Alberta's oil sands contain vast bitumen resources with reserves that are the second largest in the world, after Saudi Arabia. According to the Alberta Energy and Utilities Board (EUB), remaining established reserves are estimated to be 28 billion cubic metres (174 billion barrels) at year-end 2004.
Why did the NEB prepare this Energy Market Assessment (EMA)?
In May 2004, the Board released an Energy Market Assessment (EMA) entitled Canada's Oil Sands: Opportunities and Challenges to 2015. It contained an objective assessment on the major aspects of the oil sands industry and assessed the opportunities and challenges facing the development of the resource. Since then, the conditions surrounding oil sands development have changed significantly. As a result, the Board decided to provide an update.
What is the Board's outlook for oil sands development?
It is expected that rapid development of Canada's oil sands will continue. There are, however, issues and uncertainties associated with the development of this resource. The rate of development will depend on the balance that is reached between the opposing forces that affect the oil sands. High oil prices, international recognition, stable investment climate, global growth in oil demand, size of the resource base and proximity to the large U.S. market, and potentially access to other markets, encourage development. On the other hand, water use, air emissions, local infrastructure and services, labour requirements, natural gas costs and the light/heavy oil price differential are concerns that could potentially inhibit the development of the resource.
What are the Board's main conclusions?
How much money is being invested in the oil sands?
Over C$125 billion in oil sands recovery projects have been proposed during the 2006 to 2015 period; however, all projects are not expected to proceed. The NEB's Base Case projection assumes capital expenditures of C$94 billion over this period.
What are the key assumptions used in this analysis in comparison to the May 2004 report?
A comparison of key assumptions between this analysis (2005 dollars) and the 2004 report (2003 dollars) is provided below:
|Assumptions||June 2006 Report||May 2004 Report|
|WTI crude oil price||US$50 per barrel||US$24 per barrel|
|NYMEX natural gas price||US$7.50 per MMBtu||US$4.00 per MMBtu|
|Light/Heavy price differential||US$15 per barrel||US$7 per barrel|
|Canadian dollar exchange rate||US$0.85||US$0.75|
What are the operating costs and the supply costs of producing a barrel of oil from the oil sands?
The estimated operating costs range from $6 to $14 per barrel for bitumen and $18 to $22 per barrel for synthetic crude oil. The estimated supply costs ranges from $14 to $24 per barrel for bitumen and from $36 to $40 per barrel for synthetic crude oil. Supply costs include operating costs, capital costs, taxes, royalties and the rate of return on investment.
At what oil price range are oil sands operations economic?
Integrated mining and SAGD (Steam Assisted Gravity Drainage) operations are estimated to be economic at US$30 to $35 per barrel WTI. However, continued escalation in material and labour costs pose a risk to this outlook. Furthermore, higher natural gas prices and blending costs would also increase this estimate. On the other hand, advancement in recovery and upgrading technologies hold potential to improve economics.
What is the NEB's projection for western Canadian oil supply, including conventional oil by 2015?
Total oil supply from western Canada is expected to grow from 365 000 cubic metres (2.4 million barrels) per day in 2005 to 613 000 cubic metres (3.9 million barrels) per day in 2015, an increase of 68 percent. In 2005, oil sands production surpassed 175 000 cubic metres (1.1 million barrels) per day, and it is expected to almost triple to about 472 000 cubic metres (3.0 million barrels) per day by 2015.
What is the natural gas requirement relative to oil sands production?
It takes about 34 cubic metres (1 200 cubic feet) of natural gas to produce one barrel of bitumen from in situ projects and about 20 cubic metres (700 cubic feet) for integrated projects. Currently, the oil sands industry uses about 21 million cubic metres (0.7 billion cubic feet) per day of purchased gas, or about five percent of the Western Canada Sedimentary Basin production. By 2015, this increases to about 60 million cubic metres (2.1 billion cubic feet) per day, or nearly 12 percent, assuming gas production remains at 482 million cubic metres (17 billion cubic feet) per day.
Will there be markets to take the rising volumes of oil sands production?
Based on industry consultations and the Board's internal analysis market expansion for growing oil sands production could unfold in the following way:
Step One: Fill up existing markets, including Washington State, PADD II and PADD IV and some additional volumes in Canada.
Step Two: Further penetration of southern PADD II and PADD III, refinery expansions and conversions in northern PADD II, PADD IV and PADD V.
Step Three: Branch out and develop new markets. In this connection, a new pipeline or a major pipeline expansion to the west coast would be required to deliver crude oil to California and the Far East.
The following map illustrates the major oil pipelines in Canada and the United States as well as the North American markets.
Will there be pipeline capacity to transport the additional oil sands production?
Pipeline capacity out of western Canada could be near full utilization starting in 2007. The industry needs to decide which markets hold the greatest potential and move forward on pipeline expansions or new pipelines.
How much water is required to produce one cubic metre of oil from the oil sands?
The water requirement ranges from 2 to 4.5 cubic metres of water to produce one cubic metre of synthetic crude oil in a mining operation. Mining operations use surface water and recycled water.
In SAGD operations, although 90 to 95 percent of the water used for steam to recover bitumen is reused, every cubic metre of bitumen produced still requires about 0.2 cubic metres of additional groundwater. Some surface water is used but most operations use fresh and saline groundwater.
What are the major issues surrounding water usage by oil sands operations?
Stakeholders agree that oil sands operations must improve their water usage. At current rates of withdrawal from the Athabasca River, there would be insufficient volumes to support all the announced oil sands mining projects. River flows are low in the winter and the removal of large volumes of water during these periods is a concern.
Waste water that is collected from the extraction process is contained in large tailings ponds. There is a debate on whether the tailings ponds can be reclaimed to become biologically productive ecosystems.
How much progress has the industry made to reduce emissions?
Although significant progress has been made towards decreasing the intensity of Greenhouse Gas (GHG) emissions produced by oil sands operators, the increased production of oil counterbalances these gains and total emissions are expected to rise.
Given the current high oil prices there is renewed interest in carbon dioxide (CO2) capture and storage for enhanced oil recovery (EOR) to increase production from mature Canadian oil reserves. A major barrier to this development would be the need for a dedicated CO2 pipeline to transport CO2 from the oil sands projects to the light oil pools in central Alberta. The policy regarding long-term storage is also uncertain.
Is there sufficient skilled labour to meet the pace of development?
It is uncertain if the industry is able to increase the supply of skilled workers. A limited supply has the potential to restrict the pace of development.
Are there infrastructure concerns?
The Wood Buffalo region, the area of most intensive development, has experienced deficiencies in community service delivery and infrastructure development.
What impact has higher natural gas prices had on cogeneration in the oil sands?
Higher natural gas prices have been one of the factors supporting a trend for oil sands producers to build cogeneration to meet their own electricity demand. There has been little incentive to install excess capacity for sale to the grid.
How can the oil sands industry provide opportunities for the petrochemical sector?
The Alberta petrochemical sector faces a situation of tight ethane feedstock supply, raising the need to consider future feedstock supply and flexibility.
The bitumen upgrading process produces off-gas from which ethane and other light hydrocarbons could be extracted and used by the petrochemical industry. Currently, ethane and most of the other light hydrocarbons remain in the off-gas and are used as fuel for operations.