Athabasca oil sands

Athabasca oil sands on the banks of the river, around 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.[8]

In 1788, fur trader Alexander Mackenzie, after whom the Mackenzie River was later named, traveled along routes to both the Arctic and Pacific Ocean 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 mapmaker David Thompson and in 1819 by British Naval officer John Franklin.[9]

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."[8]

Athabasca oil sand of the McMurray Formation as seen in drill cores.

Count Alfred von Hammerstein (1870–1941), who arrived in the region in 1897, promoted the Athabasca 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 entitled The New North: Being Some Account of a Woman's Journey through Canada to the Arctic which recounted her 10,000 mi (16,000 km) roundtrip to the Arctic Ocean.[10] 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.[11] Her photographs were reproduced in 2011–2012 in an exhibit at the Canadian Museum of Civilization in Ottawa, Ontario, Canada.[12] 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."[12] "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.[13]

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.

A pioneer in the discovery and use of natural gas was Georg Naumann. He used natural gas as early as about 1940.

Project Oilsand, also known as Project Oilsands, was a 1958 proposal to exploit the Athabasca oil sands using the underground detonation of nuclear explosives;[14] hypothetically, the heat and pressure created by an underground detonation would boil the bitumen deposits, reducing their viscosity to the point that standard oilfield techniques could be used. The general means by which the plan was to work was discussed in the October 1976 Bulletin of the Atomic Scientists issue.[15] A patent was granted for the process that was intended: The Process for Stimulating Petroliferous Subterranean Formations with Contained Nuclear Explosions by Bray, Knutson, and Coffer, which was first submitted in 1964.[16][17] With the nuclear heating option considered a forerunner to some of the nascent conventional heating ideas that are presently suggested and in use extracting oil from the Alberta regions Athabasca oil sands.[18]

The proposal, originally known as "Project Cauldron", was devised by geologist Manley L. Natland at Los Angeles-based Richfield Oil Corporation. Natland believed that an underground blast was the most efficient way to generate the heat needed to liquefy the viscous bitumen so that it could be pumped to the surface by conventional wells. The project was conceived of as part of Operation Plowshare, a United States project to harness the nuclear explosions for peaceful applications. However, some experts had doubts. In 1959, oil sands pioneer Robert Fitzsimmons of the International Bitumen Company wrote a letter to the Edmonton Journal, saying "While the writer does not know anything about nuclear energy and is therefore not qualified to make any definite statement as to it's [sic] results he does know something about the effect dry heat has on those sands and ventures a guess that if it does not turn the whole deposit into a burning inferno it is almost sure to fuse it into a solid mass of semi glass or coke."[19]

In April 1959, the Federal Mines Department approved Project Oilsand.[20] However, before the project could continue beyond preliminary steps, the Canadian government's stance on the use of nuclear devices changed. In April 1962, the Canadian Secretary of State for External Affairs, Howard Charles Green, said "Canada is opposed to nuclear tests, period".[21] These 1962 changes in Canadian public opinion is regarded by historian Michael Payne to be due to the shift in public perception of nuclear explosives following the 1962 Cuban Missile Crisis,[22] Project Oilsand was subsequently cancelled. Prime Minister John Diefenbaker told Parliament that the decision to detonate an atomic bomb on or under Canadian soil would be made by Canada, not the United States, and ordered Project Cauldron/Oilsand placed on permanent hold, citing the risk of upsetting the Soviet Union during nuclear disarmament negotiations being conducted in Geneva.[23]

The United States government continued with exploring the peaceful uses of nuclear detonations with Operation Plowshare, but was likewise eventually terminated in 1977.

Social scientist Benjamin Sovacool contends that the main problem was that the produced oil and gas was radioactive, which caused consumers to reject it.[24] In contrast, oil and gas are sometimes considerably naturally radioactive to begin with and the industry is set up to deal with this, moreover in contrast to earlier stimulation efforts,[25] contamination from many later tests was not a showstopping issue, it was primarily changing public opinion due to the societal fears caused by events such as the Cuban Missile Crisis, that resulted in protests,[22] court cases and general hostility that ended the US exploration. Furthermore, as the years went by without further development and the closing/curtailment in US nuclear weapons factories, this began to evaporate the economies of scale advantage that had earlier existed, with this, it was increasingly found that most US fields could instead be stimulated by non-nuclear techniques which were found to be likely cheaper.[26][27] The most successful and profitable nuclear stimulation effort that did not result in customer product contamination issues was the 1976 Project Neva on the Sredne-Botuobinsk gas field in the Soviet Union, made possible by multiple cleaner stimulation explosives, favourable rock strata and the possible creation of an underground contaminant storage cavity.[28][29]

The oil sands, which are typically 40 to 60 metres (130 to 200 ft) thick and sit on top of relatively flat limestone, are relatively easy to access. They lie under 1 to 3 m (3 ft 3 in to 9 ft 10 in) of waterlogged muskeg, 0 to 75 metres (0 to 246 ft) of clay and barren sand. As a result of the easy accessibility, the world's first oil-sands mine was in the Athabasca oil sands.

Commercial production of oil from the Athabasca oil sands began in 1967, with the opening of the Great Canadian Oil Sands (GCOS) plant in Fort McMurray. It was the first operational oil sands project in the world, owned and operated by the American parent company, Sun Oil Company. When the US$240 million plant officially opened with a capacity of 45,000 barrels per day (7,200 m³/d), it marked the beginning of commercial development of the Athabasca oil sands. In 2013 McKenzie-Brown listed industrialist J. Howard Pew as one of the six visionaries who built the Athabasca oil sands.[30] By the time of his death in 1971, the Pew family were ranked by Forbes magazine as one of the half-dozen wealthiest families in America.[31] The Great Canadian Oil Sands Limited (then a subsidiary of Sun Oil Company but now incorporated into an independent company known as Suncor Energy Inc.) produced 30,000 barrels per day (4,800 m³/d) of synthetic crude oil.[32]

The true size of the Canadian oil sands deposits became known in the 1970s. The Syncrude mine is now the largest mine (by area) in the world, with mines potentially covering 140,000 km² (54,000 sq mi). (Although there is oil underlying 142,200 km² (54,900 sq mi), which may be disturbed by drilling and in situ extraction, only 4,800 km² (1,900 sq mi) may potentially be surface mined, and 904 km² (349 sq mi) has to date been mined.)

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.

In 1979, Sun formed Suncor by merging its Canadian refining and retailing interests with Great Canadian Oil Sands and its conventional oil and gas interests. In 1981, the Government of Ontario purchased a 25% stake in the company but divested it in 1993. In 1995, Sun Oil also divested its interest in the company, although Suncor maintained the Sunoco retail brand in Canada. Suncor took advantage of these two divestitures to become an independent, widely held public company.

Suncor continued to grow and continued to produce more and more oil from its oil sands operations regardless of fluctuating market prices, and eventually became bigger than its former parent company. In 2009, Suncor acquired the formerly Canadian government owned oil company, Petro-Canada,[33][34] which turned Suncor into the largest petroleum company in Canada and one of the biggest Canadian companies. Suncor Energy is now a Canadian company completely unaffiliated with its former American parent company. Sun Oil Company became known as Sunoco, but later left the oil production and refining business, and has since become a retail gasoline distributor owned by Energy Transfer Partners of Dallas, Texas. In Canada, Suncor Energy converted all of its Sunoco stations (which were all in Ontario) to Petro-Canada sites in order to unify all of its downstream retail operations under the Petro-Canada banner and discontinue paying licensing fees for the Sunoco brand. Nationwide, Petro-Canada's upstream product supplier and parent company is Suncor Energy. Suncor Energy continues to operate just one Sunoco retail site in Ontario.[35]

The massive development of tight oil extraction in the Bakken and Permian Basin in the United States transformed the oil industry rapidly, reducing importation of foreign oil dramatically. As with the oil sands, production costs of shale oil are higher than those of conventional oil. A combination of factors, among them oversupply and geopolitical rivalries, drove the price of oil down from more than 100 dollars a barrel in 2013 to less than 40 dollars three years later. Lingering low oil prices prompted companies to cancel new investments in the oil sands.

Satellite image of the fire at night (May 5, 2016).

From May to July 2016, a wildfire spread from Fort McMurray across northern Alberta, burning approximately 590,000 hectares (1,500,000 acres) of forested areas and destroying approximately 2,400 homes and buildings. 88,000 people were forced from their homes in what became the largest wildfire evacuation in Alberta's history and the costliest disaster in Canadian history.

The wildfire halted oil sands production at facilities north of Fort McMurray. Shell Canada shut down output at its Albian Sands mining operation. Suncor Energy and Syncrude Canada also scaled back operations and evacuated employees and their families. Approximately one million barrels of oil a day, equal to a quarter of Canada's oil production, was halted as a result of the fire in May. This continued into June at a rate of 700,000 barrels per day. The lost output was a contributing factor to rises in global oil prices. The scaled back operations, along with a refinery outage in Edmonton, caused many gas stations to run out of gas throughout Western Canada.

2015 production of crude bitumen[39]

Mine	(m3/day)	Barrels per day
Suncor mine	80,000	501,000
Syncrude mine	65,000	407,000
Shell Canada mines	40,000	255,000
Imperial Oil mine	35,000	220,000
CNRL mine	24,000	152,000
In situ projects	138,000	865,000
Total	382,000	2,400,000

In 2018, oil sands production reached 3.1 million barrels per day (490,000 m³/d).

Until 2014, industry groups believed oil sands production levels could reach 5 Mbbl/d (790,000 m³/d) by 2030. As of 2021, after a slowdown in investment, analyst are predicting it could reach 3.8 Mbbl/d (600,000 m³/d) by that time.[40][41]

Citizen demonstrating against the Keystone Pipeline and tar sands.

Canada is the largest source of oil imported by the United States, supplying 3 million barrels per day (480,000 m³/d) chiefly from oil sands sources as of 2019.[42]

Industry observers went from believing there might be excess pipeline capacity to warning that it was insufficient to accommodate oil sands production growth, after several pipeline projects were abandoned or cancelled.[43]

The North Gateway project to Kitimat, British Columbia, which would have been built by Enbridge, operator of the Enbridge Pipeline System which also serves the area, was cancelled in 2016. Similarly, after lengthy environmentalist and First Nation group opposition, Keystone XL, a pipeline project from Alberta to Gulf coast refineries, was cancelled in 2021.[44] Other projects, using existing rights of way, are being built, like Kinder Morgan's Trans Mountain Expansion, nationalized in 2018, or Enbridge's Line 9, reversed to feed refineries in Quebec.[45][46] Between January 2019 and December 2020, the Alberta government imposed a quota to adjust production to pipeline export capacity.[47]

To compensate for pipeline capacity limitations, shipment of oil by rail increased from less than 50 thousand to 400 thousand barrels per day (64,000 m³/d) between 2012 and 2020.[48]

Since Great Canadian Oil Sands (now Suncor) started operation of its mine in 1967, bitumen has been extracted on a commercial scale from the Athabasca Oil Sands by surface mining. In the Athabasca sands there are very large amounts of bitumen covered by little overburden, making surface mining the most efficient method of extracting it. The overburden consists of water-laden muskeg (peat bog) over top of clay and barren sand. The oil sands themselves are typically 40 to 60 metres (130 to 200 ft) deep, sitting on top of flat limestone rock. Originally, the sands were mined with draglines and bucket-wheel excavators and moved to the processing plants by conveyor belts.

These early mines had a steep learning curve to deal with before their bitumen mining techniques became efficient. In the intervening years, more effective in-situ production techniques were developed, particularly steam-assisted gravity drainage (SAGD). In-situ methods became increasingly important because only about 20% of the Athabasca oil sands were shallow enough to recover by surface mining, and the SAGD method in particular was very efficient at recovering large amounts of bitumen at a reasonable cost.

In recent years, companies such as Syncrude and Suncor have switched to much cheaper shovel-and-truck operations using the biggest power shovels (at least 100 short tons, 91 t) and dump trucks (400 short tons, 360 t) in the world.[86] This has held production costs to around US$27 per barrel of synthetic crude oil despite rising energy and labour costs.[87]

After excavation, hot water and caustic soda (sodium hydroxide) is added to the sand, and the resulting slurry is piped to the extraction plant where it is agitated and the oil skimmed from the top.[88] Provided that the water chemistry is appropriate to allow bitumen to separate from sand and clay, the combination of hot water and agitation releases bitumen from the oil sand, and allows small air bubbles to attach to the bitumen droplets. The bitumen froth floats to the top of separation vessels, and is further treated to remove residual water and fine solids.

About two short tons (1.8 t) of oil sands are required to produce one barrel (1⁄8 short ton, 110 kg) of oil. Originally, roughly 75% of the bitumen was recovered from the sand. However, recent enhancements to this method include Tailings Oil Recovery (TOR) units which recover oil from the tailings, Diluent Recovery Units to recover naphtha from the froth, inclined plate settlers (IPS) and disc centrifuges. These allow the extraction plants to recover well over 90% of the bitumen in the sand. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.

Alberta Taciuk Process technology extracts bitumen from oil sands through a dry retorting. During this process, oil sand is moved through a rotating drum, cracking the bitumen with heat and producing lighter hydrocarbons. Although tested, this technology is not in commercial use yet.[89]

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.[90] 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 (122–176 °F) 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.[91]

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

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."[93][94]

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.[95]

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 two-and-a-half-fold.[96]

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.[97] 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.

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. Approximately 0.19% of the Alberta boreal forest has been disturbed by open pit mining.[98] 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.[99]

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,[100] a figure disputed by other sources, who assess Syncrude more accurately reclaimed only 0.2% of its disturbed land.[101]

A Pembina Institute report stated "To produce one cubic metre (m³) [35 cu ft] of synthetic crude oil (SCO) (upgraded bitumen) in a mining operation requires about 2–4.5 m³ [71–159 cu ft] 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."[102] It 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 [7.1 cu ft], depending on how much is recycled".

The Athabasca River runs 1,231 kilometres (765 mi) from the Athabasca Glacier in west-central Alberta to Lake Athabasca in northeastern Alberta.[103] The average annual flow just downstream of Fort McMurray is 633 cubic metres per second (22,400 cu ft/s)[104] with its highest daily average measuring 1,200 cubic metres per second.[105]

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%.[106] 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.[107] The province of Alberta is also looking into cooperative withdrawal agreements between oil sands operators.[108]

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 likelihood of contamination due to ground water leakages. In 1997, Suncor admitted that their tailing ponds had been leaking 1,600 cubic metres (57,000 cu ft) 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.[109]

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 and other metal elements toxic at low concentrations to the tributaries and rivers of the Athabasca.[110]

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.[111]

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."[112] 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.[113] 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,[114] however only a 29% reduction between 1990 and 2009.[115]

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.

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.[116]

Two separate fraud lawsuits were filed against "ExxonMobil involving Alberta's oilsands" in October. One was in New York and the second was filed in Massachusetts on October 24. The Massachusetts lawsuit says that ExxonMobil misled investors by "falsely" justifying to them "its riskiest long-term investments, including Canadian bitumen oilsands projects." The company did not warn investors "about what climate change measures could cost its operations — especially those in the oilsands."[117]

In Northern Alberta, oil development activities bring an enormous number of people into a fragile ecosystem. Historically, population figures have been very low for this region. Water is easily polluted because the water table reaches the surface in most areas of muskeg. With the ever-increasing development and extraction of resources, wildlife are recipient to both direct and indirect effects of pollution. Woodland Caribou are particularly sensitive to human activities, and as such are pushed away from their preferred habitat during the time of year when their caloric needs are greatest and food is the most scarce. Humans' effect on the Caribou is compounded by road construction and habitat fragmentation that open the area up to deer and wolves.[118]

Wildlife living near the Athabasca River have been greatly impacted due to pollutants entering the water system. An unknown number of birds die each year. Particularly visible and hard hit are migrating birds that stop to rest at tailing ponds. There have been numerous reports of large flocks of ducks landing in tailing ponds and perishing soon after.[119] Data has been recorded since the 1970s on the number of birds found on tailing ponds.[120]

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, tumors, and deformed fish species have begun to appear. A study commissioned by the region's health authority found that several known toxins and carcinogens were elevated.[121] Aboriginal communities that live around the river are becoming increasingly worried about how the animals they eat and their drinking water are being affected.[122]

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.[123]

Large volumes of tailings are a byproduct of bitumen extraction from the oil sands and managing these tailings is one of the most difficult environmental challenges facing the oil sands industry.[124] Tailings ponds are engineered dam and dyke systems that contain solvents used in the separation process as well as residual bitumen, salts and soluble organic compounds, fine silts and water.[124] The concentrations of chemicals may be harmful to fish and oil on the surface harmful to birds.[125] These settling basins were meant to be temporary. A major hindrance to the monitoring of oil sands produced waters has been the lack of identification of individual compounds present. By better understanding the nature of the highly complex mixture of compounds, including naphthenic acids, it may be possible to monitor rivers for leachate and also to remove toxic components. Such identification of individual acids has for many years proved to be impossible but a breakthrough in 2011 in analysis began to reveal what is in the oil sands tailings ponds.[126] Ninety percent of the tailings water can be reused for oil extraction.[124] By 2009 as tailing ponds continued to proliferate and volumes of fluid tailings increased, the Alberta Energy Resources Conservation Board issued Directive 074 to force oil companies to manage tailings based on new aggressive criteria.[127] The Government of Alberta reported in 2013 that tailings ponds in the Alberta oil sands covered an area of about 77 square kilometres (30 sq mi).[124] The Tailings Management Framework for Mineable Oil Sands is part of Alberta's Progressive Reclamation Strategy for the oil sands to ensure that tailings are reclaimed as quickly as possible.[127]

Suncor invested $1.2 billion in their Tailings Reduction Operations (TROTM) method [128] that treats mature fine tails (MFT) from tailings ponds with chemical flocculant, an anionic Polyacrylamide, commonly used in water treatment plants to improve removal of total organic content (TOC), to speed their drying into more easily reclaimable matter. Mature tailings dredged from a pond bottom in suspension were mixed with a polymer flocculant and spread over a "beach" with a shallow grade where the tailings would dewater and dry under ambient conditions. The dried MFT can then be reclaimed in place or moved to another location for final reclamation. Suncor hoped this would reduce the time for water reclamation from tailings to weeks rather than years, with the recovered water being recycled into the oil sands plant. Suncor claimed the mature fines tailings process would reduce the number of tailing ponds and shorten the time to reclaim a tailing pond from 40 years at present to 7–10 years, with land rehabilitation continuously following 7 to 10 years behind the mining operations.[129] For the reporting periods from 2010 to 2012, Suncor had a lower-than-expected fines capture performance from this technology.[127] Syncrude used the older composite tailings (CT) technology to capture fines at its Mildred Lake project. Syncrude had a lower-than-expected fines capture performance in 2011–2012 but exceeded expectations in 2010–2011.[127] Shell used atmospheric fines drying (AFD) technology combined "fluid tailings and flocculants and deposits the mixture in a sloped area to allow the water to drain and the deposit to dry" and had a lower-than-expected fines capture performance.[127]

By 2010 Suncor had transformed their first tailings pond, Pond One, into Wapisiw Lookout, the first reclaimed settling basin in the oil sands. In 2007 the area was a 220-hectare pond of toxic effluent but several years later there was firm land planted with black spruce and trembling aspen. Wapisiw Lookout represents only one percent of tailings ponds in 2011 but Pond One was the first effluent pond in the oil sands industry in 1967 and was used until 1997. By 2011 only 65 square kilometres were cleaned up and about one square kilometre was certified by Alberta as a self-sustaining natural environment. Wapisiw Lookout has not yet been certified. Closure operations of Pond One began in 2007. The jello-like mature fine tails (MFT) were pumped and dredged out of the pond and relocated to another tailings pond for long-term storage and treatment. The MFT was then replaced with 30 million tonnes clean sand and then topsoil that had been removed from the site in the 1960s. The 1.2 million cubic meters (42×10^⁶ cu ft) of topsoil over the surface, to a depth of 50 cm (1 ft 8 in), was placed on top of the sand in the form of hummocks and swales. It was then planted with reclamation plants.[130][131][132]

In March 2012 an alliance of oil companies called Canada's Oil Sands Innovation Alliance (COSIA) was launched with a mandate to share research and technology to decrease the negative environmental impact of oil sands production focusing on tailings ponds, greenhouse gases, water and land. Almost all the water used to produce crude oil using steam methods of production ends up in tailings ponds. Recent enhancements to this method include Tailings Oil Recovery (TOR) units which recover oil from the tailings, Diluent Recovery Units to recover naphtha from the froth, Inclined Plate Settlers (IPS) and disc centrifuges. These allow the extraction plants to recover well over 90% of the bitumen in the sand.

In January 2013, scientists from Queen's University published a report analyzing lake sediments in the Athabasca region over the past fifty years.[133] They found that levels of polycyclic aromatic hydrocarbons (PAHs) had increased as much as 23-fold since bitumen extraction began in the 1960s. Levels of carcinogenic, mutagenic, and teratogenic PAHs were substantially higher than guidelines for lake sedimentation set by the Canadian Council of Ministers of the Environment in 1999. The team discovered that the contamination spread farther than previously thought.[134]

The Pembina Institute suggested that the huge investments by many companies in Canadian oil sands leading to increased production results in excess bitumen with no place to store it. It added that by 2022 a month's output of waste-water could result in a 11-foot-deep (3 m) toxic reservoir the size of New York City's Central Park [840.01 acres (339.94 ha) (3.399 km²)].[135]

The oil sands industry may build a series of up to thirty lakes by pumping water into old mine pits when they have finished excavation leaving toxic effluent at their bottoms and letting biological processes restore it to health. It is less expensive to fill abandoned open pit mines with water instead of dirt.[136] In 2012 the Cumulative Environmental Management Association (CEMA) described End Pit Lakes (EPL)[137] as

An engineered water body, located below grade in an oil sands post-mining pit. It may contain oil sands by-product material and will receive surface and groundwater from surrounding reclaimed and undisturbed landscapes. EPLs will be permanent features in the final reclaimed landscape, discharging water to the downstream environment.

— CEMA 2012

CEMA acknowledged that the "main concern is the potential for EPLs to develop a legacy of toxicity and thus reduce the land use value of the oil sands region in the future." Syncrude Canada was planning the first end pit lake in 2013 with the intention of "pumping fresh water over 40 vertical metres of mine effluent that it has deposited in what it calls 'base mine lake.'" David Schindler argued that no further end pit lakes should be approved until we "have some assurance that they will eventually support a healthy ecosystem." There is to date no "evidence to support their viability, or the 'modelled' results suggesting that outflow from the lakes will be non-toxic."[136]

Oil sands and especially the related projects, like the construction of a new pipeline, also have a social impact. Most of all, the local population groups would suffer from the effects of a new oil pipeline. In addition to the risk of general oil spills, there is now also the danger of gathering food due to the pollution of the fields and waters. Despite the fact that most people in those areas are not well off, the money is still used to build new projects instead of spending it on improving the quality of life there. Furthermore, adding a new pipeline to the already existing oil pipelines would increase our dependence on fossil fuels.[138]

In July 2015, one of the largest leaks in Canada's history spilled 5,000 cubic metres of emulsion — about 5 million litres of bitumen, sand and wastewater — from a Nexen Energy pipeline at a Long Lake oil sands facility, south of Fort McMurray. The subsidiary of China's CNOOC Ltd. automated safety systems had not detected the pipeline fault that caused the spill to cover an area of about 16,000 square metres prior to manual inspection.[139] Alberta Energy Regulator (AER) revealed the number of pipeline "incidents" in Alberta increased 15% last year, despite the regulator's well-publicized efforts to reduce ruptures and spills.

An explosion left one worker dead and another seriously injured at the Chinese-owned Nexen Energy facility in the Long Lake oil sands near Anzac, south of Fort McMurray[140] The two maintenance workers involved were found near natural gas compression equipment used for a hydrocracker, which turns heavy oil into lighter crude, at the plant's main processing facility, known as an upgrader.[141]

• Cameron, Agnes Deans (1909). The New North: Being Some Account of a Woman's Journey through Canada to the Arctic. New York: Appleton.
• Gismondi, Mike; Davidson, Debra J. (September 2012). "Imagining the Tar Sands: 1880 -1967 and Beyond" (PDF). Imaginations. Edmonton, Alberta: Campus Saint-Jean, University of Alberta. pp. 68–102. Archived from the original (PDF) on 2013-10-02.