Athabasca Oil Sands

The Athabasca Oil Sands are a large deposit of oil-rich bitumen located in northern Alberta, Canada. These oil sands 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 of three oil sands deposits in Alberta, along with the Peace River and Cold Lake deposits. Together, these oil sand deposits cover about 141 000 km² of sparsely populated boreal forest and muskeg (peat bogs). 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.^[1] The oil deposits are located within the boundaries of Treaty 8, and several First Nations of the area are involved with the sands. The oil sands were first seen by Europeans in 1788.

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 square kilometres (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 (now Suncor) back in 1967. The Syncrude mine (the biggest mine in the world) 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, though in Albian's case, the upgrader is not co-located with the mine, but at Scotford, 439 km south. The bitumen, diluted with a solvent is transferred there in a 610 millimetres (24 in) Corridor Pipeline.

The Athabasca oil sands are primarily located in and around the city of Fort McMurray which was still, in the late 1950s, primarily a wilderness outpost of a few hundred people whose main economic activities included fur trapping and salt mining. Since the energy crisis of the 1970s, Fort McMurray has been transformed into a boomtown of 80,000 people struggling to provide services and housing for migrant workers, many of them from Eastern Canada, especially Newfoundland.

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Estimated oil reserves

Alberta Government calculates that about 28 billion cubic metres (174 billion barrels) of crude bitumen are economically recoverable from the three Alberta oil sands areas at current prices using current technology. This is equivalent to about 10% of the estimated 1,700 and 2,500 billion barrels of bitumen in place.^[2] Alberta estimates that the Athabasca deposits alone contain 5.6 billion cubic metres (35 billion barrels) of surface mineable bitumen and 15.6 billion cubic metres (98 billion barrels) of bitumen recoverable by in-situ methods. These estimates of Canada's oil reserves caused some astonishment when they were first published but are now largely accepted by the international community. This volume places Canadian proven oil 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 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 extremely easy to find. One risk is economic risk of low oil prices and with the oil price increases of 2004-2006, this economic risk evaporated.

The Alberta estimates in some ways are extremely conservative, since they assume a recovery rate of around 20% of bitumen in place, whereas oil companies using the new steam assisted gravity drainage (SAGD) method of extracting bitumen report that they can recover over 60% with little effort. These much higher recovery rates probably mean that the ultimate production could be several times as high as the already very large government estimates.

At rate of production projected for 2015, about 3,000,000 barrels (~510,000 t) per day, the Athabasca oil sands reserves would last over 400 years. ^[3] However, production cannot increase to those levels without a huge influx of workers into northern Alberta, which by 2006 was already occurring. This need created a severe labor shortage in Alberta, which by 2007 drove unemployment rates in Alberta and adjacent British Columbia to the lowest levels in history. Even as far away as the Atlantic Provinces, where workers were leaving to work in Alberta, unemployment rates fell to levels not seen for over 100 years.^[4]

The Venezuelan Orinoco tar sands site may contain more oil sands than Athabasca (see tar sands article). 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.  

Economics

Despite the large reserves, the cost of extracting the oil from the sand 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 $9 to $12 per barrel, while the cost of an in-situ SAGD operation (using dual horizontal wells) would be $10 to $14 per barrel. This compares to operating costs for conventional oil wells which can range from less than $1 per barrel in Iraq and Saudi Arabia to $6 and up in the United States and Canada's conventional oil reserves.

In addition, the capital cost of the equipment, such as the huge machines required to mine the sands and the dump trucks used to haul it to processing, is a major consideration in starting production. The NEB estimates that capital costs raise the total cost of production to $18 to $20 per barrel for a new mining operation and $18 to $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 $36 to $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 enormous 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 almost always cover incremental operating costs.

However, the development of commercial production is made easier by the fact that exploration costs are virtually nil. 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 tar sands are well known and an estimate of recovery costs can usually be made easily. Most important, the oil sands are in a politically stable area - there is not another region in the world with energy deposits of this magnitude where it would be less likely that these expensive 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 of 2004-2006, the economics of oil sands have improved dramatically. At a world price of $50 per barrel, the NEB estimates an integrated mining operation would make a rate return of 16 to 23 percent, while a SAGD operation would return 16 to 27 percent. Prices in 2006 have been considerably higher than that. As a result, capital expenditures in the oil sands announced for the period 2006 to 2015 exceed $100 billion, which is twice the amount projected as recently as 2004. However, due to 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, Alberta, has seen the most effect from the increased activity in the oil sands. However, 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.^[5]

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.^[6]. 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 and driven Alberta's unemployment rates to the lowest levels in history.^[7]

Oil Sands Production

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 the oil sands to the Hudson's Bay Company post at Fort Churchill. In 1719, fur trader Henry Kelsey became the first white man to see the outcroppings along the Athabasca River and he noted that the native people used it to waterproof their canoes.^[8] In 1883, 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. However, it was nearly a century before extracting it became commercially viable. Dr. Karl Clark of the University of Alberta, perfected a steam separation process for the tar sands in 1926.

Commercial production of oil from the Athabasca oil sands began in 1967, when Great Canadian Oil Sands (now Suncor) opened its first mine, producing 30,000 barrels per day 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 caused the oil companies and the Alberta government under Premier Peter Lougheed to pull the plug on new developments. Once more, 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, with Oil price increases of 2004-2006, the existing mines have been greatly expanded and new ones are being planned.

According to the Alberta Energy and Utilities Board, production of crude bitumen in the Athabasca oil sands was as follows:

This was despite a major fire at the Suncor operation, a major turnaround at Syncrude, and operational problems at the Shell operation. Combined oil production in all three Alberta oil sands areas was 169,100 m3/day or 1,065,000 bpd.

Future production

With planned projects coming on stream, by 2010 oil sands production is projected to reach 2 million barrels per day or about two thirds of Canadian production. By 2015 Canadian oil production may reach 4 million barrels per day, of which only 15% will be conventional crude oil. The Canadian Association of Petroleum Producers predicts that by 2020 Canadian oil production will reach 4.8 million barrels per day, of which only about 10% will be conventional light or medium crude oil, and most of the rest will be crude bitumen and synthetic crude oil from the Athabasca oil sands.

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 60,000 barrels per day (10,000 m³/d) 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.^[9]

In mid December 2007, ConocoPhillips announced its intention to increase its oil sands production from 60,000 barrels per day (10,000 m³/d) to 1 million bpd (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 oilsands 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 bpd or 125,000 m³/d); Syncrude Canada (to 550,000 bpd or 90,000 m³/d); Suncor Energy (to 500,000 bpd or 80,000 m³/d) and Canadian Natural Resources (to 500,000 bpd or 80,000 m³/d).^[10] If all these plans come to fruition, these five companies will be producing over 3.3 million bpd (500,000 m³/d) of oil from oil sands by 2028.

Extraction of oil

See main article on Oil sands extraction

The original process of extraction used at the oil sands was developed by Dr. Karl Clark, working with the Research Council of Alberta in the 1920s.^[11] Historically (since the 1960s), the oil sands have been mined in huge open pit mines and extracted from the sand by variations of the Clark water-based extraction process, which separates aerated bitumen from the other oil sand components in gravity settling vessels. More recently, new in-situ methods 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 also 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 by a factor of 2.5 times.^[12]

According to the National Energy Board, it requires about 1200 cubic feet of natural gas to produce one barrel of bitumen from in situ projects and about 700 cubic feet for integrated projects.^[13] Since a barrel of oil equivalent is about 6000 cubic feet 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,^[14] is designed to provide its own fuel, by on-site cracking of the bitumen mined.^[15] It is supposed to start extracting bitumen in 2006, and "upgrading" of bitumen to liquid oil in 2007, producing 60,000 bbl/day of usable oil. If it works, the natural gas problem becomes less of an issue and the problem of disposing of tailings disappears.

Geopolitical importance

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. Although most of the oil sands production is currently exported to the United States, that could change.

An agreement has been signed between PetroChina and Enbridge to build a 400,000 barrel-per-day 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 150,000-barrel-per-day 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.

India has announced plans to invest $1 billion in the Athabasca Oil Sands in 2006. As many as four different Indian oil companies, such as Oil and Natural Gas Corporation and Indian Oil Corporation, are involved.^[16]

Indigenous peoples of the area

Indigenous peoples of the area include the Fort McKay First Nation and the Fort McMurray 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.^[17] However, support within the First Nation for such development is not unanimous.

Environmental impacts

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. ^{[18] [19]}

The open-pit mining of the Athabasca oils sands destroys the boreal forest and muskeg, as well as changing the natural landscape. The Alberta government does not require companies to restore the land to "original condition" but only 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 will not necessarily be identical.^[20] Since the government considers agricultural land to be equivalent to forest land, oil sands companies have reclaimed mined land to use as pasture for buffalo, rather than restoring it to the original boreal forest and muskeg.

For every barrel of synthetic oil produced in Alberta, more than 80 kg of greenhouse gases are released^{[citation needed]} into the atmosphere and between 2 and 4 barrels^{[citation needed]} of waste water are dumped into tailing ponds that have replaced about 50 km²^{[citation needed]} of forest. 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.

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." ^[21] 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. Approved oil sands mining operations -- not the in situ kind that extract oil from tar sands far below the surface -- will take twice the annual water needs of the City of Calgary. The water will come from the Athabasca River, from which 359-million cubic metres will be diverted." ^[19] However, the Athabasca River is much bigger than the small rivers that flow through Calgary, and current oil sands water license allocations are only for about 1% of the flow of the river. ^[22] The Alberta government sets strict limits on how much water oil sands companies can remove from the Athabasca River, and during low-flow conditions orders them to reduce their withdrawals. ^[23]

Ranked as the world's eighth largest emitter of greenhouse gases ^[24], Canada is a relatively large emitter given its population. The United States, which has not signed the Kyoto Protocol, is the world's largest emitter at a fluctuating 25% of the total. China is the second largest emitter at 20%, but as a developing country is exempt from controls. Its economy has been growing rapidly, and as a result the International Energy Agency expects it to exceed the U.S. as the world's largest emitter of carbon dioxide by about 2008. Other developing countries in Asia and Africa have also been increasing their emissions rapidly. However, it is developed nations that are responsible for the vast majority of historic emissions which are now causing climate change. Most European countries have missed their reduction targets, as has Canada. A major Canadian initiative called the Integrated CO2 Network (ICO2N) [[1]] 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.

Oil sand companies

There are currently three large oil sands mining operations in the area run by Syncrude Canada Limited, Suncor Energy and Albian Sands owned by Shell Canada, Chevron, and Western Oil Sands Ltd.

Major producing or planned developments in the Athabasca Oil Sands include the following projects:^[25]

• Suncor Energy's Steepbank and millennium mines currently produce 263,000 barrels per day and its Firebag in-situ project produces 35,000 bpd. It intends to spend $3.2 billion to expand its mining operations to 400,000 bpd and its in-situ production to 140,000 bpd by 2008.
• Syncrude's Mildred Lake and Aurora mines currently can produce 360,000 bpd.
• Shell Canada currently operates its Muskeg River mine producing 155,000 bpd and the Scotford Upgrader at Fort Saskatchewan, Alberta. Shell intends to open its new Jackpine mine and expand total production to 500,000 bpd over the next few years.
• Nexen's in-situ Long Lake SAGD project is on schedule to produce 70,000 bpd by late 2007, with plans to expand it to 240,000 bpd over the next 10 years.
• CNRL's $8 billion Horizon mine is planned to produce 110,000 bpd on startup in 2008 and grow to 300,000 bpd by 2010.
• Total S.A.'s subsidiary Deer Creek Energy is operating a SAGD project on its Joslyn lease, producing 10,000 bpd. It intends on constructing its mine by 2010 to expand its production by 100,000 bpd.
• Imperial Oil's $5 to $8 billion Kearl Oil Sands Project is projected to start construction in 2008 and produce 100,000 bpd by 2010. Imperial also operates a 160,000 bpd in-situ operation in the Cold Lake oil sands region.
• Synenco Energy and SinoCanada Petroleum Corp., a subsidiary of Sinopec, China's largest oil refiner, had agreed to create the $3.5 billion Northern Lights mine, projected to produce 100,000 bpd by 2009. This project has since been indefinitely deferred (as of 2007).^[26]
• North American Oil Sands Corporation (NAOSC), a subsidiary of StatoilHydro, is expected to produce in the Kai Kos Dehseh project around 100,000 bpd by 2015. It is expected to ramp up production to around 100,000 barrels per day by around 2015.^[27]

See also

• Canadian Centre for Energy Information
• History of the petroleum industry in Canada (oil sands and heavy oil)
• Mackenzie Valley Pipeline

References

Coordinates: 57.02° N 111.65° W