The world's largest deposits of bitumen are in Canada, although Venezuela's deposits of extra- heavy crude oil are even bigger. Western Canadian Select , launched in as a new heavy oil stream, blended at the Husky Energy terminal in Hardisty , Alberta ,  is the largest crude oil stream coming from the Canadian oil sands and the benchmark for emerging heavy, high TAN acidic crudes.
Since Venezuela also has financial problems — as a result of the country's economic crisis -, and political disagreements with the US government and oil companies, the situation remains unresolved. A network of gathering and feeder pipelines collects crude bitumen and SCO from Alberta's northern oil sands deposits primarily Athabasca, Cold Lake, and Peace River , and feeds them into two main collection points for southbound deliveries: Edmonton, Alberta and Hardisty, Alberta.
Most of the feeder pipelines move blended bitumen or SCO southbound and diluent northbound, but a few move product laterally within the oil sands region. The building of new oil sands feeder pipelines requires only the approval of the Alberta Energy Regulator, an agency that deals with matters entirely within Alberta and is likely to give little consideration to interference from political and environmental interest from outside Alberta. From Edmonton and Hardisty, main transmission pipelines move blended bitumen and SCO, as well as conventional crude oil and various oil and natural productions to market destinations across North America.
The main transmission systems include: Overall, the total pipeline capacity for the movement of crude oil from Edmonton and Hardisty to the rest of North America is about 3. However, other substances such as conventional crude oil and refined petroleum products also share this pipeline network.
The rapidly increasing tight oil production from the Bakken formation of North Dakota also competes for space on the Canadian export pipeline system. North Dakota oil producers are using the Canadian pipelines to deliver their oil to US refineries. In , the Canadian export pipeline system began to become overloaded with new oil production. As a result, Enbridge implemented pipeline apportionment on its southbound lines, and Kinder Morgan on its westbound line.
This rationed pipeline space by reducing the monthly allocation of each shipper to a certain percentage of its requirements. The Chevron Corporation Burnaby Refinery , the last remaining oil refinery on Canada's west coast, applied to the NEB for preferential access to Canadian oil since American refineries in Washington and California were outbidding it for pipeline space, but was denied because it would violate NAFTA equal access to energy rules.
Similarly, new North Dakota tight oil production began to block new Canadian production from using the Enbridge, Kinder Morgan, and TransCanada southbound systems. In addition, the US oil marketing hub at Cushing was flooded with new oil because most new North American production from Canada, North Dakota, and Texas converged at that point, and there was insufficient capacity to take it from there to refineries on the Gulf Coast, where half of US oil refinery capacity is located.
The American pipeline system is designed to take imported oil from the Gulf Coast and Texas to the refineries in the northern US, and the new oil was flowing in the opposite direction, toward the Gulf Coast. The price of West Texas Intermediate delivered at Cushing, which is the main benchmark for US oil prices, fell to unprecedented low levels below other international benchmark oils such as Brent Crude and Dubai Crude.
Since the price of WTI at Cushing is usually quoted by US media as the price of oil , this gave many Americans a distorted view of world oil prices as being lower than they were, and the supply being better than it was internationally. Canada used to be in a similar position to the US in that offshore oil was cheaper than domestic oil, so the oil pipelines used to run westward from the east coast to Central Canada, now they are being reversed to carry cheaper domestic oil sands production from Alberta to the east coast.
Lack of access to markets, limited export capacity, and oversupply in the US market have been a problem for oil sands producers in recent years. They have caused lower prices to Canadian oil sands producers and reduced royalty and tax revenues to Canadian governments.
The pipeline companies have moved forward with a number of solutions to the transportation problems: With the main constraint on Canadian oil sands development becoming the availability of export pipeline capacity, pipeline companies have proposed a number of major new transmission pipelines. Many of these became stalled in government regulatory processes, both by the Canadian and American governments.
Another factor is competition for pipeline space from rapidly increasing tight oil production from North Dakota, which under NAFTA trade rules has equal access to Canadian pipelines. In addition, there are a large number of new pipelines proposed for Alberta. These will likely be approved rapidly by the Alberta Energy Regulator, so there are likely to be few capacity problems within Alberta. The movement of crude oil by rail is far from new, but it is now a rapidly growing market for North American railroads.
The growth is driven by several factors. One is that the transmission pipelines from Alberta are operating at or near capacity and companies who cannot get pipeline space have to move oil by rail instead. Another is that many refineries on the east, west, and Gulf coasts of North America are under-served by pipelines since they assumed that they would obtain their oil by ocean tanker.
Producers of new oil in Alberta, North Dakota, and West Texas are now shipping oil by rail to coastal refiners who are having difficulty obtaining international oil at prices competitive with those in the interior of North America.
In addition, crude bitumen can be loaded directly into tank cars equipped with steam heating coils, avoiding the need for blending it with expensive condensate in order to ship it to market. Tank cars can also be built to transport condensate on the back-haul from refineries to the oil sands to make additional revenue rather than returning empty.
This would require locomotives and 18, tank cars, which is a small part of the fleet of a Class 1 railroad. With many of their lines being underused, railroads find transporting crude oil an attractive source of revenue. With enough new tank cars they could carry all the new oil being produced in North America, albeit at higher prices than pipelines. In the short term, the use of rail will probably continue to grow as producers try to bypass short-term pipeline bottlenecks to take advantage of higher prices in areas with refineries capable of handling heavier crudes.
In the long term the growth in rail transport will largely depend on the continued pipeline bottlenecks due to increased production in North America and regulatory delays for new pipelines. As a result, Canadian farmers suffered an acute shortage of rail capacity to export their grains because so much of Canada's rail capacity was tied up by oil products. The safety of rail transport of oil was being called into question after several derailments, especially after a train with 74 tank cars of oil derailed and caught fire in Lac Megantic, Quebec.
The ensuing explosion and firestorm burned down 40 buildings in the town center and killed 47 people. The cleanup of the derailment area could take 5 years, and another buildings may need to be demolished. Although near a huge oil import port on the Atlantic Ocean, the Irving refinery is importing US Bakken oil by rail because oil from outside North America is too expensive to be economic, and there are no pipelines to deliver heavier but cheaper Western Canadian oil to New Brunswick.
It was subsequently pointed out that the Bakken light oil was much more flammable than Alberta bitumen, and the rail cars were mislabeled by the North Dakota producers as to their flammability. By , the movement of crude by rail had become very profitable to oil companies. Suncor Energy , Canada's largest oil company declared record profits and attributed much of it to transporting oil to market by rail.
Suncor has been considering adding a coker to its Montreal refinery to upgrade heavy oil sands bitumen, which would be cheaper than adding another upgrader to its oil sands operation. It was also shipping marine cargoes on an "opportunistic basis" from Texas and Louisiana "at significant discounts to the international crudes we would typically run in Montreal", thereby taking advantage of the recent US tight oil glut in addition to increased supplies of cheap Canadian oil sands bitumen.
Heavy crude oil feedstock crude feedstock needs pre-processing before it is fit for conventional refineries, although heavy oil and bitumen refineries can do the pre-processing themselves. This pre-processing is called 'upgrading', the key components of which are as follows:. As carbon rejection is very inefficient and wasteful in most cases, catalytic hydrocracking is preferred in most cases. All these processes take large amounts of energy and water, while emitting more carbon dioxide than conventional oil.
Catalytic purification and hydrocracking are together known as hydroprocessing. The big challenge in hydroprocessing is to deal with the impurities found in heavy crude, as they poison the catalysts over time. Many efforts have been made to deal with this to ensure high activity and long life of a catalyst. Catalyst materials and pore size distributions are key parameters that need to be optimized to deal with this challenge and varies from place to place, depending on the kind of feedstock present.
Some of the large oil sands upgraders also produced diesel fuel as part of their operations. Some of the oil sands bitumen and SCO went to refineries other provinces, but most of it was exported to the United States. The four major Alberta refineries are: NWU, which was founded in , is a private, Alberta-based company with headquarters in Calgary.
A petroleum coker is required to upgrade the raw product before it can be made into diesel. The Alberta government has guaranteed NWU's loans and signed a firm contract for feedstock deliveries because of some economic issues. Since Alberta has a chronic shortage of diesel fuel, the government would prefer to sell diesel fuel rather than bitumen to Alberta and international oil companies.
The Pacific Future Energy project proposes a new refinery in British Columbia that would bring in Western Canadian bitumen and process it into fuels for Asian and Canadian markets. Pacific Future Energy proposes to transport near-solid bitumen to the refinery using railway tank cars.
Canadian oil exports have increased tenfold since , mostly as the result of new oil sands bitumen and heavy oil output, but at the same time Canadian oil consumption and refining capacity has hardly grown at all. Since the s, the number of oil refineries in Canada has declined from 40 to There hasn't been a new oil refinery other than oil sands upgraders built in Canada since Most of the Canadian oil refining industry is foreign-owned, and except for Alberta, international companies preferred to build refining capacity elsewhere than in Canada.
The result is a serious imbalance between Canadian oil production versus Canadian oil refining. Although Canada produces much more oil than it refines, and exports more oil and refined products than it consumes, most of the new production is heavier than traditional oil and concentrated in the landlocked provinces of Alberta and Saskatchewan. The remainder of Canadian oil production is exported, almost all of it to the US. Canadian refineries, outside of the major oil producing provinces of Alberta and Saskatchewan, were originally built on the assumption that light and medium crude oil would continue to be cheap in the long term, and that imported oil would be cheaper than oil sands production.
With new oil sands production coming on production at lower prices than international oil, market price imbalances have ruined the economics of refineries which could not process it. Most of the Canadian oil refineries which closed were in the oil deficient regions of Quebec , the Atlantic Provinces , and British Columbia where they had no access to cheaper domestic Canadian production. They also were not designed to refine the heavier grades which comprised most new Canadian production.
These refinery closures were part of an international trend, since about a dozen refineries in Europe, the Caribbean and along the US east coast have shut down recent years due to sharp increases in the cost of imported oil and declining domestic demand for fuel. Prior to , when China surpassed it, the United States was the largest oil importer in the world. The main market for Canadian bitumen as well as Venezuelan extra-heavy oil was assumed to be the US. Export pipeline capacity is approaching its limits; Canadian oil is selling at a discount to world market prices; and US demand for crude oil and product imports has declined because of US economic problems.
For the benefit of oil marketers, in Western Canadian producers created a new benchmark crude oil called Western Canadian Select , WCS , a bitumen-derived heavy crude oil blend that is similar in its transportation and refining characteristics to California, Mexico Maya, or Venezuela heavy crude oils.
This heavy oil has an API gravity of 19—21 and despite containing large amounts of bitumen and synthetic crude oil, flows through pipelines well and is classified as "conventional heavy oil" by governments. There are several hundred thousand barrels per day of this blend being imported into the US, in addition to larger amounts of crude bitumen and synthetic crude oil SCO from the oil sands. Demand for oil in Asia has been growing much faster than in North America or Europe.
In , China replaced the United States as the world's largest importer of crude oil, and its demand continues to grow much faster than its production. There is sufficient heavy oil refinery capacity in China and India to refine the additional Canadian volume, possibly with some modifications to the refineries.
The world's largest deposits of bitumen are in Canada, although Venezuela's deposits of extra- heavy crude oil are even bigger. Canada has vast energy resources of all types and its oil and natural gas resource base would be large enough to meet Canadian needs for generations if demand was sustained. Abundant hydroelectric resources account for the majority of Canada's electricity production and very little electricity is produced from oil.
The major importing country would probably continue to be the United States, although before the developments in , there was increasing demand for oil, particularly heavy oil, from Asian countries such as China and India. Canada has abundant resources of bitumen and crude oil, with an estimated remaining ultimate resource potential of 54 billion cubic metres billion barrels.
Of this, oil sands bitumen accounts for 90 per cent. Resources become reserves only after it is proven that economic recovery can be achieved. This put its reserves in third place in the world behind Venezuela and Saudi Arabia. At the much lower prices of , the reserves are much smaller.
The costs of production and transportation of saleable petroleum from oil sands is typically significantly higher than from conventional global sources. Major Canadian oil companies had announced expansion plans and foreign companies were investing significant amounts of capital, in many cases forming partnerships with Canadian companies.
Investment had been shifting towards in-situ steam assisted gravity drainage SAGD projects and away from mining and upgrading projects, as oil sands operators foresee better opportunities from selling bitumen and heavy oil directly to refineries than from upgrading it to synthetic crude oil. Cost estimates for Canada include the effects of the mining when the mines are returned to the environment in "as good as or better than original condition". Cleanup of the end products of consumption are the responsibility of the consuming jurisdictions, which are mostly in provinces or countries other than the producing one.
The main market was the huge refinery complexes on the US Gulf Coast, which are generally capable of processing Canadian bitumen and Venezuelan extra-heavy oil without upgrading. Since the larger and more sophisticated refineries preferred to buy raw bitumen and heavy oil rather than synthetic crude oil, new oil sands projects avoided the costs of building new upgraders.
Canadian oil companies were in a more competitive market and had access to more capital than in Venezuela, and preferred to spend that extra money on SAGD or mining to recover more oil. Then in late the dramatic rise in U. None of these forecasts take into account probable international constraints to be imposed on combustion of all hydrocarbons in order to limit global temperature rise, giving rise to a situation denoted by the term " carbon bubble ".
The majority of the growth would likely occur in the in-situ category, as in-situ projects usually have better economics than mining projects. An additional assumption is that there would be sufficient pipeline infrastructure to deliver increased Canadian oil production to export markets. If this were a limiting factor, there could be impacts on Canadian crude oil prices, constraining future production growth.
Another assumption is that US markets will continue to absorb increased Canadian exports. Rapid growth of tight oil production in the US, Canada's primary oil export market, has greatly reduced US reliance on imported crude. The potential for Canadian oil exports to alternative markets such as Asia is also uncertain.
There are increasing political obstacles to building any new pipelines to deliver oil in Canada and the US. In November , U. Other than ocean tankers, these alternatives are all more expensive than pipelines. A shortage of skilled workers in the Canadian oil sands developed during periods of rapid development of new projects. In the absence of other constraints on further development, the oil and gas industry would need to fill tens of thousands of job openings in the next few years as a result of industry activity levels as well as age-related attrition.
In the longer term, under a scenario of higher oil and gas prices, the labor shortages would continue to get worse. A potential labor shortage can increase construction costs and slow the pace of oil sands development.
The skilled worker shortage was much more severe in Venezuela because the government controlled oil company PDVSA fired most of its heavy oil experts after the Venezuelan general strike of —03 , and wound down the production of Orimulsion , which was the primary product from its oil sands.
Following that, the government re-nationalized the Venezuelan oil industry and increased taxes on it. The result was that foreign companies left Venezuela, as did most of its elite heavy oil technical experts.
In recent years, Venezuela's heavy oil production has been falling, and it has consistently been failing to meet its production targets. Hence continued exploration or development of reserves would be extraneous to needs.
The impact on producers in Canada would be far larger than in the U. Open-pit mining of natural bitumen in Canada would soon drop to negligible levels after in all scenarios considered because it is considerably less economic than other methods of production. In their commissioned report entitled "Prudent Development: Secretary of Energy, acknowledged health and safety concerns regarding the oil sands which include "volumes of water needed to generate issues of water sourcing; removal of overburden for surface mining can fragment wildlife habitat and increase the risk of soil erosion or surface run-off events to nearby water systems; GHG and other air emissions from production.
Oil sands extraction can affect the land when the bitumen is initially mined, water resources by its requirement for large quantities of water during separation of the oil and sand, and the air due to the release of carbon dioxide and other emissions. Although oil sands exports to Europe are minimal, the issue has caused friction between the EU and Canada.
Also, Iran, Saudi Arabia, Nigeria and Russia do not provide data on how much natural gas is released via flaring or venting in the oil extraction process. In results of a study published in the Proceedings of the National Academy of Sciences showed that official reports on emissions were not high enough.
Report authors noted that, "emissions of organic substances with potential toxicity to humans and the environment are a major concern surrounding the rapid industrial development in the Athabasca oil sands region AOSR. In September , the Pembina Institute published a brief report about "a recent surge of odour and air quality concerns in northern Alberta associated with the expansion of oilsands development", contrasting the responses to these concerns in Peace River and Fort McKay.
Despite these advantages, more progress was made in remediating the odour problems in the Peace River community, although only after some families had already abandoned their homes. The odour concerns in Fort McKay were reported to remain unresolved. Between 2 and 4. For the Athabasca oil sand operations water is supplied from the Athabasca River, the ninth longest river in Canada. Actual use in was about 0. In December , the Oil Sands Advisory Panel, commissioned by former environment minister Jim Prentice, found that the system in place for monitoring water quality in the region, including work by the Regional Aquatic Monitoring Program, the Alberta Water Research Institute, the Cumulative Environmental Management Association and others, was piecemeal and should become more comprehensive and coordinated.
The production of bitumen and synthetic crude oil emits more greenhouse gases than the production of conventional crude oil. If the entire oil-in-place of 1. To offset greenhouse gas emissions from the oil sands and elsewhere in Alberta, sequestering carbon dioxide emissions inside depleted oil and gas reservoirs has been proposed.
This technology is inherited from enhanced oil recovery methods. In November , Fatih Birol , the chief economist of the International Energy Agency , described additional greenhouse gas emissions from Canada's oil sands as "extremely low". Birol said "the emissions of this additional production is equal to only 23 hours of emissions of China — not even one day.
Birol said he spends little time worrying about carbon emissions from oil sands. Birol acknowledged that there is tremendous difference of opinion on the course of action regarding climate change, but added, "I hope all these reactions are based on scientific facts and sound analysis.
In , the U. Congressional Research Service published a report in preparation for the decision about permitting construction of the Keystone XL pipeline. The report states in part: There is conflicting research on the effects of the oil sands development on aquatic life. In , Environment Canada completed a study that shows high deformity rates in fish embryos exposed to the oil sands.
Schindler , a limnologist from the University of Alberta , co-authored a study on Alberta's oil sands' contribution of aromatic polycyclic compounds , some of which are known carcinogens , to the Athabasca River and its tributaries. RAMP studies show that deformity rates are normal compared to historical data and the deformity rates in rivers upstream of the oil sands.
In , it was suggested that wildlife has been negatively affected by the oil sands; for instance, moose were found in a study to have as high as times the acceptable levels of arsenic in their systems, though later studies lowered this to 17 to 33 times the acceptable level although below international thresholds for consumption. Concerns have been raised concerning the negative impacts that the oil sands have on public health, including higher than normal rates of cancer among residents of Fort Chipewyan.
The College later reported that O'Connor's statements consisted of "mistruths, inaccuracies and unconfirmed information. In , the Royal Society of Canada released a report stating that "there is currently no credible evidence of environmental contaminant exposures from oil sands reaching Fort Chipewyan at levels expected to cause elevated human cancer rates.
In August , the Alberta government initiated a provincial health study to examine whether a link exists between the higher rates of cancer and the oil sands emissions.
From Wikipedia, the free encyclopedia. Not to be confused with Oil shale. History of the petroleum industry in Canada oil sands and heavy oil.
List of countries by proven oil reserves. This section does not cite any sources. Please help improve this section by adding citations to reliable sources. Unsourced material may be challenged and removed. May Learn how and when to remove this template message. Cold Lake oil sands. Peace River oil sands. History of the Venezuelan oil industry. Petroleum production in Canada. Oil sands tailings ponds. Cold heavy oil production with sand.
Steam injection oil industry. Steam assisted gravity drainage. Natural gas in Canada. Petroleum Administration for Defense Districts. Petroleum industry in China. Environmental impact of the Athabasca oil sands and Environmental impact of the petroleum industry. Retrieved 13 May The energy security problem solved?
Oil and Energy Trends. National Energy Board of Canada. Retrieved 26 March Canadian Association of Petroleum Producers. Retrieved 28 Feb Oil sands are a mixture of sand, water, clay and bitumen. Bitumen is oil that is too heavy or thick to flow or be pumped without being diluted or heated.
Survey of energy resources PDF 22 ed. Retrieved 1 January Retrieved 23 October The New York Times. Retrieved 11 February City of Kingston, Ontario. Archived from the original on 10 April Retrieved 22 April If unconventional sources of oil, such as oil sands, could be transformed into crude we could still have a year supply left.
The problem is extracting it". Retrieved 7 October The Journals and Letters of Alexander Mackenzie. Alberta Department of Energy. Association of Petroleum Engineers and Geoscientists of Alberta. Peace River proceeding no. Retrieved 23 January Historical Dictionary of the Petroleum Industry.
Retrieved 14 May Retrieved 23 July Retrieved 4 May US National Public Radio. Things are very, very bad. I have been covering Venezuela for a long time. And frankly, I was shocked at the situation as I see it here at the moment. Retrieved 21 May Saskatchewan Energy and Mines.
Journal of Petroleum Science Research. Science and Engineering Publishing Company. Thermal Recovery of Oil and Bitumen. Retrieved 18 February Oil Sands Developers Group.
Petrobank Energy and Resources Ltd. Archived from the original on Retrieved 7 December Retrieved 19 March Retrieved 13 August Retrieved 8 April Retrieved 17 August Retrieved 14 August Archived from the original PDF on 3 October Venezuela's upgraders are maxed out to handle its heavy oil".
Platts, McGraw Hill Financial. Canadian Transportation Research Foundation. Retrieved 6 November Retrieved 7 November Toronto Globe and Mail. Retrieved 16 April University of Calgary School of Public Policy. Canadian Energy Research Institute. International New York Times. The Wall Street Journal. Beware of the Carbon Bubble Report. The Globe and Mail. Retrieved November 6, Gary 20 August In McKenzie-Brown listed industrialist J.
Howard Pew as one of the six visionaries who built the Athabasca oil sands. In , Sun formed Suncor by merging its Canadian refining and retailing interests with Great Canadian Oil Sands and its conventional oil and gas interests.
In 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 , Suncor acquired the formerly Canadian government owned oil company, Petro-Canada ,   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. The true size of the Canadian oil sands deposits became known in the s.
Development was inhibited by declining world oil prices, and the second mine, operated by the Syncrude consortium, did not begin operating until , after the oil crisis sparked investor interest. However the price of oil subsided afterwards and although the energy crisis caused oil prices to peak again, during the s, oil prices declined to very low levels causing considerable retrenchment in the oil industry. At the turn of the 21st century, oil sands development in Canada started to take off, with an expansion at the Suncor mine, a new mine and expansion at Syncrude, and a new mine by Royal Dutch Shell associated with their new Scotford Upgrader near Edmonton.
Three new large steam assisted gravity drainage SAGD projects were added — Foster Creek, Surmont, and MacKay River — by different companies, all of which have since been bought by larger companies. Shell Canada 's third mine began operating in However, as a result of oil price increases since , 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:. The Alberta government believes this level of production could reach 3. In , the actual oil production from oil sands was 1.
Keystone XL , a pipeline from Alberta to Gulf coast refineries, is under consideration,  as is the North Gateway project to Kitimat, British Columbia , which would be built by Enbridge , operator of the Enbridge Pipeline System which also serves the area. As of December , the Canadian Association of Petroleum Producers revised its — crude oil forecasts to account for project cancellations and cutbacks as a result of the price declines in the second half of The revised forecast predicted that Canadian oil sands production would continue to grow, but at a slower rate than previously predicted.
This would mean that Canadian oil sands production would grow from 1. In early December , 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. 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. 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. 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. Ottawa has avoided direct investment, preferring to improve the investment climate. Some people have claimed that Alberta features one of the lowest royalty rates in the world. This industry-centric royalty system has been criticised for "promoting a runaway pace of development". Industry is the core force of oil sands development. The first major players, Suncor Energy and Syncrude , dominated the market until the s.
Currently there are 64 companies operating several hundred projects. 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.
The MSC represents four organisations: On October 17, , 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. 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.
On 17 June the newly formed corporation, Alberta Energy Regulator AER  was phased in with a mandate to regulate oil, gas and coal development in Alberta including the Athabasca oil sands. The key characteristic of the Athabasca deposit is that it is the only one shallow enough to be suitable for surface mining.
The Albian Sands mine operated by Shell Canada opened in 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. The Energy Resource Conservation Board has approved over mining and in-situ projects despite the negative environmental impacts.
The ERCB has also approved 20 projects that are testing unproven technology as well as new versions of existing technologies. Since Great Canadian Oil Sands now Suncor started operation of its mine in , 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. 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.
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.
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. 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. 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. The original process for extraction of bitumen from the sands was developed by Dr. Karl Clark , working with the Alberta Research Council in the s. In this process, the ores are mined using open-pit mining technology.
The mined ore is then crushed for size reduction. The recovered bitumen froth needs to be cleaned to reject the contained solids and water to meet the requirement of downstream upgrading processes. 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.
Butler "developed the concept of using horizontal pairs of wells and injected steam to develop certain deposits of bitumen considered too deep for mining. More recently, in situ methods like steam-assisted gravity-drainage SAGD and cyclic steam stimulation CSS have been developed to extract bitumen from deep deposits by injecting steam to heat the sands and reduce the bitumen viscosity so that it can be pumped out like conventional crude oil.
The standard extraction process requires huge amounts of natural gas. By , this may increase two-and-a-half-fold. 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. Open pit mining destroys the boreal forest and muskeg , while in situ extraction technologies cause less significant damage. This means that the ability of the land to support various land uses after reclamation is similar to what existed, but that the individual land uses may not necessarily be identical.
In some particular circumstances the government considers agricultural land to be equivalent to forest land. Oil sands companies have reclaimed mined land to use as pasture for wood bison instead of restoring it to the original boreal forest and muskeg.
Approved oil sands mining operations are currently licensed to divert million m 3 from the Athabasca River, or more than twice the volume of water required to meet the annual municipal needs of the City of Calgary.
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. 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.
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 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.
The processing of bitumen into synthetic crude requires energy, which is currently being generated by burning natural gas. Based on gas purchases, natural gas requirements are given by the Canadian Energy Resource Institute as 2. A 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. The forecast growth in synthetic oil production in Alberta also threatens Canada's international commitments.
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 CO 2 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.
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. 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.
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. 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. 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.
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 in analysis began to reveal what is in the oil sands tailings ponds. 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.
By Suncor had transformed their first tailings pond, Pond One, into Wapisiw Lookout, the first reclaimed settling basin in the oil sands. In the area was a 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 but Pond One was the first effluent pond in the oil sands industry in and was used until By 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 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 s. It was then planted with reclamation plants.
In March 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. In January , scientists from Queen's University published a report analyzing lake sediments in the Athabasca region over the past fifty years.
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 The team discovered that the contamination spread farther than previously thought. 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.
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. 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 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. In July , one of the largest leaks in Canada's history spilled 5, 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.
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  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.
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 s, 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, in , the boomtown of Fort McMurray and the surrounding region known as the Regional Municipality of Wood Buffalo grew to 79, people as of , including a "shadow population" of 10, living in work camps,  leaving the community struggling to provide services and housing for migrant workers, many of them from Eastern Canada, especially Newfoundland.
Fort McMurray ceased to be an incorporated city in and is now an urban service area within Wood Buffalo. 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. By 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. However, while the Orinoco deposits are less viscous and more easily produced using conventional techniques the Venezuelan government prefers to call them "extra-heavy oil" , they are too deep to access by surface mining. Despite the large reserves, the cost of extracting the oil from bituminous sands has historically made production of the oil sands unprofitable—the cost of selling the extracted crude would not cover the direct costs of recovery; labour to mine the sands and fuel to extract the crude.
The capital cost of the equipment required to mine the sands and haul it to processing is a major consideration in starting production. Therefore, although high crude prices make the cost of production very attractive, sudden drops in price leaves producers unable to recover their capital costs—although the companies are well financed and can tolerate long periods of low prices since the capital has already been spent and they can typically cover incremental operating costs. However, the development of commercial production is made easier by the fact that exploration costs are very low.
Such costs are a major factor when assessing the economics of drilling in a traditional oil field. The location of the oil deposits in the oil sands are well known, and an estimate of recovery costs can usually be made easily. There is not another region in the world with energy deposits of comparable magnitude where it would be less likely that the installations would be confiscated by a hostile national government, or be endangered by a war or revolution.
As a result of the oil price increases since , the economics of oil sands have improved dramatically. In and 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, Alberta Highway 63 , connecting it to the rest of the province, and there is pressure on the government of Alberta to improve road links as well as hospitals and other infrastructure.
Despite the best efforts of companies to move as much of the construction work as possible out of the Fort McMurray area, and even out of Alberta, the shortage of skilled workers is spreading to the rest of the province.