|Athabasca Oil Sands|
|Operators:||Syncrude, Suncor, CNRL, Shell, Total, Imperial Oil, Petro Canada, Devon, Husky, Statoil, Nexen|
|Partners:||Chevron, Marathon, ConocoPhillips, BP, Oxy|
|Extent in Alberta, Canada|
|Start of production:||1967|
|Current production of oil (barrels per day):||1,300,000 barrels/day|
|Estimated oil in place (millions of barrels):||133,000 MMBbl (21.2×109m3) |
|Producing formations:||McMurray, Clearwater, Grand Rapids|
The Athabasca Oil Sands (also known colloquially as the Athabasca Tar Sands, although there is no actual tar) are large deposits of bitumen, or extremely heavy crude oil, located in northeastern Alberta, Canada - roughly centered around the boomtown of Fort McMurray. These oil sands, hosted in the McMurray Formation, consist of a mixture of crude bitumen (a semi-solid form of crude oil), silica sand, clay minerals, and water. The Athabasca deposit is the largest reservoir of crude bitumen in the world and the largest of three major oil sands deposits in Alberta, along with the nearby Peace River and Cold Lake deposits. Together, these oil sand deposits lie under 141,000 square kilometres (54,000 sq mi) of sparsely populated boreal forest and muskeg (peat bogs) and contain about 1.7 trillion barrels (270×109 m3) of bitumen in-place, comparable in magnitude to the world's total proven reserves of conventional petroleum.
With modern unconventional oil production technology, at least 10% of these deposits, or about 170 billion barrels (27×109 m3) 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 are named after the Athabasca River which cuts through the heart of the deposit, and traces of the heavy oil are readily observed on the river banks. Historically, the bitumen was used by the indigenous Cree and Dene Aboriginal peoples to waterproof their canoes. The oil deposits are located within the boundaries of Treaty 8, and several First Nations of the area are involved with the sands.
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 24 miles (39 km) from the fork (of the Athabasca and Clearwater Rivers) are some bituminous fountains into which a pole of 20 feet (6.1 m) 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 hot water 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.
Commercial production of oil from the Athabasca oil sands began in 1967, when Great Canadian Oil Sands Limited (then a subsidiary of Sun Oil Company but now an independent company known as Suncor Energy) opened its first mine, producing 30,000 barrels per day (4,800 m3/d) of synthetic crude oil. Development was inhibited by declining world oil prices, and the second mine, operated by the Syncrude consortium, did not begin operating until 1978, after the 1973 oil crisis sparked investor interest. However, the price of oil subsided afterwards, and although the 1979 energy crisis caused oil prices to peak again, introduction of the National Energy Program by Pierre Trudeau discouraged foreign investment in the Canadian oil industry. During the 1980s, oil prices declined to very low levels, causing considerable retrenchment in the oil industry, and the third mine, operated by Shell Canada, did not begin operating until 2003. However, as a result of oil price increases since 2003, the existing mines have been greatly expanded and new ones are being planned.
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 1.126 million barrels per day (179,000 m3/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 3 Mbbl/d (480,000 m3/d) by 2020 and possibly 5 Mbbl/d (790,000 m3/d) by 2030.
As of December 2008, the Canadian Association of Petroleum Producers revised its 2008-2020 crude oil forecasts to account for project cancellations and cutbacks as a result of the price declines in the second half of 2008. The revised forecast predicted that Canadian oil sands production would continue to grow, but at a slower rate than previously predicted. There would be minimal changes to 2008-2012 production, but by 2020 production could be 300,000 barrels per day (48,000 m3/d) less than its prior predictions. This would mean that Canadian oil sands production would grow from 1.2 million barrels per day (190,000 m3/d) in 2008 to 3.3 million barrels per day (520,000 m3/d) in 2020, and that total Canadian oil production would grow from 2.7 to 4.1 million barrels per day (430,000 to 650,000 m3/d) in 2020. Even accounting for project cancellations, this would place Canada among the four or five largest oil-producing countries in the world by 2020.
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 was planned to start producing 60,000 barrels per day (9,500 m3/d) of bitumen in 2012 and may reach 200,000 bbl/d (30,000 m3/d) by 2015-2020. BP would modify its Toledo refinery to process 170,000 bbl/d (27,000 m3/d) of bitumen directly to refined products. The joint venture would solve problems for both companies, since Husky was short of refining capacity, and BP had no presence in the oil sands. It was 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 60,000 barrels per day (9,500 m3/d) to 1 million barrels per day (160,000 m3/d) 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 770,000 bbl/d (122,000 m3/d); Syncrude Canada (to 550,000 bbl/d (87,000 m3/d); Suncor Energy (to 500,000 bbl/d (79,000 m3/d) and Canadian Natural Resources (to 500,000 bbl/d (79,000 m3/d). 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.
|Project Name||Type||Major Partners||National
|Suncor||Primarily Mining||Suncor Energy||Canada||239,100||500,000|
|Syncrude||Mining||Syncrude||Canada (some USA)||307,000||550,000|
|Albian Sands||Mining||Shell(60%), Chevron(20%), Marathon(20%)||UK/Netherlands, USA||136,000||770,000|
|MacKay River||SAGD||Suncor Energy||Canada||30,000||190,000|
|Fort Hills||Mining||Suncor Energy(60%), UTS Energy(20%), Teck(20%)||Canada||—||140,000|
|Foster Creek, Christina Lake||SAGD||EnCana Energy(50%), ConocoPhillips(50%)||Canada, USA||6,000||400,000 |
|Surmont||SAGD||Total S.A.(50%),ConocoPhillips(50%)||France, USA||—||193,000|
|Hangingstone||SAGD||Japan Canada Oil Sands (JACOS)||Japan||8,000||30,000|
|Long Lake||SAGD||Nexen(65%), OPTI Canada(35%)||Canada||—||240,000|
|Horizon||Mining and in situ||Canadian Natural Resources Limited||Canada||—||500,000|
|Jackfish I and II||SAGD||Devon Energy||USA||??||70,000|
|Northern Lights||Mining||Total S.A.(60%), Sinopec(40%)||France, China||—||100,000|
|Kearl||Mining||Imperial Oil, ExxonMobil||USA||—||300,000|
|Sunrise||SAGD||Husky Energy(50%), BP(50%)||Canada, UK||—||200,000|
|Oil Sands Project||Mining and SAGD||Total S.A. (76%), Oxy (15%), Inpex (10%)||France, USA, Japan||—||225,000|
|Ells River||SAGD||Chevron(60%), Marathon(20%), Shell(20%)||USA, UK/Netherlands||—||100,000|
|Terre de Grace||SAGD||Value Creation Inc||Canada||—||300,000|
|Kai Kos Dehseh||SAGD||Statoil||Norway||—||200,000 |
|Black Gold Mine||Mining?||Korea National Oil Corporation||Korea||—||30,000 |
The key characteristic of the Athabasca deposit is that it is the only one shallow enough to be suitable for surface mining. About 10% of the Athabasca oil sands are covered by less than 75 metres (246 ft) of overburden. The mineable area as defined by the Alberta government covers 37 contiguous townships (about 3,400 km2/1,300 sq mi) north of the city of Fort McMurray. The overburden consists of 1 to 3 metres of water-logged muskeg on top of 0 to 75 metres of clay and barren sand, while the underlying oil sands are typically 40 to 60 metres thick and sit on top of relatively flat limestone rock. As a result of the easy accessibility, the world's first oil sands mine was started by Great Canadian Oil Sands Limited (a predecessor company of Suncor Energy) in 1967. The Syncrude mine (the biggest mine in the world at 191 km2) followed in 1978, and the Albian Sands mine (operated by Shell Canada) in 2003. All three of these mines are associated with bitumen upgraders that convert the unusable bitumen into synthetic crude oil for shipment to refineries in Canada and the United States. At Albian, the upgrader is located at Scotford, 439 km south. The bitumen, diluted with a solvent is transferred there in a 610 millimetres (24 in) Corridor Pipeline.
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. Depending on the bitumen content in the ore, between 90 and 100% of the bitumen can be recovered using modern hot water extraction techniques. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.
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 1,200 cubic feet (34 m3) of natural gas to produce one barrel of bitumen from in situ projects and about 700 cubic feet (20 m3) for integrated projects. Since a barrel of oil equivalent is about 6,000 cubic feet (170 m3) 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.
Critics contend that government and industry measures taken to minimize environmental and health risks posed by large-scale mining operations are inadequate, causing damage to the natural environment. Objective discussion of the environmental impacts has often been clouded by polarized arguments from industry and from advocacy groups.
Approximately 20% of Alberta's oil sands are recoverable through open-pit mining, while 80% require in situ extraction technologies (largely because of their depth). Open pit mining destroys the boreal forest and muskeg. The Alberta government requires companies to restore the land to "equivalent land capability". This means that the ability of the land to support various land uses after reclamation is similar to what existed, but that the individual land uses may not necessarily be identical. In some particular circumstances the government considers agricultural land to be equivalent to forest land. Oil sands companies have reclaimed mined land to use as pasture for wood bison instead of restoring it to the original boreal forest and muskeg. Syncrude asserts they have reclaimed 22% of their disturbed land.
A Pembina Institute report stated "To produce one cubic metre (m3) of synthetic crude oil (SCO) (upgraded bitumen) in a mining operation requires about 2–4.5 m3 of water (net figures). Approved oil sands mining operations are currently licensed to divert 359 million m3 from the Athabasca River, or more than twice the volume of water required to meet the annual municipal needs of the City of Calgary." and went on to say "...the net water requirement to produce a cubic metre of oil with in situ (emphasis added) production may be as little as 0.2 m3, depending on how much is recycled". Jeffrey Simpson of the Globe and Mail paraphrased this report, saying: "A cubic metre of oil, mined from the tar sands, needs two to 4.5 cubic metres of water.
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.
Water license allocations total about 1% of the Athabasca river average annual 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.
The processing of bitumen into synthetic crude requires energy, and currently this energy is generated by burning natural gas, which releases carbon dioxide. In 2007, the oil sands used around 1 billion cubic feet of natural gas per day, around 40% of Alberta's total usage. Based on gas purchases, natural gas requirements are given by the Canadian Energy Resource Institute as 2.14 GJ (2.04 mcf) per barrel for cyclic steam stimulation projects, 1.08 GJ (1.03 mcf) per barrel for SAGD projects, 0.55 GJ (0.52 mcf) per barrel for bitumen extraction in mining operations not including upgrading or 1.54 GJ (1.47 mcf) per barrel for extraction and upgrading in mining operations.
The forecast growth in synthetic oil production in Alberta also threatens Canada's international commitments. In ratifying the Kyoto Protocol, Canada agreed to reduce, by 2012, its greenhouse gas emissions by 6% with respect to 1990. In 2002, Canada's total greenhouse gas emissions had increased by 24% since 1990. Oil Sands production contributed 3.4% of Canada's greenhouse gas emissions in 2003.
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.
The Athabasca oil sands are located in the northeastern portion of the Canadian province of Alberta, near the city of Fort McMurray. The area is only sparsely populated, and in the late 1950s, it was primarily a wilderness outpost of a few hundred people whose main economic activities included fur trapping and salt mining. From a population of 37,222 in 1996, the boomtown of Fort McMurray and the surrounding region (known as the Regional Municipality of Wood Buffalo) grew to 79,810 people as of 2006, including a "shadow population" of 10,442 living in work camps, leaving the community struggling to provide services and housing for migrant workers, many of them from Eastern Canada, especially Newfoundland. Fort McMurray ceased to be an incorporated city in 1995 and is now an urban service area within Wood Buffalo.
The Alberta government's Energy and Utilities Board (EUB) estimated in 2007 that about 173 billion barrels (27.5×109 m3) of crude bitumen are economically recoverable from the three Alberta oil sands areas based on benchmark WTI market prices of $62 per barrel in 2006, rising to a projected $69 per barrel in 2016 using current technology. This was equivalent to about 10% of the estimated 1,700 billion barrels (270×109 m3) of bitumen-in-place. In fact WTI prices topped $133 in May 2008. Alberta estimated that the Athabasca deposits alone contain 35 billion barrels (5.6×109 m3) of surface mineable bitumen and 98 billion barrels (15.6×109 m3) of bitumen recoverable by in-situ methods. These estimates of Canada's reserves were doubted when they were first published but are now largely accepted by the international oil industry. This volume placed Canadian proven reserves second in the world behind those of Saudi Arabia.
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 unconventional 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 3 million barrels per day (480×103 m3/d), 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 Oil 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.
Despite the large reserves, the cost of extracting the oil from bituminous sands has historically made production of the oil sands unprofitable—the cost of selling the extracted crude would not cover the direct costs of recovery; labour to mine the sands and fuel to extract the crude.
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.
The Athabasca Oil Sands are now featured prominently in international trade talks, with energy rivals China and the United States negotiating with Canada for a bigger share of the oil sands' rapidly increasing output. Output at the oil sands is expected to quadruple between 2005 and 2015, reaching 4 million bbl/day, increasing their political and economic importance. Currently most of the oil sands production is exported to the United States.
An agreement has been signed between PetroChina and Enbridge to build a 400,000 barrels per day (64,000 m3/d) 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 150-million-barrel-per-day (24,000,000 m3/d) 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.
On August 20, 2009, the U.S. State Department issued a presidential permit for an Alberta Clipper Pipeline that will run from Hardisty, Alberta to Superior, Wisconsin. The pipeline will be capable of carrying up to 450,000 barrels of crude oil a day from the Athabasca Oil Sands to U.S. refineries.
Indigenous peoples of the area include the Fort McKay First Nation. The oil sands themselves are located within the boundaries of Treaty 8, signed in 1899. The Fort McKay First Nation has formed several companies to service the oil sands industry and will be developing a mine on their territory. Opposition remaining within the First Nation focuses on environmental stewardship issues.
Major producing or planned developments in the Athabasca Oil Sands include the following projects:
|Royal Dutch Shell||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)||2009||Operating|
|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|
In August 2008 the British Advertising Standards Authority (ASA) ruled that Royal Dutch Shell had misled the public by claiming that its oil sands project in Alberta was a "sustainable energy source". Although widely used, "sustainable" had been deemed a "vague" and "ambiguous" term, in light of DEFRA's advice that companies should avoid vague environmentally-friendly terms intended to simply give a good impression. They concluded the claim of sustainability was misleading "[b]ecause we had not seen data that showed how Shell was effectively managing carbon emissions from its oil sands projects in order to limit climate change".