With modern non-conventional oil production technology, at least 10% of these deposits, or about were considered to be economically recoverable at 2006 prices, making Canada's total oil reserves the second largest in the world, after Saudi Arabia's. The Athabasca deposit is the only large oil sands reservoir in the world which is suitable for large-scale surface mining, although most of it can only be produced using more recently developed in-situ technology.
The Athabasca oil sands first came to the attention of European fur traders in 1719 when Wa-pa-su, a Cree trader, brought a sample of bituminous sands to the Hudson's Bay Company post at York Factory on Hudson Bay where Henry Kelsey was the manager. In 1778, Peter Pond, another fur trader and a founder of the rival North West Company, became the first European to see the Athabasca deposits after discovering the Methye Portage which allowed access to the rich fur resources of the Athabasca River system from the Hudson Bay watershed.
In 1788, fur trader Alexander MacKenzie (who later discovered routes to both the Arctic and Pacific Oceans from this area) wrote: "At about from the fork (of the Athabasca and Clearwater Rivers) are some bituminous fountains into which a pole of long may be inserted without the least resistance. The bitumen is in a fluid state and when mixed with gum, the resinous substance collected from the spruce fir, it serves to gum the Indians' canoes." He was followed in 1799 by map maker David Thompson and in 1819 by British Naval officer Sir John Franklin.
Sir John Richardson did the first geological assessment of the oil sands in 1848 on his way north to search for Franklin's lost expedition. The first government-sponsored survey of the oil sands was initiated in 1875 by John Macoun, and in 1883, G.C. Hoffman of the Geological Survey of Canada tried separating the bitumen from oil sand with the use of water and reported that it separated readily. In 1888, Dr. Robert Bell, the director of the Geological Survey of Canada, reported to a Senate Committee that "The evidence ... points to the existence in the Athabasca and Mackenzie valleys of the most extensive petroleum field in America, if not the world."
In 1926, Dr. Karl Clark of the University of Alberta perfected a steam separation process which became the basis of today's thermal extraction process. Several attempts to implement it had varying degrees of success, but it was 1967 before the first commercially viable operation began with the opening of the Great Canadian Oil Sands (now Suncor) plant using surfactants in the separation process developed by Dr. Earl W. Malmberg of Sun Oil Company.
The method of calculating economically recoverable reserves that produced these estimates was adopted because conventional methods of accounting for reserves gave increasingly meaningless numbers. They made it appear that Alberta was running out of oil at a time when rapid increases in oil sands production were more than offsetting declines in conventional oil, and in fact most of Alberta's oil production is now non-conventional oil. Conventional estimates of oil reserves are really calculations of the geological risk of drilling for oil, but in the oil sands there is very little geological risk because they outcrop on the surface and are easy to locate. With the oil price increases since 2003, the economic risk of low oil prices was reduced.
The Alberta estimates only assume a recovery rate of around 20% of bitumen-in-place, whereas oil companies using the steam assisted gravity drainage (SAGD) method of extracting bitumen report that they can recover over 60% with little effort.
Only 3% of the initial established crude bitumen reserves have been produced since commercial production started in 1967. At rate of production projected for 2015, about , the Athabasca oil sands reserves would last over 170 years. However those production levels require an influx of workers into an area that until recently was largely uninhabited. By 2007 this need in northern Alberta drove unemployment rates in Alberta and adjacent British Columbia to the lowest levels in history. As far away as the Atlantic Provinces, where workers were leaving to work in Alberta, unemployment rates fell to levels not seen for over one hundred years.
The Venezuelan Orinoco tar sands site may contain more oil sands than Athabasca. However, while the Orinoco deposits are less viscous and more easily produced using conventional techniques (the Venezuelan government prefers to call them "extra-heavy oil"), they are too deep to access by surface mining.
In mid-2006, the National Energy Board of Canada estimated the operating cost of a new mining operation in the Athabasca oil sands to be C$9 to C$12 per barrel, while the cost of an in-situ SAGD operation (using dual horizontal wells) would be C$10 to C$14 per barrel. This compares to operating costs for conventional oil wells which can range from less than one dollar per barrel in Iraq and Saudi Arabia to over six in the United States and Canada's conventional oil reserves.
The capital cost of the equipment required to mine the sands and haul it to processing is a major consideration in starting production. The NEB estimates that capital costs raise the total cost of production to C$18 to C$20 per barrel for a new mining operation and C$18 to C$22 per barrel for a SAGD operation. This does not include the cost of upgrading the crude bitumen to synthetic crude oil, which makes the final costs C$36 to C$40 per barrel for a new mining operation.
Therefore, although high crude prices make the cost of production very attractive, sudden drops in price leaves producers unable to recover their capital costs—although the companies are well financed and can tolerate long periods of low prices since the capital has already been spent and they can typically cover incremental operating costs.
However, the development of commercial production is made easier by the fact that exploration costs are very low. Such costs are a major factor when assessing the economics of drilling in a traditional oil field. The location of the oil deposits in the oil sands are well known, and an estimate of recovery costs can usually be made easily. There is not another region in the world with energy deposits of comparable magnitude where it would be less likely that the installations would be confiscated by a hostile national government, or be endangered by a war or revolution.
As a result of the oil price increases since 2003, the economics of oil sands have improved dramatically. At a world price of US$50 per barrel, the NEB estimated an integrated mining operation would make a rate return of 16 to 23%, while a SAGD operation would return 16 to 27%. Prices since 2006 have risen, exceeding US$145 in mid 2008. As a result, capital expenditures in the oil sands announced for the period 2006 to 2015 are expected to exceed C$100 billion, which is twice the amount projected as recently as 2004. However, because of an acute labour shortage which has developed in Alberta, it is not likely that all these projects can be completed.
At present the area around Fort McMurray has seen the most effect from the increased activity in the oil sands. Although jobs are plentiful, housing is in short supply and expensive. People seeking work often arrive in the area without arranging accommodation, driving up the price of temporary accommodation. The area is isolated, with only a two-lane road connecting it to the rest of the province, and there is pressure on the government of Alberta to improve road links as well as hospitals and other infrastructure.
Despite the best efforts of companies to move as much of the construction work as possible out of the Fort McMurray area, and even out of Alberta, the shortage of skilled workers is spreading to the rest of the province.. Even without the oil sands, the Alberta economy would be very strong, but development of the oil sands has resulted in the strongest period of economic growth ever recorded by a Canadian province.
According to the Alberta Energy and Utilities Board, 2005 production of crude bitumen in the Athabasca oil sands was as follows:
|Shell Canada Mine||26,800||169,000|
|In Situ Projects||21,300||134,000|
As of 2006, output of oil sands production had increased to (bbl/d). Oil sands were the source of 62% of Alberta's total oil production and 47% of all oil produced in Canada. The Alberta government believes this level of production could reach by 2020 and possibly by 2030.
In early December 2007, London based BP and Calgary based Husky Energy announced a 50/50 joint venture to produce and refine bitumen from the Athabasca oil sands. BP would contribute its Toledo, Ohio refinery to the joint venture, while Husky would contribute its Sunrise oil sands project. Sunrise is planned to start producing of bitumen in 2012 and may reach 200,000 bpd (30,000 m3/d) by 2015-2020. BP would modify its Toledo refinery to process 170,000 bpd (27,000 m3/d) of bitumen directly to refined products. The joint venture would solve problems for both companies, since Husky is short of refining capacity, and BP has no presence in the oil sands. It is a change of strategy for BP, since the company historically has downplayed the importance of oil sands.
In mid December 2007, ConocoPhillips announced its intention to increase its oil sands production from to over the next 20 years, which would make it the largest private sector oil sands producer in the world. ConocoPhillips currently holds the largest position in the Canadian oil sands with over 1 million acres (4000 km2) under lease. Other major oil sands producers planning to increase their production include Royal Dutch Shell (to ; Syncrude Canada (to ; Suncor Energy (to and Canadian Natural Resources (to . If all these plans come to fruition, these five companies will be producing over 3.3 million bbl/d (500,000 m³/d) of oil from oil sands by 2028.
|Major Partners|| National |
| 2007 Production |
| Planned Production |
|Shell, Chevron, Marathon||UK, NL, US||136,000||770,000|
|Japan Canada Oil Sands (JACOS)||Japan||8,000||30,000|
|Nexen, OPTI Canada||—||240,000|
|Canadian Natural Resources Limited||—||700,000|
|Synenco Energy, Sinopec||China||—||100,000|
|Imperial Oil, ExxonMobil||US||—||300,000|
|Total S.A., Enerplus||France||—||225,000|
|Value Creation Inc||—||300,000|
|Korea National Oil Corporation||Korea||—||30,000|
The original process for extraction of bitumen from the sands was developed by Dr. Karl Clark, working with Alberta Research Council in the 1920s. Today, all of the producers doing surface mining, such as Syncrude Canada, Suncor Energy and Albian Sands Energy etc., use a variation of the Clark Hot Water Extraction (CHWE) process. In this process, the ores are mined using open-pit mining technology. The mined ore is then crushed for size reduction. Hot water at 50 — 80 °C is added to the ore and the formed slurry is transported using hydrotransport line to a primary separation vessel (PSV) where bitumen is recovered by flotation as bitumen froth. The recovered bitumen froth consists of 60% bitumen, 30% water and 10% solids by weight. The recovered bitumen froth needs to be cleaned to reject the contained solids and water to meet the requirement of downstream upgrading processes.
More recently, in-situ methods like steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) have been developed to extract bitumen from deep deposits by injecting steam to heat the sands and reduce the bitumen viscosity so that it can be pumped out like conventional crude oil.
The standard extraction process requires huge amounts of natural gas. Currently, the oil sands industry uses about 4% of the Western Canada Sedimentary Basin natural gas production. By 2015, this may increase 2.5 fold.
According to the National Energy Board, it requires about of natural gas to produce one barrel of bitumen from in situ projects and about for integrated projects. Since a barrel of oil equivalent is about of gas, this represents a large gain in energy. That being the case, it is likely that Alberta regulators will reduce exports of natural gas to the United States in order to provide fuel to the oil sands plants. As gas reserves are exhausted, however, oil upgraders will likely turn to bitumen gasification to generate their own fuel. In much the same way the bitumen can be converted into synthetic crude oil, it can also be converted into synthetic natural gas.
In-situ extraction on a commercial scale is just beginning. A project nearing completion, the Long Lake Project, is designed to provide its own fuel, by on-site hydrocracking of the bitumen extracted. Long Lake Phase 1 is extracting 13,000 barrels/day of bitumen as of July 2008, ramping towards a target of 72,000 in late 2009. and "upgrading" of bitumen to liquid oil in 2007, producing 60,000 bbl/day of usable oil. The hydrocracker is scheduled to complete commissioning by September 2008.
An agreement has been signed between PetroChina and Enbridge to build a pipeline from Edmonton, Alberta, to the west coast port of Kitimat, British Columbia, to export synthetic crude oil from the oil sands to China and elsewhere in the Pacific, plus a pipeline running the other way to import condensate to dilute the bitumen so it will flow. Sinopec, China's largest refining and chemical company, and China National Petroleum Corporation have bought or are planning to buy shares in major oil sands development.
The Athabasca River runs 1,231 kilometres from the Athabasca Glacier in west-central Alberta to Lake Athabasca in northeastern Alberta . The average annual flow just downstream of Fort McMurray is 633 cubic metres per second with its highest daily average measuring 1,200 cubic metres per second .
Current water license allocations totals about 1.8% of the Athabasca river flow. Actual use in 2006 was about 0.4%. In addition, the Alberta government sets strict limits on how much water oil sands companies can remove from the Athabasca River. According to the Water Management Framework for the Lower Athabasca River, during periods of low river flow water consumption from the Athabasca River is limited to 1.3% of annual average flow. The province of Alberta is also looking into cooperative withdrawal agreements between oil sands operators.
Ranked as the world's eighth largest emitter of greenhouse gases, Canada is a relatively large emitter given its population and is missing its Kyoto targets. A major Canadian initiative called the Integrated CO2 Network (ICO2N) has proposed a system for the large scale capture, transport and storage of carbon dioxide (CO2). ICO2N members represent a group of industry participants providing a framework for carbon capture and storage development in Canada, initially using it to enhance oil recovery. Nuclear power has also been proposed as a means of generating the required energy without releasing green house gases.
Major producing or planned developments in the Athabasca Oil Sands include the following projects:
|Shell Oil||Jackpine||1A||100,000 bbl/d (16,000 m³/d)||2010||Under construction|
|1B||100,000 bbl/d (16,000 m³/d)||2012||Approved|
|2||100,000 bbl/d (16,000 m³/d)||2014||Applied for|
|Muskeg River||Existing||155,000 bbl/d (24,600 m³/d)||2002||Operating|
|Expansion||115,000 bbl/d (18,300 m³/d)||2010||Approved|
|Pierre River||1||100,000 bbl/d (16,000 m³/d)||2018||Applied for|
|2||100,000 bbl/d (16,000 m³/d)||2021||Applied for|
|Canadian Natural Resources||Horizon||1||135,000 bbl/d (21,500 m³/d)||2008||Under construction|
|2 and 3||135,000 bbl/d (21,500 m³/d)||2011||Approved|
|4||145,000 bbl/d (23,100 m³/d)||2015||Announced|
|5||162,000 bbl/d (25,800 m³/d)||2017||Announced|
|Imperial Oil||Kearl||1||100,000 bbl/d (16,000 m³/d)||2010||Approved|
|2||100,000 bbl/d (16,000 m³/d)||2012||Approved|
|3||100,000 bbl/d (16,000 m³/d)||2018||Approved|
|Petro Canada||Fort Hills||1||165,000 bbl/d (26,200 m³/d)||2011||Approved|
|debottleneck||25,000 bbl/d (4,000 m³/d)||TBD||Approved|
|Suncor Energy||Millenium||294,000 bbl/d (46,700 m³/d)||1967||Operating|
|debottleneck||23,000 bbl/d (3,700 m³/d)||2008||Under construction|
|Steepbank||debottleneck||4,000 bbl/d (640 m³/d)||2007||Under construction|
|Voyageur South||1||120,000 bbl/d (19,000 m³/d)||2012||Applied for|
|Syncrude||Mildred Lake & Aurora||1 and 2||290,700 bbl/d (46,220 m³/d)||1978||Operating|
|3 Expansion||116,300 bbl/d (18,490 m³/d)||2006||Operating|
|3 Debottleneck||46,500 bbl/d (7,390 m³/d)||2011||Announced|
|4 Expansion||139,500 bbl/d (22,180 m³/d)||2015||Announced|
|Synenco Energy||Northern Lights||1||57,250 bbl/d (9,102 m³/d)||2010||Applied for|
|Total S.A.||Joslyn||1||50,000 bbl/d (7,900 m³/d)||2013||Applied for|
|2||50,000 bbl/d (7,900 m³/d)||2016||Applied for|
|3||50,000 bbl/d (7,900 m³/d)||2019||Announced|
|4||50,000 bbl/d (7,900 m³/d)||2022||Announced|
|UTS/Teck Cominco||Equinox||Lease 14||50,000 bbl/d (7,900 m³/d)||2014||Public disclosure|
|Frontier||1||100,000 bbl/d (16,000 m³/d)||2014||Public disclosure|
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