Athabasca oil sands

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Athabasca oil sands
Athabasca Oil Sands map.png
CountryCanada
RegionNorthern Alberta
Offshore/onshoreOnshore, mining
Coordinates57°01′N 111°39′W / 57.02°N 111.65°W / 57.02; -111.65Coordinates: 57°01′N 111°39′W / 57.02°N 111.65°W / 57.02; -111.65
OperatorsSyncrude, Suncor, CNRL, Shell, Total, Imperial Oil, Petro Canada, Devon, Husky, Statoil, Nexen
PartnersChevron, Marathon, ConocoPhillips, BP, Oxy
Field history
Discovery1848
Start of production1967
Production
Current production of oil1,300,000 barrels per day (~6.5×10^7 t/a)[1]
Estimated oil in place133,000 million barrels (~1.81×10^10 t)[2]
Producing formationsMcMurray, Clearwater, Grand Rapids
 
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Athabasca oil sands
Athabasca Oil Sands map.png
CountryCanada
RegionNorthern Alberta
Offshore/onshoreOnshore, mining
Coordinates57°01′N 111°39′W / 57.02°N 111.65°W / 57.02; -111.65Coordinates: 57°01′N 111°39′W / 57.02°N 111.65°W / 57.02; -111.65
OperatorsSyncrude, Suncor, CNRL, Shell, Total, Imperial Oil, Petro Canada, Devon, Husky, Statoil, Nexen
PartnersChevron, Marathon, ConocoPhillips, BP, Oxy
Field history
Discovery1848
Start of production1967
Production
Current production of oil1,300,000 barrels per day (~6.5×10^7 t/a)[1]
Estimated oil in place133,000 million barrels (~1.81×10^10 t)[2]
Producing formationsMcMurray, Clearwater, Grand Rapids

The Athabasca oil sands (also called the Athabasca tar sands or Alberta tar sands) are large deposits of bitumen or extremely heavy crude oil, located in northeastern Alberta, Canada – roughly centred on 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 known 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.[3]

Together, these oil sand deposits lie under 141,000 square kilometres (54,000 sq mi) of boreal forest and muskeg (peat bogs) and contain about 1.7 trillion barrels (270×10^9 m3) of bitumen in-place, comparable in magnitude to the world's total proven reserves of conventional petroleum. Although the former CEO of Shell Canada, Clive Mather, estimated Canada's reserves to be 2 trillion barrels (320 km3) or more, the International Energy Agency (IEA) lists Canada's reserves as being 178 billion barrels (2.83×1010 m3).[3]

With modern unconventional oil production technology, at least 10% of these deposits, or about 170 billion barrels (27×10^9 m3) were considered to be economically recoverable at 2006 prices, making Canada's total proven reserves the second largest in the world, after Saudi Arabia's.[4] Canada’s oil sands are found in three deposits –The Athabasca oil sands deposit is the largest of Canada's three oil sands. The two others are in the Peace River and Cold Lake areas in Alberta and part of Saskatchewan. By 2009, the two extraction methods used were in situ (Latin, meaning "in place") extraction, when the bitumen occurs deeper within the ground, (which will account for 80 percent of oil sands development) and surface or open-pit mining, when the bitumen is closer to the surface. Only 20 percent of bitumen can be extracted using open pit mining methods,[5] which involves large scale excavation of the land with huge hydraulic power shovels and 400-ton heavy hauler trucks. Surface mining leaves toxic tailings ponds. In contrast, in situ uses more specialized techniques such as Steam-assisted gravity drainage (SAGD). "Eighty per cent of the oil sands will be developed in situ which accounts for 97.5 per cent of the total surface area of the oil sands region in Alberta."[6] In 2006 the Athabasca deposit was the only large oil sands reservoir in the world which was suitable for large-scale surface mining, although most of it can only be produced using more recently developed in-situ technology.[4]

On 17 June 2013 the newly formed corporation, Alberta Energy Regulator (AER) [7] was phased in with a mandate to regulate oil, gas and coal development in Alberta including the Athabasca oil sands.[8][9] The AER brings together "the regulatory functions from the Energy Resources Conservation Board and the Alberta Ministry of Environment and Sustainable Resource Development into a one-stop shop" [10] The Alberta Energy Regulator is now "responsible for all projects from application to reclamation." They will respond to project proponents, landowners and industry regarding energy regulations in Alberta.[10] The Responsible Energy Development Act gave the Alberta Energy Regulator "the authority to administer the Public Lands Act, the Environmental Protection and Enhancement Act and the Water Act, with regards to energy development."[10] The Alberta Energy Regulator will enforce environmental laws and issue environmental and water permits, responsibilities formerly the mandate of Alberta Environment.[8][11]

History[edit]

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.[12] The oil deposits are located within the boundaries of Treaty 8, and several First Nations of the area are involved with the sands.

Athabasca oil sands on the banks of the river, c. 1900

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 exploring the Methye Portage which allowed access to the rich fur resources of the Athabasca River system from the Hudson Bay watershed.[13]

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 John Franklin.[14]

John Richardson did the first serious scientific 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, 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."[13]

Count Alfred von Hammerstein (1870–1941), who arrived in the region in 1897, promoted the Athabaska oil sands for over forty years, taking photos with descriptive titles such as "Tar Sands and Flowing Asphaltum in the Athabasca District," that are now in the National Library and National Archives Canada. Photos of the Athabasca oil sands were also featured in Canadian writer and adventurer, Agnes Deans Cameron's, best-selling book(Cameron & 1908 71)[15] entitled The New North: Being Some Account of a Woman’s Journey through Canada to the Arctic which recounted her 10,000 mile-round trip to the Arctic Ocean. Following this journey and the publication of her book, she travelled extensively as lecturer, with magic lantern slides of her Kodak images, promoting immigration to western Canada at Oxford, Cambridge, St. Andrew’s University and the Royal Geographical Society.[16] Her photographs were reproduced in 2011-2012 in an exhibit at the Canadian Museum of Civilization in Ottawa, Canada.(Gismondi & 2012 71)[17] Cameron was particularly enthusiastic about the Athabaska region and the Athabaska oil sands which included photos of Count Alfred Von Hammerstein's oil drill works along the Athabasca River. "While the Count was unsuccessful drilling for "elephant pools of oil," Cameron’s book and its images... made her a media celebrity."(Gismondi & 2012 71)[17] "In all Canada there is no more interesting stretch of waterway than that upon which we are entering. An earth-movement here has created a line of fault clearly visible for seventy or eighty miles along the river-bank, out of which oil oozes at frequent intervals. […] Tar there is […] in plenty. […] It oozes from every fissure, and into some bituminous tar well we can poke a twenty foot pole and find no resistance.(1909 & Cameron 71)[15] cited in (Gismondi & 2012 71)[17]

In 1926, Karl Clark of the University of Alberta received a patent for a hot water separation process which was the forerunner of today's thermal extraction processes. 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 Earl W. Malmberg of Sun Oil Company.

Oil sands production[edit]

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 incorporated into 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.[18] 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, during the 1980s, oil prices declined to very low levels causing considerable retrenchment in the oil industry. 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:

2005 Productionm3/daybbl/day
Suncor Mine31,000195,000
Syncrude Mine41,700262,000
Shell Canada Mine26,800169,000
In Situ Projects21,300134,000
Total120,800760,000

As of 2006, 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.[19] As of 2010, oil sands production had increased to over 1.6 million barrels per day (250,000 m3/d), where 53% of this was produced by surface mining and 47% by in-situ. The Alberta government believes this level of production could reach 3.5 Mbbl/d (560,000 m3/d) by 2020 and possibly 5 Mbbl/d (790,000 m3/d) by 2030.[20]

Transportation[edit]

Canada is the largest source of oil imported by the United States, supplying nearly a million barrels a day from oil sand sources. Keystone XL, a pipeline from Alberta to Gulf coast refineries, is under consideration,[21] as is the North Gateway project to Kitimat, B.C. which would be built by Enbridge, operator of the Enbridge Pipeline System which also serves the area.[22] Industry observers believe there may be excess pipeline capacity.[23] Kinder Morgan has made another proposal for a west coast pipeline while Enbridge also proposes Eastern Access, a pipeline to refineries in Montreal and possibly to a terminal in Portland, Maine, as well as expansion of an existing pipeline to Chicago.[24] Environmental and First Nations opposition to all these projects is anticipated, and planned.[25]

Future production[edit]

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 (429,000 to 652,000 m3/d) in 2020.[26] 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 (32,000 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.[27]

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 (4,000 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)).[28] If all these plans come to fruition, these five companies will be producing over 3.3 Mbbl/d (520,000 m3/d) of oil from oil sands by 2028.

Major Athabasca Oil Sands Projects (as of December 2007)[29]
Project NameTypeMajor PartnersNational
Affiliation
2007 Production
(barrels/day)
Planned Production
(barrels/day)
SuncorPrimarily MiningSuncor EnergyCanada239,100500,000
SyncrudeMiningSyncrudeCanada (some China, USA)307,000550,000
Albian SandsMiningShell(60%), Chevron(20%), Marathon(20%)[30]UK/Netherlands, USA136,000770,000
MacKay RiverSAGDSuncor EnergyCanada  30,000190,000
Fort HillsMiningSuncor Energy(60%), UTS Energy(20%), Teck(20%)[31]Canada  —140,000
Foster Creek, Christina Lake[32]SAGDCenovus Energy[33](50%), ConocoPhillips(50%)Canada, USA    6,000400,000 [34]
SurmontSAGDTotal S.A.(50%), ConocoPhillips(50%)France, USA193,000[34]
Hangingstone[35]SAGDJapan Canada Oil Sands (JACOS)Japan    8,000  30,000
Long LakeSAGDNexen(65%), OPTI Canada(35%)[36][37]Canada240,000
HorizonMining and in situCanadian Natural Resources LimitedCanada500,000[38]
Jackfish I and IISAGDDevon EnergyUSA ??  70,000[39]
Northern LightsMiningTotal S.A.(60%), Sinopec(40%)[40][41][42]France, China100,000
KearlMiningImperial Oil, ExxonMobilUSA300,000[43]
SunriseSAGDHusky Energy(50%), BP(50%)[44]Canada, UK200,000[44]
TuckerSAGDHusky EnergyCanada ??30,000[45]
Oil Sands ProjectMining and SAGDTotal S.A. (76%), Oxy (15%), Inpex (10%)France, USA, Japan225,000
Ells RiverSAGDChevron(60%), Marathon(20%), Shell(20%)USA, UK/Netherlands100,000[46]
Terre de GraceSAGDValue Creation IncCanada300,000[47]
Kai Kos DehsehSAGDStatoilNorway200,000[48]
SaleskiSAGDLaricina Energy(60%), OSUM(40%)Canada270,000[49]
Black Gold MineMining?Korea National Oil CorporationSouth Korea  30,000[50]
Total726,1005,068,000   

Governance[edit]

The governance of the Alberta oil sands is focused on economic development, and has historically been dominated by the interests of two primary actors; government (federal and provincial) and industry. Canadian federalism forms the functions and roles of each level of government, in that constitutional power is split so that neither is superior to the other.[51] The Constitution Act, 1867, Section 109 ensures the province full ownership of the lands and resources within its borders. The province acts as the landowner and the federal government oversees jurisdiction over trade, commerce and taxation. There is a clear overlap, as resource management influences trade, and trade management influences resources.[52] As of the 1990s, both the federal and provincial government have been aligned, focusing on regulation, technology and the development of new export markets.[53] The majority of “ground-level” governance is carried out by a number of provincial institutions.

Ottawa has avoided direct investment, preferring to improve the investment climate. A prime example of this occurred in 1994, when the federal government rolled out tax breaks allowing 100% of oil sands capital investments to be written off as accelerated capital cost allowances.[54] The provincial government had a much more direct role in development; investing directly in numerous pilot projects, undertaking joint ventures with the industry and consistently making massive investments in research and development. Alberta features one of the lowest royalty rates in the world.[55] This industry-centric royalty system is criticised for "promoting a runaway pace of development".[56][57]

Industry is the core force of oil sands development. The first major players, Suncor Energy and Syncrude, dominated the market until the 1990s. Currently there are 64 companies operating several hundred projects.[58] The majority of production now comes from foreign-owned corporations,[59] and the necessity of maintaining a favourable climate for these corporations grants them strong influence; much stronger than that of non-productive stakeholders, such as citizens and environmental groups.[56]

Governance (policy, administration, regulation) over the oil sands is held almost entirely by the Ministry of Energy (Alberta) and its various departments. Critics noted a clear and systemic lack of public involvement at all key stages of the governance process.[60] In answer to this, the province initiated the Oil Sands Consultations Multistakeholder Committee (MSC) in 2006. The MSC represents four organisations: the Cumulative Environmental Management Association (CEMA), the Wood Buffalo Environmental Association (WBEA), the Canadian Oil Sands Network for Research and Development (CONRAD) and the Athabasca Regional Issues Working Group (RIWG).[56] The role of the MSC is to consult and make recommendations on management principles.[61] The recommendations contained in the MSC’s first 2007 Final Report were lauded by several ministers and government representatives,[62] but none have yet been effectively passed into law.

On October 17, 2012, the Alberta government announced it would follow the recommendations of a working group to develop an agency that would monitor the environmental impact of the oil sands. "The new science-based agency will begin work in the oil sands region and will focus on what is monitored, how it’s monitored and where it’s monitored. This will include integrated and coordinated monitoring of land, air, water and biodiversity," said a press release from Diana McQueen's office, the Minister of Energy and Sustainable Development.[63] The provincial government moved to develop the agency after widespread public criticism by environmentalists, aboriginal groups and scientists, who claimed the oil sands would have a devastating, long-term effect on the environment if left unchecked.[64]

Development[edit]

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. Until 2009, the surface mineable area (SMA) was defined by the ERCB, an agency of the Alberta government, to cover 37 contiguous townships (about 3,400 km2 or 1,300 sq mi) north of the city of Fort McMurray. In June 2009, the SMA was expanded to 51.5 townships, or about 4,700 km2 or 1,800 sq mi.[65] This expansion pushes the northern limit of the SMA to within 12 miles (19 km) of Wood Buffalo National Park, a UNESCO World Heritage Site.

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 followed in 1978 and is now the largest mine (by area) in the world at 191 km2.[66]

The Albian Sands mine (operated by Shell Canada) opened 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. For 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 Energy Resource Conservation Board has approved over 100 mining and in-situ projects despite the negative environmental impacts. [67] As of 2012, there was 9 active open mining projects, more than 50 approved in-situ projects as well as 190 primary recovery projects extracting bitumen that is free flowing. The ERCB has also approved 20 projects that are testing unproven technology as well as new versions of existing technologies.[68]

Bitumen extraction[edit]

The original process for extraction of bitumen from the sands was developed by Dr. Karl Clark, working with the Alberta Research Council in the 1920s.[69] 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.[70]

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.[71] After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.

Steam-assisted gravity drainage[edit]

See main article - Steam-assisted gravity drainage. Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation in which a pair of horizontal wells are drilled into the oil reservoir, one a few metres above the other. High pressure steam is continuously injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain into the lower wellbore, where it is pumped out to a bitumen recovery facility. Dr. Roger Butler, engineer at Imperial Oil from 1955 to 1982, invented steam assisted gravity drainage (SAGD) in the 1970s. Butler "developed the concept of using horizontal pairs of wells and injected steam to develop certain deposits of bitumen considered too deep for mining."[72][73]

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.[74]

The standard extraction process requires huge amounts of natural gas. As of 2007, the oil sands industry used about 4% of the Western Canada Sedimentary Basin natural gas production. By 2015, this may increase 2.5 fold.[75]

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.[76] 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 probably turn to bitumen gasification to generate their own fuel. In much the same way as bitumen can be converted into synthetic crude oil, it can also be converted into synthetic natural gas.

In 2006, in-situ extraction on a commercial scale was in its early stages.(Nexen 2006) Nearing completion, the Long Lake Project, was designed to provide its own fuel, by on-site hydrocracking of the bitumen extracted.(Nexen 2006)[77] Long Lake Phase 1 is extracting 34,500 barrels per day (5,490 m3/d) of bitumen as of 2012, ramping towards a target of 72,000.(Reuters 2012)[78]

Environmental impacts[edit]

Mining operations in the Athabasca oil sands. Image shows the Athabasca River about 600m from the tailings pond. NASA Earth Observatory photo, 2009.

Critics contend that government and industry measures taken to reduce environmental and health risks posed by large-scale mining operations are inadequate, causing unacceptable damage to the natural environment and human welfare.[79][80] Objective discussion of the environmental impacts has often been clouded by polarized arguments from industry and from advocacy groups.[81][82][83]

Land[edit]

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, while in situ extraction technologies cause less significant damage. 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.[84]

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,[85] a figure disputed by other sources, who assess Syncrude more accurately reclaimed only 0.2% of its disturbed land.[86]

Water[edit]

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."[87] and went on to say "...the net water requirement to produce a cubic metre of oil with in situ 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." Though actual water withdrawals for conventional production run at even less than the 0.2 m3 needed for in situ production.

The Athabasca River runs 1,231 kilometres from the Athabasca Glacier in west-central Alberta to Lake Athabasca in northeastern Alberta.[88] The average annual flow just downstream of Fort McMurray is 633 cubic metres per second[89] with its highest daily average measuring 1,200 cubic metres per second.[90]

Water licence allocations total about 1% of the Athabasca River average annual flow, though actual withdrawals for all uses, in 2006, amount to about 0.4%.[91] 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.[92] The province of Alberta is also looking into cooperative withdrawal agreements between oil sands operators.[93]

Since the beginning of the oil sands development, there have been several leaks into the Athabasca River polluting it with oil and tailing pond water. The close proximity of the tailing ponds to the river drastically increases the likely hood of contamination due to ground water leakages. In 1997, Suncor admitted that their tailing ponds had been leaking 1,600 cubic meters of toxic water into the river a day. This water contains naphthenic acid, trace metals such as mercury and other pollutants. The Athabasca River is the largest freshwater delta in the world but with Suncor and Syncrude leaking tail ponds the amount of polluted water will exceed 1 billion cubic meters by 2020.[94]

Natural toxicants derived from bitumen in Northern Alberta pose potential ecological and human health risks to northerners living in the area. Oil sands development contributes arsenic, cadmium, chromium, lead, mercury, nickel other metal elements toxic at low concentrations to the tributaries and rivers of the Athabasca.[95]

Natural gas use and greenhouse gases[edit]

The processing of bitumen into synthetic crude requires energy, which is currently being generated by burning natural gas. In 2007, the oil sands used around 1 billion cubic feet (28,000,000 m3) 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 thousand cu ft) per barrel for cyclic steam stimulation projects, 1.08 GJ (1.03 thousand cu ft) per barrel for SAGD projects, 0.55 GJ (0.52 thousand cu ft) per barrel for bitumen extraction in mining operations not including upgrading or 1.54 GJ (1.47 thousand cu ft) per barrel for extraction and upgrading in mining operations.[96]

A 2009 study by CERA estimated that production from Canada's oil sands emits "about 5 percent to 15 percent more carbon dioxide, over the "well-to-wheels" lifetime analysis of the fuel, than average crude oil."[97] Author and investigative journalist David Strahan that same year stated that IEA figures show that carbon dioxide emissions from the oil sands are 20% higher than average emissions from oil, explaining the discrepancy as the difference between upstream emissions and life cycle emissions.[98] He goes on to say that a US government report in 2005 suggested with current technology conventional oil releases 40 kg of carbon dioxide per barrel while non-conventional oil releases 80–115 kg of carbon dioxide. Alberta energy suggests lower releases of carbon with improving technology, giving a value of 39% drop in emissions per barrel between 1990 and 2008,[99] however only a 29% reduction between 1990 and 2009.[100]

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.[101]

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) promotes the development of large scale capture, transport and storage of carbon dioxide (CO2) as a means of helping Canada to help meet climate change objectives while supporting economic growth. ICO2N members represent a group of industry participants, many oil sands producers, providing a framework for carbon capture and storage development in Canada.[102]

Animals[edit]

There has been a great impact of the wildlife surrounding the Athabasca River due to pollutants entering the water system creating numerous issues. Studies have shown that hundreds to thousands of birds each year die due to the affects of tailing ponds. Many birds migrate across the country landing in waters to rest, while these birds do not realize that landing on these waters can lead to an 80-90% of death. Although there has not been any standardized research to acquire the exact number of yearly bird fatalities, there has been data recorded since the 1970s on the number of birds founds on tailing ponds.[103]

There has also been a large impact on the fish that live and spawn in the area. As toxins accumulate in the river due to the oil sands, bizarre mutations, tumours and deformed fish species have begun to appear. A study commissioned by the regions health authority, found that several known toxins and carcinogens were elevated.[104] Aboriginal communities that live around the river are becoming increasingly worried about how the animals they eat and their drinking water are being affected.[105]

While there has been no link yet made between the oil sands and health issues, Matt Price of Environmental Defense says the connection makes common sense. Deformities in fish and high concentrations of toxic substances in animals have also been identified.[106]

Population[edit]

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,[107] 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.[108]

Estimated oil reserves[edit]

The Alberta government's Energy and Utilities Board (EUB) estimated in 2007 that about 173 billion barrels (27.5×10^9 m3) of crude bitumen were economically recoverable from the three Alberta oil sands areas based on then-current technology and price projections from the 2006 market prices of $62 per barrel for benchmark West Texas Intermediate (WTI), rising to a projected $69 per barrel. This was equivalent to about 10% of the estimated 1,700 billion barrels (270×10^9 m3) of bitumen-in-place.[2] Alberta estimated that the Athabasca deposits alone contain 35 billion barrels (5.6×10^9 m3) of surface mineable bitumen and 98 billion barrels (15.6×10^9 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.

Syncrude's Mildred Lake mine site and plant

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 (480×10^3 m3/d), the Athabasca oil sands reserves would last over 170 years.[109] 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.[110]

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.[citation needed]

Economics[edit]

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.

Oil prices 1996–2008 (not adjusted for inflation)

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.[111] 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[citation needed].

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$145 in mid-2008 but falling back to less than 40 US$ as a result of the worldwide financial crisis, the oil price recovered slowly and many of the planned projects (expected to exceed C$100 billion between 2006 and 2015) were stopped or scheduled. In 2012 and 2013 the oil price was high again, but the US production is increasing due to new technologies, while the gasoline demand is falling, so there is an overproduction of oil. But recovering economy can change this in a few years.

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.[111]

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.[112] 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.[113]

Geopolitical importance[edit]

The Athabasca oil sands are often a topic in international trade talks, with energy rivals China and the United States negotiating with Canada for a bigger share of the rapidly increasing output. Production is expected to quadruple between 2005 and 2015, reaching 4 million barrels (640,000 m3) a day, with increasing 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. If it is built, the pipeline will help export synthetic crude oil from the oil sands to China and elsewhere in the Pacific.[114] However, in 2011, First Nations and environmental groups protested the proposed pipeline, stating that its construction and operation would be destructive to the environment. First Nations groups also claim that the development of the proposed pipeline is in violation of commitments that the Government of Canada has made through various Treaties and the UN Declaration of the Rights of Indigenous Peoples.[115] A smaller pipeline will also be built alongside to import condensate to dilute the bitumen. Sinopec, the largest refining and chemical company in China, 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 (72,000 m3) of crude oil a day to refineries in the U.S.[116][117]

Indigenous peoples of the area[edit]

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, which states:

It does not appear likely that the conditions of the country on either side of the Athabasca and Slave Rivers or about Athabasca Lake will be so changed as to affect hunting or trapping, and it is safe to say that so long as the fur-bearing animals remain, the great bulk of the Indians will continue to hunt and to trap.

—Treaty 8

We had to solemnly assure them that only such laws as to hunting and fishing as were in the interest of the Indians and were found necessary in order to protect the fish and fur-bearing animals would be made, and that they would be as free to hunt and fish after the treaty as they would be if they never entered into it. (…) It does not appear likely that the conditions of the country on either side of the Athabasca and Slave Rivers or about Athabasca Lake will be so changed as to affect hunting or trapping, and it is safe to say that so long as the fur-bearing animals remain, the great bulk of the Indians will continue to hunt and to trap.

—The Honourable Clifford Sifton, Superintendent General of Indian Affairs, Report of Commissioners for Treaty No. 8, Winnipeg, Manitoba, September 22, 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.[118] Opposition remaining within the First Nation focuses on environmental stewardship, land rights, and health issues, like elevated cancer rates in Fort Chipewyan and deformed fish being found by commercial fishermen in Lake Athabasca.

The Alberta Cancer Board published research of the cancer rates of those living in Fort Chipewyan, Alberta in 2009. While many companies argue that there is not enough chemicals and toxic material in the water due to the development of the oil sands, this report indicates that there is coincidentally a significantly higher rate of cancer within this community. There have been many speculations as to why there is a higher rate of cancer in this community; some of those speculations are contamination with the river and the oil sands as well as uranium mining that is currently in progress. The world’s largest production of uranium is produced in this area as well as along the Athabasca River allowing for easy contamination of the river.[119]

Oil sand companies[edit]

Planned mining operation oil production by various companies. Data from table below.

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 Marathon Oil Corp.

Major producing or planned developments in the Athabasca Oil Sands include the following projects:[120]

Mining Projects
OperatorProjectPhaseCapacityStart-upRegulatory Status
Royal Dutch ShellJackpine1A100,000 bbl/d (16,000 m3/d)2010Under construction
 1B100,000 bbl/d (16,000 m3/d)2012Approved
 2100,000 bbl/d (16,000 m3/d)2014Applied for
Muskeg RiverExisting155,000 bbl/d (24,600 m3/d)2002Operating
 Expansion115,000 bbl/d (18,300 m3/d)2010Approved
Pierre River1100,000 bbl/d (16,000 m3/d)2018Applied for
 2100,000 bbl/d (16,000 m3/d)2021Applied for
Canadian Natural ResourcesHorizon1135,000 bbl/d (21,500 m3/d)2009Operating
 2 and 3135,000 bbl/d (21,500 m3/d)2011Approved
 4145,000 bbl/d (23,100 m3/d)2015Announced
 5162,000 bbl/d (25,800 m3/d)2017Announced
Imperial OilKearl1110,000 bbl/d (17,000 m3/d)2012Operating
 2220,000 bbl/d (35,000 m3/d)20??Approved
 3275,000 bbl/d (43,700 m3/d)20??Approved
 4345,000 bbl/d (54,900 m3/d)20??Approved
Petro CanadaFort Hills1165,000 bbl/d (26,200 m3/d)2011Approved
 debottleneck25,000 bbl/d (4,000 m3/d)TBDApproved
Suncor EnergyMillenium 294,000 bbl/d (46,700 m3/d)1967Operating
 debottleneck23,000 bbl/d (3,700 m3/d)2008Under construction
Steepbankdebottleneck4,000 bbl/d (640 m3/d)2007Under construction
 extension 2010Approved
Voyageur South1120,000 bbl/d (19,000 m3/d)2012Applied for
SyncrudeMildred Lake & Aurora1 and 2290,700 bbl/d (46,220 m3/d)1978Operating
 3 Expansion116,300 bbl/d (18,490 m3/d)2006Operating
 3 Debottleneck46,500 bbl/d (7,390 m3/d)2011Announced
 4 Expansion139,500 bbl/d (22,180 m3/d)2015Announced
Synenco EnergyNorthern Lights157,250 bbl/d (9,102 m3/d)2010Applied for
Total S.A.Joslyn150,000 bbl/d (7,900 m3/d)2013Applied for
 250,000 bbl/d (7,900 m3/d)2016Applied for
 350,000 bbl/d (7,900 m3/d)2019Announced
 450,000 bbl/d (7,900 m3/d)2022Announced
UTS/Teck ComincoEquinoxLease 1450,000 bbl/d (7,900 m3/d)2014Public disclosure
Frontier1100,000 bbl/d (16,000 m3/d)2014Public disclosure

Court ordered sanctions[edit]

For improper diversion of water in 2008/2009, Statoil Canada Ltd. was ordered in 2011 to pay a fine of $5000 and to allocate $185,000 for a training project (The verdict was handed down by the Provincial Court of Alberta, Criminal Division).[123][124]

See also[edit]

Notes[edit]

References[edit]

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