AIR EMISSIONS IN CANAdA'S OIl SANdS
Air Emissions in Canada’s Oil Sands GREENHOUSE GAS EMISSIONS There are many different types of oil produced in the world and differences in the quantity of GHG emissions they generate depends primarily on how much energy is required to produce and process the oil. For example, some oil can be produced through wells with minimal pumping while other oils can only be produced by injecting water or steam into the reservoir. Equally, light oil requires less energy to be refined into transportation fuels than heavy oil. The amount of natural gas contained in the oil that may be flared or vented also contributes to the overall GHG emissions. Finally, there are GHG emissions created when the transportation fuels are consumed in vehicles (this is where about 75 per cent of GHG emissions occur). Total GHG emissions from production to consumption are referred to as life cycle GHG emissions.
Key Conclusions of Life Cycle GHG Analysis • Life cycle GHG emissions for oil sands are comparable to domestic and imported conventional crude oils. • About 75 per cent of GHG emissions occur during fuel consumption and are the same regardless of the source of the crude oil.
Life 140 Cycle GHG Emissions of Various Crude Oils U.S. Domestic
Common U.S. Conventional Oil Imports
120
114 98
102
102
102
104
116 108
113
105
Range of Common U.S. Imported Crude Oils
80
0
Saudi Arabia
Mexico
Iraq
Venezuela
Nigeria
US Gulf Coast
California Thermal
In situ Oil Oil Sands – Sands Diluted Mining – Upgraded Bitumen Bitumen
In situ Oil Sands – Upgraded Bitumen
No current production (likely future scenario)
20
Approx 5% of 2008 oil sands production
40
Approx 40% of 2008 oil sands production
60 Approx 55% of 2008 oil sands production
g CO2e/MJ Gasoline
100
106
Oil Sands
GHG Emissions from Oil Production and Refining GHG Emissions from Gasoline Consumption
In situ Oil Sands – Bitumen
Source: Jacobs Consultancy, Life Cycle Assessment Comparison for North American and Imported Crudes, June 2009 Source: Jacobs Consultancy, Life Cycle Assessment Comparison for North American and Imported Crudes, June 2009
We will continue to reduce greenhouse gas emissions per barrel of production by improving our energy efficiency and by developing new technologies.
The Alberta Energy Research Institute recently commissioned Jacobs Consultancy, a branch of a major international engineering firm, to conduct an in-depth assessment of the life cycle GHG emissions of various U.S. imported and domestic crude oils compared to oil sands. The results indicate that life cycle GHG emissions vary according to the oil source and type of production and that life cycle GHG emissions of oil sands are comparable to conventional oil (some conventional oils have higher GHG emissions than some types of oil sands production and vice versa). The variability in GHG emissions in oil sands operations depends primarily on the type of product the facility is designed to produce. Some oil sands operations produce a high quality upgraded crude oil while others send unprocessed heavy oil (bitumen) straight to a refinery. It requires more energy
Canada’s GHG Emissions by Sector
to produce upgraded crude oil which results in higher GHG emissions. Conversely, some oil sands operators mix their bitumen with a lighter petroleum product before sending it to the refinery (referred to as diluted bitumen) and this approach results in the lowest life cycle GHG emissions because the diluent has lower GHG life cycle emissions resulting in an overall lower GHG profile blend. As oil sands production increases in the future, it is unlikely that there will be sufficient diluent supply to continue transporting the majority of in situ bitumen as blended product. The more likely future case is that the diluent will be separated at the refinery and sent back to northern Alberta via pipeline for reuse. The In situ Oil Sands - Bitumen case (see graph on page 1) is representative of this scenario.
Global Energy Related Emissions by Country China 20%
Transportation 25%
Other Industry 14%
Agriculture 9%
Europe 17%
U.S. 22%
Buildings 10%
Electricity & Heat Generation 16%
Eurasia 9% Solvent & Waste 4%
Oil Sands 5%
Oil & Gas Excluding Oil Sands 18%
Source: Environment Canada
Total GHG emissions from the oil sands industry are approximately 33 million tonnes per year1. This is equivalent to about 5 per cent of Canada’s GHG emissions, 0.5 per cent of GHG emissions of the United States and 0.1 per cent of global GHG emissions. Average GHG emissions per barrel in the oil sands
Other 21 %
Japan 4% India 4%
Australia 1% Canada 2%
Source: U.S. Energy Information Administration 2005
industry has decreased by more than 30 per cent since 19902. Approximately half of this reduction is due to technology advancements and energy efficiency improvements, and the balance is primarily due to an increasing percentage of oil sands production being refined in the U.S. rather than in Canada.
1, 2 Environment Canada: 1990 – 2006 Canada’s Greenhouse Gas Emissions: Understanding the Trends. November 2008
Reducing GHG Emissions in Oil Sands Mining according to the facility’s steam requirements, which often results in the generation of more electricity than the facility requires. This excess electricity is sold back into the electricity grid which means that there is less natural gas and coal used elsewhere in the Province to meet Alberta’s electricity needs, significantly reducing GHG and other air emissions in the Province. All existing oil sands mines and all but a few small in situ projects have cogeneration facilities (over 98 per cent of oil sands production has associated cogeneration). Cogeneration in the oil sands provides approximately 18 per cent of Alberta’s total electricity supply.3
Oil Sands Mining – Heavy Hauler The primary source of GHG emissions in oil sands mining is the energy required to mine and transport the oil sands, separate the oil from the sand and to process the oil. Commercial oil sands mining in Canada began in the late 1960s. Since that time, continual advancements in technology and energy efficiency have resulted in significant reductions in GHG emissions per barrel. The oil sands mining industry continues to develop new technologies that will further reduce GHG emissions per barrel in coming years. Warm Water Extraction – An area where oil sands mining companies, such as Syncrude Canada Ltd. and Shell Canada Limited, are advancing technology is by reducing the temperature of the process water used to separate the heavy oil from the sand during extraction. For example, Syncrude has been able to reduce water temperatures from approximately 80° C to 35° C at its Aurora mine. The reduced temperature results in approximately a third less energy consumption, and correspondingly lower GHG emissions. Cogeneration – oil sands operations require steam, which is usually created with natural gas-fired boilers. The process of creating this steam can be simultaneously used to generate electricity. This process, referred to as cogeneration, creates a highly efficient energy system that produces both steam and electricity from a single source with efficiency gained from joint production. Oil sands cogeneration plants are sized
Carbon Capture and Storage (CCS) – CCS has been identified by governments, industry, researchers and stakeholders as a key option to significantly reduce GHG emissions in the future. CCS is well understood from a technical perspective but widespread implementation is limited by challenging economics and a lack of infrastructure. The Alberta government recently committed $2 billion dollars to CCS development and the federal government has committed an additional $1 billion. Industry is investing heavily in CCS development, and there are currently several CCS projects operating in Western Canada, including EnCana Corporation’s Weyburn Project and Pennwest Energy’s Joffre Project. As the required infrastructure is developed, CCS has the potential to significantly reduce GHG emissions from the oil sands. Capture and storage of readily available CO2 streams such as those associated with hydrogen production facilities at upgraders may be feasible in the near to mid-term with investment in pipeline and injection infrastructure. A number of these types of oil sands projects have been short-listed by the Alberta Government as candidates to receive cofunding from the $2 billion CCS investment fund. Full CCS, including the capture of CO2 from combustion flue gases, will require significantly more investment and government and industry are working to make it feasible in the long-term. It is likely that full CCS will be applied at coal-fired electricity generation facilities prior to deployment in the oil sands as it is more cost effective in that application given the larger and more concentrated point sources of CO2.
3 ERCB ST98-2009 – Alberta's Energy Reserves 2008 and Supply/Demand Outlook 2009-2018
Reducing GHG Emissions from In situ Oil Sands In situ operations require significant amounts of energy to generate steam that is then injected deep underground into the oil sands formation to warm the heavy oil so that it can be pumped to the surface.
reduce GHG emissions from production by about 50 per cent. This technology has been successfully field tested and is planned for use in commercial production by Petrobank Energy and Resources Ltd. by 2010.
In situ oil sands producers have made significant progress in reducing the amount of steam required to produce the heavy oil in recent years. There are also several technologies nearing commercial implementation that have the potential to further reduce GHG emissions per barrel from in situ oil sands to levels that are equivalent to or better than imported conventional oil.
Solvent Recovery – Numerous companies are testing the ability to partially or completely eliminate the need for steam by injecting solvents (such as propane) into the oil sands to dilute the bitumen and allow it to flow. Results from several field pilots have demonstrated the ability to reduce steam requirements (and GHG emissions) by up to 50 per cent in addition to a corresponding reduction in water use. Full solvent recovery has been successfully demonstrated at laboratory scale and could potentially
Current Technologies — Existing projects using standard steam injection have continued to refine the in situ recovery process and are achieving reductions of production-related GHG emissions of over 20 per cent per barrel compared to a few years ago. Advancements include the use of electric submersible pumps, drilling of additional production wells to take greater advantage of reservoir heating and overall improvements in energy efficiency. In situ Combustion — Technologies such as the Toe-to-Heel Air Injection (THAITM) process inject air into the oil sands in order to create underground combustion that warms the thick bitumen so it can be extracted. By eliminating the need for steam, the technology can
EnCana Solvent Recovery Pilot Facility
reduce GHG emissions from production by up to 85 per cent. Commercial applications of this technology are expected to follow upon completion of the pilots. Electrical Heating — Technologies such as ET DSPTM heat the oil sands by using electrical current rather than steam. In addition to virtually eliminating the need for water, GHG emissions from production are reduced by approximately 60 per cent (using electricity from the Alberta grid). This technology has been successfully field tested at a 1000 bbl/day scale and is expected to be used in full commercial production by E-T Energy within 2 - 3 years.
E-T Energy Electrical Heating Pilot Facility
Petrobank THAI Pilot Project
Life Cycle GHG Emissions (g CO2e/MJ Gasoline)
120 Comparison of Common U.S. Imported Crude Oils vs. Various Oil Sands Technologies Range of Common U.S. Imported Crude Oils
100
80
60
40
GHG Emissions from Oil Production and Refining
20
0
GHG Emissions from Gasoline Consumption Oil Sands Mining (Upgraded Bitumen) with Cogeneration
Oil Sands In situ Mining Combustion (Upgraded Bitumen) with CCS at Upgrader
In situ Solvent Recovery
In situ Oil Sands In situ Electrical (Diluted Bitumen) with Heating Cogeneration
Source: Jacobs Consultancy, Life Cycle Assessment Comparison for North American and Imported Crudes, June 2009 Source: CAPP 2009 Jacobs Consultancy, Life Cycle Assessment Comparison for North American and Imported Crudes, June 2009 CAPP 2009
Alberta GHG Regulation – Reduce or Pay The Government of Alberta implemented GHG regulations in 2007 (the first jurisdiction in North America to do so) that require a 12 per cent reduction in GHG emissions per barrel for all existing oil sands operations. New facilities are given a 3-year start-up period after which their baseline is established and they are required to reduce GHG emissions per barrel by 2 per cent annually until they have achieved the 12 per cent reduction requirement.
Federal GHG Regulation In addition to the Alberta GHG regulations, the Federal Government is developing a carbon pricing system using a cap and trade approach which would drive further reductions in oil sands and other industry sectors in Canada and create additional funding for transformative technology development.
Emitters can meet the reduction target, acquire approved offsets, or pay $15/tonne of GHG emitted into the Climate Change and Emissions Management Fund. Proceeds are directed to research and technology development focused on reducing GHG emissions. During the first two years, the legislation has resulted in approximately 6.5 million tonnes of actual reductions in Alberta and companies that were not able to achieve the required GHG reductions paid approximately $122 million into the Climate Change and Emissions Management Fund.
Air Quality in the Oil Sands Region GHG emissions are important in a global context. There are other air emissions associated with oil sands development that are important at the local level, in terms of regional air quality. These emissions include nitrogen dioxide (NO2), sulphur dioxide (SO2) and fine particulate matter (PM) which are primarily created through fuel combustion (plant facilities and vehicles). Alberta Environment has established Ambient Air Quality Objectives (AAQO) as indicators of air quality in the Province. These objectives are intended to provide protection of the environment and human health and are used to report on the state of Alberta’s atmospheric environment and to assess compliance near major industrial air emission sources. Alberta Environment ensures that emissions from human activities are minimized and that air quality continues to be better than the AAQO’s. As oil sands development has increased, the industry has invested heavily in emissions abatement equipment on existing facilities and state-of-the-art low emission technologies on new facilities in order to ensure that regional air quality stays within regulated limits. Oil sands
operators are also required to fund air quality monitoring in the region. The monitoring is conducted by the Wood Buffalo Environmental Association (WBEA) which is a collaboration of communities, environmental groups, industry, government and Aboriginal stakeholders. WBEA monitors the air in the Regional Municipality of Wood Buffalo, 24 hours a day, 365 days a year through one of the most extensive air quality monitoring networks in North America with 16 air monitoring stations and 14 passive monitoring stations. The information collected is openly shared with stakeholders and the public and is available in real time on their website (www.wbea.org). Data collected over the past 10 years at monitoring stations across Alberta indicate an improving or static trend in air quality throughout the province. Annual average concentrations of common air pollutants show that, despite an increase in emissions-associated activities and population growth, monitored ambient concentrations do not reflect any deterioration in air quality.
Sulphur Dioxide Annual Average Trend 12 Alberta Ambient Air Quality Objective
SO2 Concentration (ppb)
10
Concentrations of SO2 have remained relatively constant over the past 10 years in the oil sands region and remain well below the AAQO.
Fort McMurray Calgary
8
Edmonton Fort Chipewyan Fort McKay
6
4
2
0 1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
Data for Calgary and Edmonton from the CASA Data Warehouse.
Data Data for Calgary Edmonton CASA Data Warehouse. for Woodand Buffalo from the from WBEAthe 2007 Annual Report. Data for Wood Buffalo from the WBEA 2007 Annual Report.
We will design and operate our facilities to ensure that regional air quality continues to exceed provincial air quality objectives.
Nitrogen Dioxide Annual Average Trend NO2 concentrations at stations in the Regional Municipality of Wood Buffalo show a moderate increase in NO2 yet still remain well below the AAQO and at least two times less than those measured in Edmonton and Calgary.
35 Alberta Ambient Air Quality Objective
30
NO2 Concentration (ppb)
25 20 15 10
Fort McMurray Calgary
5
Edmonton Fort Chipewyan Fort McKay
0 1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
Data for Calgary and Edmonton from the CASA Data Warehouse.
Data for and Edmonton CASA Data Warehouse. DataCalgary for Wood Buffalo from thefrom WBEAthe 2007 Annual Report. Data for Wood Buffalo from the WBEA 2007 Annual Report.
Particulate Matter (
Key Conclusions of Life Cycle GHG Analysis • Life cycle GHG emissions for oil sands are comparable to domestic and imported conventional crude oils. • About 75 per cent of GHG emissions occur during fuel consumption and are the same regardless of the source of the crude oil.
Life 140 Cycle GHG Emissions of Various Crude Oils U.S. Domestic
Common U.S. Conventional Oil Imports
120
114 98
102
102
102
104
116 108
113
105
Range of Common U.S. Imported Crude Oils
80
0
Saudi Arabia
Mexico
Iraq
Venezuela
Nigeria
US Gulf Coast
California Thermal
In situ Oil Oil Sands – Sands Diluted Mining – Upgraded Bitumen Bitumen
In situ Oil Sands – Upgraded Bitumen
No current production (likely future scenario)
20
Approx 5% of 2008 oil sands production
40
Approx 40% of 2008 oil sands production
60 Approx 55% of 2008 oil sands production
g CO2e/MJ Gasoline
100
106
Oil Sands
GHG Emissions from Oil Production and Refining GHG Emissions from Gasoline Consumption
In situ Oil Sands – Bitumen
Source: Jacobs Consultancy, Life Cycle Assessment Comparison for North American and Imported Crudes, June 2009 Source: Jacobs Consultancy, Life Cycle Assessment Comparison for North American and Imported Crudes, June 2009
We will continue to reduce greenhouse gas emissions per barrel of production by improving our energy efficiency and by developing new technologies.
The Alberta Energy Research Institute recently commissioned Jacobs Consultancy, a branch of a major international engineering firm, to conduct an in-depth assessment of the life cycle GHG emissions of various U.S. imported and domestic crude oils compared to oil sands. The results indicate that life cycle GHG emissions vary according to the oil source and type of production and that life cycle GHG emissions of oil sands are comparable to conventional oil (some conventional oils have higher GHG emissions than some types of oil sands production and vice versa). The variability in GHG emissions in oil sands operations depends primarily on the type of product the facility is designed to produce. Some oil sands operations produce a high quality upgraded crude oil while others send unprocessed heavy oil (bitumen) straight to a refinery. It requires more energy
Canada’s GHG Emissions by Sector
to produce upgraded crude oil which results in higher GHG emissions. Conversely, some oil sands operators mix their bitumen with a lighter petroleum product before sending it to the refinery (referred to as diluted bitumen) and this approach results in the lowest life cycle GHG emissions because the diluent has lower GHG life cycle emissions resulting in an overall lower GHG profile blend. As oil sands production increases in the future, it is unlikely that there will be sufficient diluent supply to continue transporting the majority of in situ bitumen as blended product. The more likely future case is that the diluent will be separated at the refinery and sent back to northern Alberta via pipeline for reuse. The In situ Oil Sands - Bitumen case (see graph on page 1) is representative of this scenario.
Global Energy Related Emissions by Country China 20%
Transportation 25%
Other Industry 14%
Agriculture 9%
Europe 17%
U.S. 22%
Buildings 10%
Electricity & Heat Generation 16%
Eurasia 9% Solvent & Waste 4%
Oil Sands 5%
Oil & Gas Excluding Oil Sands 18%
Source: Environment Canada
Total GHG emissions from the oil sands industry are approximately 33 million tonnes per year1. This is equivalent to about 5 per cent of Canada’s GHG emissions, 0.5 per cent of GHG emissions of the United States and 0.1 per cent of global GHG emissions. Average GHG emissions per barrel in the oil sands
Other 21 %
Japan 4% India 4%
Australia 1% Canada 2%
Source: U.S. Energy Information Administration 2005
industry has decreased by more than 30 per cent since 19902. Approximately half of this reduction is due to technology advancements and energy efficiency improvements, and the balance is primarily due to an increasing percentage of oil sands production being refined in the U.S. rather than in Canada.
1, 2 Environment Canada: 1990 – 2006 Canada’s Greenhouse Gas Emissions: Understanding the Trends. November 2008
Reducing GHG Emissions in Oil Sands Mining according to the facility’s steam requirements, which often results in the generation of more electricity than the facility requires. This excess electricity is sold back into the electricity grid which means that there is less natural gas and coal used elsewhere in the Province to meet Alberta’s electricity needs, significantly reducing GHG and other air emissions in the Province. All existing oil sands mines and all but a few small in situ projects have cogeneration facilities (over 98 per cent of oil sands production has associated cogeneration). Cogeneration in the oil sands provides approximately 18 per cent of Alberta’s total electricity supply.3
Oil Sands Mining – Heavy Hauler The primary source of GHG emissions in oil sands mining is the energy required to mine and transport the oil sands, separate the oil from the sand and to process the oil. Commercial oil sands mining in Canada began in the late 1960s. Since that time, continual advancements in technology and energy efficiency have resulted in significant reductions in GHG emissions per barrel. The oil sands mining industry continues to develop new technologies that will further reduce GHG emissions per barrel in coming years. Warm Water Extraction – An area where oil sands mining companies, such as Syncrude Canada Ltd. and Shell Canada Limited, are advancing technology is by reducing the temperature of the process water used to separate the heavy oil from the sand during extraction. For example, Syncrude has been able to reduce water temperatures from approximately 80° C to 35° C at its Aurora mine. The reduced temperature results in approximately a third less energy consumption, and correspondingly lower GHG emissions. Cogeneration – oil sands operations require steam, which is usually created with natural gas-fired boilers. The process of creating this steam can be simultaneously used to generate electricity. This process, referred to as cogeneration, creates a highly efficient energy system that produces both steam and electricity from a single source with efficiency gained from joint production. Oil sands cogeneration plants are sized
Carbon Capture and Storage (CCS) – CCS has been identified by governments, industry, researchers and stakeholders as a key option to significantly reduce GHG emissions in the future. CCS is well understood from a technical perspective but widespread implementation is limited by challenging economics and a lack of infrastructure. The Alberta government recently committed $2 billion dollars to CCS development and the federal government has committed an additional $1 billion. Industry is investing heavily in CCS development, and there are currently several CCS projects operating in Western Canada, including EnCana Corporation’s Weyburn Project and Pennwest Energy’s Joffre Project. As the required infrastructure is developed, CCS has the potential to significantly reduce GHG emissions from the oil sands. Capture and storage of readily available CO2 streams such as those associated with hydrogen production facilities at upgraders may be feasible in the near to mid-term with investment in pipeline and injection infrastructure. A number of these types of oil sands projects have been short-listed by the Alberta Government as candidates to receive cofunding from the $2 billion CCS investment fund. Full CCS, including the capture of CO2 from combustion flue gases, will require significantly more investment and government and industry are working to make it feasible in the long-term. It is likely that full CCS will be applied at coal-fired electricity generation facilities prior to deployment in the oil sands as it is more cost effective in that application given the larger and more concentrated point sources of CO2.
3 ERCB ST98-2009 – Alberta's Energy Reserves 2008 and Supply/Demand Outlook 2009-2018
Reducing GHG Emissions from In situ Oil Sands In situ operations require significant amounts of energy to generate steam that is then injected deep underground into the oil sands formation to warm the heavy oil so that it can be pumped to the surface.
reduce GHG emissions from production by about 50 per cent. This technology has been successfully field tested and is planned for use in commercial production by Petrobank Energy and Resources Ltd. by 2010.
In situ oil sands producers have made significant progress in reducing the amount of steam required to produce the heavy oil in recent years. There are also several technologies nearing commercial implementation that have the potential to further reduce GHG emissions per barrel from in situ oil sands to levels that are equivalent to or better than imported conventional oil.
Solvent Recovery – Numerous companies are testing the ability to partially or completely eliminate the need for steam by injecting solvents (such as propane) into the oil sands to dilute the bitumen and allow it to flow. Results from several field pilots have demonstrated the ability to reduce steam requirements (and GHG emissions) by up to 50 per cent in addition to a corresponding reduction in water use. Full solvent recovery has been successfully demonstrated at laboratory scale and could potentially
Current Technologies — Existing projects using standard steam injection have continued to refine the in situ recovery process and are achieving reductions of production-related GHG emissions of over 20 per cent per barrel compared to a few years ago. Advancements include the use of electric submersible pumps, drilling of additional production wells to take greater advantage of reservoir heating and overall improvements in energy efficiency. In situ Combustion — Technologies such as the Toe-to-Heel Air Injection (THAITM) process inject air into the oil sands in order to create underground combustion that warms the thick bitumen so it can be extracted. By eliminating the need for steam, the technology can
EnCana Solvent Recovery Pilot Facility
reduce GHG emissions from production by up to 85 per cent. Commercial applications of this technology are expected to follow upon completion of the pilots. Electrical Heating — Technologies such as ET DSPTM heat the oil sands by using electrical current rather than steam. In addition to virtually eliminating the need for water, GHG emissions from production are reduced by approximately 60 per cent (using electricity from the Alberta grid). This technology has been successfully field tested at a 1000 bbl/day scale and is expected to be used in full commercial production by E-T Energy within 2 - 3 years.
E-T Energy Electrical Heating Pilot Facility
Petrobank THAI Pilot Project
Life Cycle GHG Emissions (g CO2e/MJ Gasoline)
120 Comparison of Common U.S. Imported Crude Oils vs. Various Oil Sands Technologies Range of Common U.S. Imported Crude Oils
100
80
60
40
GHG Emissions from Oil Production and Refining
20
0
GHG Emissions from Gasoline Consumption Oil Sands Mining (Upgraded Bitumen) with Cogeneration
Oil Sands In situ Mining Combustion (Upgraded Bitumen) with CCS at Upgrader
In situ Solvent Recovery
In situ Oil Sands In situ Electrical (Diluted Bitumen) with Heating Cogeneration
Source: Jacobs Consultancy, Life Cycle Assessment Comparison for North American and Imported Crudes, June 2009 Source: CAPP 2009 Jacobs Consultancy, Life Cycle Assessment Comparison for North American and Imported Crudes, June 2009 CAPP 2009
Alberta GHG Regulation – Reduce or Pay The Government of Alberta implemented GHG regulations in 2007 (the first jurisdiction in North America to do so) that require a 12 per cent reduction in GHG emissions per barrel for all existing oil sands operations. New facilities are given a 3-year start-up period after which their baseline is established and they are required to reduce GHG emissions per barrel by 2 per cent annually until they have achieved the 12 per cent reduction requirement.
Federal GHG Regulation In addition to the Alberta GHG regulations, the Federal Government is developing a carbon pricing system using a cap and trade approach which would drive further reductions in oil sands and other industry sectors in Canada and create additional funding for transformative technology development.
Emitters can meet the reduction target, acquire approved offsets, or pay $15/tonne of GHG emitted into the Climate Change and Emissions Management Fund. Proceeds are directed to research and technology development focused on reducing GHG emissions. During the first two years, the legislation has resulted in approximately 6.5 million tonnes of actual reductions in Alberta and companies that were not able to achieve the required GHG reductions paid approximately $122 million into the Climate Change and Emissions Management Fund.
Air Quality in the Oil Sands Region GHG emissions are important in a global context. There are other air emissions associated with oil sands development that are important at the local level, in terms of regional air quality. These emissions include nitrogen dioxide (NO2), sulphur dioxide (SO2) and fine particulate matter (PM) which are primarily created through fuel combustion (plant facilities and vehicles). Alberta Environment has established Ambient Air Quality Objectives (AAQO) as indicators of air quality in the Province. These objectives are intended to provide protection of the environment and human health and are used to report on the state of Alberta’s atmospheric environment and to assess compliance near major industrial air emission sources. Alberta Environment ensures that emissions from human activities are minimized and that air quality continues to be better than the AAQO’s. As oil sands development has increased, the industry has invested heavily in emissions abatement equipment on existing facilities and state-of-the-art low emission technologies on new facilities in order to ensure that regional air quality stays within regulated limits. Oil sands
operators are also required to fund air quality monitoring in the region. The monitoring is conducted by the Wood Buffalo Environmental Association (WBEA) which is a collaboration of communities, environmental groups, industry, government and Aboriginal stakeholders. WBEA monitors the air in the Regional Municipality of Wood Buffalo, 24 hours a day, 365 days a year through one of the most extensive air quality monitoring networks in North America with 16 air monitoring stations and 14 passive monitoring stations. The information collected is openly shared with stakeholders and the public and is available in real time on their website (www.wbea.org). Data collected over the past 10 years at monitoring stations across Alberta indicate an improving or static trend in air quality throughout the province. Annual average concentrations of common air pollutants show that, despite an increase in emissions-associated activities and population growth, monitored ambient concentrations do not reflect any deterioration in air quality.
Sulphur Dioxide Annual Average Trend 12 Alberta Ambient Air Quality Objective
SO2 Concentration (ppb)
10
Concentrations of SO2 have remained relatively constant over the past 10 years in the oil sands region and remain well below the AAQO.
Fort McMurray Calgary
8
Edmonton Fort Chipewyan Fort McKay
6
4
2
0 1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
Data for Calgary and Edmonton from the CASA Data Warehouse.
Data Data for Calgary Edmonton CASA Data Warehouse. for Woodand Buffalo from the from WBEAthe 2007 Annual Report. Data for Wood Buffalo from the WBEA 2007 Annual Report.
We will design and operate our facilities to ensure that regional air quality continues to exceed provincial air quality objectives.
Nitrogen Dioxide Annual Average Trend NO2 concentrations at stations in the Regional Municipality of Wood Buffalo show a moderate increase in NO2 yet still remain well below the AAQO and at least two times less than those measured in Edmonton and Calgary.
35 Alberta Ambient Air Quality Objective
30
NO2 Concentration (ppb)
25 20 15 10
Fort McMurray Calgary
5
Edmonton Fort Chipewyan Fort McKay
0 1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
Data for Calgary and Edmonton from the CASA Data Warehouse.
Data for and Edmonton CASA Data Warehouse. DataCalgary for Wood Buffalo from thefrom WBEAthe 2007 Annual Report. Data for Wood Buffalo from the WBEA 2007 Annual Report.
Particulate Matter (
