-12: CO₂ Emission Factors for Coal and Coal Products

Click here to view Table A12-12

Sources:

1. Jaques (1992).

2. IPCC/OECD/IEA (1997).

A12.4 Solvent and Other Product Use

N₂O emissions can result from its use as anaesthetic and propellant. The development of the emission factors shown in Table A12-16 is described in the Solvent and Other Product Use chapter of the inventory report (Chapter 5).

Source:

Cheminfo Services (2006.

A12.5 Agriculture

Emissions from agriculture result from enteric fermentation, manure management, and agricultural soils. Methodologies for generating these emission estimates are detailed in Section Section A3.4 of Annex 3. Emission factors and related information are given in Tables A12-17 to A12-21.

Notes:

1 Sources of emission factors (Tier 2) are country-specific (Boadi et al., 2004).

2 Sources of emission factors (Tier 2) are country-specific (Marinier et al., 2004).

3 Source of emission factors is IPCC/OECD/IEA (1997).

Notes:

1 Emission factors are derived from Boadi et al. (2004) following Good Practice Guidance provided by IPCC (2000) with modifications to capture changes in milk productivity.

2 Emission factors are derived following Good Practice Guidance provided by IPCC (2006).

Note:

1 ASAE Standards (ASAE, 2003).

Source:

Marinier et al. (2004).

Notes:

1 IPCC/OECD/IEA (1997), except where otherwise noted.

2 IPCC (2006).

A12.6 Biomass Combustion

A12.6.1 CO₂

Emissions of CO₂ from the combustion of biomass (whether for energy use, from prescribed burning, or from wildfires) are not included in national inventory totals. These emissions are estimated and recorded as a loss of biomass stock in the LULUCF Sector.

The emissions related to energy use are reported as memo items in the CRF tables as required by the UNFCCC. Emissions from this source are dependent primarily on the characteristics of the fuel being combusted. The methodology for deriving the emission factors (Table A12-22) is described in the biomass combustion section of the inventory report (see Section 3.4.2).

CO₂ emissions occur during forest wildfires and from controlled burning during forest conversion activities. The carbon emitted as CO₂ (CO2-C) during forest fires is considered in the forest carbon balance, whereas the CO₂-C emitted during controlled burns is reported under the new land-use categories. There is no unique CO₂ emission factor applicable to all fires, as the proportion of CO₂-C emitted for each pool can be specific to the pool, the type of forest and disturbance, and the ecological zone (see Section A3.5.2 in Annex 3).

A12.6.2 CH₄

Emissions of CH₄ from biomass fuel combustion are technology dependent. The emission factors (Table A12-22) were derived from a review of emission factors for combustion technologies (SGA, 2000). The factors are from the U.S. EPA AP 42 Supplement B (EPA, 1996).

Emissions of carbon as CH₄ (CH4-C) from wildfires and controlled burning are always equal to 1/90th of CO₂-C emissions.

A12.6.3 N₂O

Emissions of N₂O from biomass fuel combustion are technology dependent. The emission factors (Table A12-22) were developed from a review of emission factors for combustion technologies and an analysis of combustion technologies typically used in Canada (SGA, 2000). The factors are from the U.S. EPA AP 42 Supplement B (EPA, 1996).

N₂O emissions from wildfires and controlled burning are equal to 0.017% vol/vol of CO₂ emissions. Since both gases have the same molecular weight, the same ratio can be applied on a mass basis (see Section A3.5.2 in Annex  3).

Notes:

1. Emission ratio for CH₄ is 1/90th CO₂. See Annex 3.5 in Annex 3.

2. Emission ratio for N₂O is 0.017% CO₂. See Annex 3.5 in Annex 3.

3. CO₂ emissions from biomass combusted for energy purposes are not included in inventory totals, whereas CH₄ and N₂O emissions from these sources are inventoried under the Energy Sector. All GHG emissions including CO₂ from biomass burned in managed forests (wildfires and controlled burning) are reported under LULUCF and excluded from national inventory totals.

N/A = not applicable

Sources:

CO₂ Emission Factors:
Wood Fuel/Wood Waste -- EPA (1996).
Conventional Stoves -- ORTECH (1994).

CH₄ Emission Factors:
Wood Fuel/Wood Waste -- EPA (1985).

N₂O Emission Factors:
Wood Fuel/Wood Waste -- Rosland and Steen (1990); Radke et al. (1991).

References

AAC (2002), Calculating Direct GHG Emissions from Primary Aluminium Metal Production, Aluminum Association of Canada, Montréal, Quebec, Canada.

AMEC (2006), Identifying and Updating Industrial Process Activity Data in the Minerals Sector for the Canadian Greenhouse Gas Inventory, AMEC Earth & Environmental, March.

ASAE (2003), Manure production and characteristics, in: ASAE Standards 2003, Standards Engineering Practices Data, 47th Edition, American Society of Agricultural Engineers, The Society for Engineering in Agricultural, Food and Biological Science, St. Joseph, Michigan, U.S.A.

Barton, P. and J. Simpson (1994), The Effects of Aged Catalysts and Cold Ambient Temperatures on Nitrous Oxide Emissions,Mobile Sources Emissions Division, Environment Canada, MSED Report No. 94-21.

Boadi, D.A., K.H. Ominski, D.L. Fulawka, and K.M. Wittenberg (2004), Improving Estimates of Methane Emissions Associated with Enteric Fermentation of Cattle in Canada by Adopting an IPCC (Intergovernmental Panel on Climate Change) Tier-2 Methodology, Final report submitted to the Greenhouse Gas Division, Environment Canada, by the Department of Animal Science, University of Manitoba, Winnipeg, Manitoba, Canada.

CAPP (1999), CH₄ and VOC Emissions from the Canadian Upstream Oil and Gas Industry, Vols. 1 and 2, Prepared for the Canadian Association of Petroleum Producers by Clearstone Engineering, Calgary, Alberta, Canada, Publication No. 1999-0010.

Cheminfo Services (2005), Improvements to Canada's Greenhouse Gas Emissions Inventory Related to Non-Energy Use of Hydrocarbon Products, Cheminfo Services Inc., Markham, Ontario, Canada.

Cheminfo Services (2006), Improvements and Updates to Certain Industrial Process and Solvent Use-Related Sections in Canada's Greenhouse Gas Inventory, Final Report, Cheminfo Services, Markham, Ontario, Canada, September.

CIEEDAC (2003), A Review of Energy Consumption in Canadian Oil Sands Operations, Heavy Oil Upgrading 1990, 1994 to 2001, Canadian Industrial Energy End-Use Data and Analysis Centre, Simon Fraser University, Burnaby, British Columbia, Canada, March.

CIEEDAC (2006),A Review of Energy Consumption in Canadian Oil Refineries 1990, 1994 to 2004, Canadian Industrial Energy End-Use Data and Analysis Centre, Simon Fraser University, Burnaby, British Columbia, Canada, March.

Collis, G.A. (1992), Personal communication (March 1992), Canadian Fertilizer Institute.

DOE/EIA (1993), Emission of Greenhouse Gases in the United States, 1985-1990, Department of Energy/Energy Information Administration, Washington, D.C., U.S.A., Report No. 0573.

EPA (1985), Compilation of Air Pollutant Emission Factors, Vol. I,Stationary Point and Area Sources, AP 42, 4th Edition, U.S. Environmental Protection Agency, Washington, D.C., U.S.A.

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ICF (2004), Update of Methane and Nitrous Oxide Emission Factors for On-Highway Vehicles,

Prepared for the U.S. Environmental Protection Agency by ICF Consulting, 420-P-04-16.

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Jaques, A. (1992), Canada's Greenhouse Gas Emissions: Estimates for 1990, Environmental Protection, Conservation and Protection, Environment Canada, December, EPS 5/AP/4.

King, B. (1994), Management of Methane Emissions from Coal Mines: Environmental, Engineering, Economic and Institutional Implication of Options, Neil and Gunter Ltd., Halifax, Nova Scotia, Canada, March.

Marinier, M., K. Clark, and C. Wagner-Riddle (2004), Improving Estimates of Methane Emissions Associated with Animal Waste Management Systems in Canada by Adopting an IPCC Tier 2 Methodology, Final report submitted to the Greenhouse Gas Division, Environment Canada, by the Department of Land Resource Science, University of Guelph, Guelph, Ontario, Canada.

McCann, T.J. (2000), 1998 Fossil Fuel and Derivative Factors, prepared for Environment Canada by T.J. McCann and Associates, March.

Nyboer, J. (2006), Personal communication, Simon Fraser University, Burnaby, British Columbia, Canada.

ORTECH Corporation (1994), Inventory Methods Manual for Estimating Canadian Emissions of Greenhouse Gases, Unpublished report prepared for the Regulatory Affairs and Program Integration Branch, Conservation and Protection, Environment Canada, Report No. 93-T61- P7013-FG.

Radke, L.F., D.A. Hegg, P.V. Hobbs, J.D. Nance, J.H. Lyons, K.K. Laursen, R.E. Weiss, P.J. Riggan, and D.E. Ward (1991), Particulate and trace gas emissions from large biomass fires in North America, in: J.S. Levine (Ed.) Global Biomass Burning: Atmospheric Climatic and Biospheric Implications, Massachusetts Institute of Technology, Cambridge, Massachusetts, U.S.A.

Rosland, A. and M. Steen (1990), Klimgass-Regnshap for Norge, Statens Forurensningstilsyn, Oslo, Norway.

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