Oil sands, tar sands or, more technically, bituminous sands, are a type of unconventional petroleum deposit.
The oil sands are loose sand or partially consolidated sandstone containing naturally occurring mixtures of sand, clay, and water, saturated with a dense and extremely viscous form of petroleum technically referred to as bitumen (or colloquially tar due to its similar appearance, odour and colour). Natural bitumen deposits are reported in many countries, but in particular are found in extremely large quantities in Canada. Other large reserves are located in Kazakhstan and Russia. The estimated worldwide deposits of oil are more than 2 trillion barrels (320 billion cubic metres); the estimates include deposits that have not yet been discovered. Proven reserves of bitumen contain approximately 100 billion barrels, and total natural bitumen reserves are estimated at 249.67 billion barrels (39.694×109 m3) globally, of which 176.8 billion barrels (28.11×109 m3), or 70.8%, are in Canada.
Oil sands reserves have only recently[when?] been considered to be part of the world's oil reserves, as higher oil prices and new technology enable profitable extraction and processing. Oil produced from bitumen sands is often referred to as unconventional oil or crude bitumen, to distinguish it from liquid hydrocarbons produced from traditional oil wells.
The crude bitumen contained in the Canadian oil sands is described by the National Energy Board of Canada as "a highly viscous mixture of hydrocarbons heavier than pentanes which, in its natural state, is not usually recoverable at a commercial rate through a well because it is too thick to flow." Crude bitumen is a thick, sticky form of crude oil, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons such as light crude oil or natural-gas condensate. At room temperature, it is much like cold molasses. The World Energy Council (WEC) defines natural bitumen as "oil having a viscosity greater than 10,000 centipoise under reservoir conditions and an API gravity of less than 10° API". The Orinoco Belt in Venezuela is sometimes described as oil sands, but these deposits are non-bituminous, falling instead into the category of heavy or extra-heavy oil due to their lower viscosity. Natural bitumen and extra-heavy oil differ in the degree by which they have been degraded from the original conventional oils by bacteria. According to the WEC, extra-heavy oil has "a gravity of less than 10° API and a reservoir viscosity of no more than 10,000 centipoise".
Making liquid fuels from oil sands requires energy for steam injection and refining. This process generates 12 percent more greenhouse gases per barrel of final product than extraction of conventional oil.
- 1 History
- 2 Major deposits
- 3 Production
- 4 Methods of extraction
- 5 Transportation and refining
- 6 Economics
- 7 Environmental issues
- 8 Input energy
- 9 See also
- 10 References
- 11 Further reading
- 12 External links
The exploitation of bituminous deposits and seeps dates back to Paleolithic times. The earliest known use of bitumen was by Neanderthals, some 40,000 years ago. Bitumen has been found adhering to stone tools used by Neanderthals at sites in Syria. After the arrival of Homo sapiens, humans used bitumen for construction of buildings and waterproofing of reed boats, among other uses. In ancient Egypt, the use of bitumen was important in preparing Egyptian mummies.
In ancient times, bitumen was primarily a Mesopotamian commodity used by the Sumerians and Babylonians, although it was also found in the Levant and Persia. The area along the Tigris and Euphrates rivers was littered with hundreds of pure bitumen seepages. The Mesopotamians used the bitumen for waterproofing boats and buildings. In North America, the early European fur traders found Canadian First Nations peoples using bitumen from the vast Athabasca oil sands to waterproof their birch-bark canoes. In Europe, they were extensively mined near the French city of Pechelbronn, where the vapour separation process was in use in 1742.
The name tar sands was applied to bituminous sands in the late 19th and early 20th century. People who saw the bituminous sands during this period were familiar with the large amounts of tar residue produced in urban areas as a by-product of the manufacture of coal gas for urban heating and lighting. The word "tar" to describe these natural bitumen deposits is really a misnomer, since, chemically speaking, tar is a human-made substance produced by the destructive distillation of organic material, usually coal.
Since then, coal gas has almost completely been replaced by natural gas as a fuel, and coal tar as a material for paving roads has been replaced by the petroleum product asphalt. Naturally occurring bitumen is chemically more similar to asphalt than to coal tar, and the term oil sands (or oilsands) is more commonly used by industry in the producing areas than tar sands because synthetic oil is manufactured from the bitumen, and due to the feeling that the terminology of tar sands is less politically acceptable to the public. Oil sands are now an alternative to conventional crude oil. The basic process for extracting the oil from oil sands was developed by Karl Clark in the 1920s.
There are numerous deposits of oil sands in the world, but the biggest and most important are in Canada and Venezuela, with lesser deposits in Kazakhstan and Russia. The total volume of non-conventional oil in the oil sands of these countries exceeds the reserves of conventional oil in all other countries combined.
Most of the Canadian oil sands are in three major deposits in northern Alberta. They are the Athabasca-Wabiskaw oil sands of north northeastern Alberta, the Cold Lake deposits of east northeastern Alberta, and the Peace River deposits of northwestern Alberta. Between them, they cover over 140,000 square kilometres (54,000 sq mi)—an area larger than England—and contain approximately 1.75 trillion barrels (280×109 m3) of crude bitumen in them. About 10% of the oil in place, or 173 billion barrels (27.5×109 m3), is estimated by the government of Alberta to be recoverable at current prices, using current technology, which amounts to 97% of Canadian oil reserves and 75% of total North American petroleum reserves. Although the Athabasca deposit is the only one in the world which has areas shallow enough to mine from the surface, all three Alberta areas are suitable for production using in-situ methods, such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD).
The Athabasca oil sands lie along the Athabasca River and are the largest natural bitumen deposit in the world, containing about 80% of the Alberta total, and the only one suitable for surface mining. With modern unconventional oil production technology, at least 10% of these deposits, or about 170 billion barrels (27×109 m3) are considered to be economically recoverable, making Canada's total proven reserves the third largest in the world, after Saudi Arabia's conventional oil and Venezuela's Orinoco oil sands.
The Athabasca River cuts through the heart of the deposit, and traces of the heavy oil are readily observed as black stains on the river banks. Since portions of the Athabasca sands are shallow enough to be surface-mineable, they were the earliest ones to see development. Historically, the bitumen was used by the indigenous Cree and Dene Aboriginal peoples to waterproof their canoes. 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.
In 1778, Peter Pond, a fur trader for the rival North West Company, was the first European to see the Athabasca deposits. In 1788, fur trader and explorer Alexander MacKenzie from the Hudson Bay Company, who later discovered the MacKenzie River and routes to both the Arctic and Pacific Oceans, described the oil sands in great detail. He said, "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."
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 of the Geological Survey of Canada reported to a Senate Committee that "The evidence ... points to the existence in the Athabasca and Mackenzie valleys of the most extensive petroleum field in America, if not the world." In 1926, Karl Clark of the University of Alberta patented a hot water separation process which was the forerunner of today's thermal extraction processes. However, it was 1967 before the first large scale commercial operation began with the opening of the Great Canadian Oil Sands mine by the Sun Oil Company of Ohio.
Today its successor company, Suncor Energy (no longer affiliated with Sun Oil), is the largest oil company in Canada. In addition, other companies such as Shell, Exxon, and various national oil companies are developing the Athabasca oil sands. As a result, Canada is now by far the largest exporter of oil to the United States.
The smaller Wabasca (or Wabiskaw) oil sands lie above the western edge of the Athabasca oil sands and overlap them. In many regions the oil-rich Wabasca formation overlies the similarly oil-rich McMurray formation edge, and as a result the two overlapping oil sands are often treated as one oil sands deposit. However, the two reservoirs are invariable separated by a minimum of 6-8 metres of clay shale and silt. The bitumen in the Wabasca is as highly viscous as that in the Athabasca, but lies too deep to be surface-mined, so in-situ production methods must be used to produce the crude bitumen.
The Cold Lake oil sands are northeast of Alberta's capital, Edmonton, near the border with Saskatchewan. A small portion of the Cold Lake deposit lies in Saskatchewan. Although smaller than the Athabasca oil sands, the Cold Lake oil sands are important because some of the oil is fluid enough to be extracted by conventional methods. The Cold Lake bitumen contains more alkanes and less asphaltenes than the other major Alberta oil sands and the oil is more fluid. As a result, cyclic steam stimulation (CSS) is commonly used for production.
Much of the oil sands are on Canadian Forces Base Cold Lake. CFB Cold Lake's CF-18 Hornet jet fighters defend the western half of Canadian air space and cover Canada's Arctic territory. Cold Lake Air Weapons Range (CLAWR) is one of the largest live-drop bombing ranges in the world, including testing of cruise missiles. As oil sands production continues to grow, various sectors vie for access to airspace, land, and resources, and this complicates oil well drilling and production significantly.
The Peace River oil sands located in northwest-central Alberta are the smallest of the three major oil sands deposits in Alberta. The Peace River oil sands lie generally in the watershed of the Peace River, the largest river in Alberta. The Peace and Athabasca rivers, which are by far the largest rivers in Alberta, flow through their respective oil sands and merge at Lake Athabasca to form the Slave River, which flows into the MacKenzie River, one of the largest rivers in the world. All of the water from these rivers flow into the Arctic Ocean.
Whereas the Athabasca oil sands lie close enough to the surface that the bitumen can be excavated in open-pit mines, the smaller Peace River deposits are too deep, and must be exploited using in situ methods such as steam-assisted gravity drainage and Cold Heavy Oil Production with Sand (CHOPS).
The Orinoco Belt is a territory in the southern strip of the eastern Orinoco River Basin in Venezuela which overlies one of the world's largest deposits of petroleum. The Orinoco Belt follows the line of the river. It is approximately 600 kilometres (370 mi) from east to west, and 70 kilometres (43 mi) from north to south, with an area about 55,314 square kilometres (21,357 sq mi).
The oil sands consist of large deposits of extra heavy crude. Venezuela's heavy oil deposits of about 1,200 billion barrels (1.9×1011 m3) of oil in place are estimated to approximately equal the world's reserves of lighter oil. Petróleos de Venezuela S.A. (PDVSA), Venezuela's national oil company, has estimated that the producible reserves of the Orinoco Belt are up to 235 billion barrels (3.74×1010 m3) which would make it the largest petroleum reserve in the world.
In 2009, the US Geological Survey (USGS) increased its estimates of the reserves to 513 billion barrels (8.16×1010 m3) of oil which is "technically recoverable (producible using currently available technology and industry practices)." No estimate of how much of the oil is economically recoverable was made. 
Despite the fact that the Orinoco oil sands contain extra-heavy oil which is easier to produce than Canada's similarly-sized reserves of bitumen, Venezuela's oil production has been declining in recent years due to the country's political and economic problems, while Canada's have been increasing. As a result, Canadian heavy oil and bitumen exports have been backing Venezuelan heavy and extra-heavy oil out of the US market, and Canada's total exports of oil to the US are now several times as great as Venezuela's.
In addition to the three major Canadian oil sands in Alberta, there is a fourth major oil sands deposit in Canada, the Melville Island oil sands in the Canadian Arctic islands which are too remote to expect commercial production in the foreseeable future.
Outside of Canada and Venezuela, numerous other countries hold oil sands deposits which are smaller by orders of magnitude. In Kazakhstan, the bitumen deposits are located in the North Caspian Basin. Russia holds oil sands in two main regions. Large resources are present in the Tunguska Basin, East Siberia, with the largest deposits being Olenek and Siligir. Other deposits are located in the Timan-Pechora and Volga-Urals basins (in and around Tatarstan), which is an important but very mature province in terms of conventional oil, holds large amounts of oil sands in a shallow permian formation.
In Madagascar, Tsimiroro and Bemolanga are two heavy oil sands deposits, with a pilot well already producing small amounts of oil in Tsimiroro. and larger scale exploitation in the early planning phase. In the Republic of the Congo reserves are estimated between 0.5 and 2.5 billion barrels (79×106 and 397×106 m3).
In the United States, oil sands resources are primarily concentrated in Eastern Utah, with a total of 32 billion barrels (5.1×109 m3) of oil (known and potential) in eight major deposits in Carbon, Garfield, Grand, Uintah, and Wayne counties. In addition to being much smaller than the oil sands deposits in Alberta, Canada, the U.S. oil sands are hydrocarbon-wet, whereas the Canadian oil sands are water-wet. As a result of this difference, extraction techniques for the Utah oil sands will be different from those used for the Alberta oil sands.
Bituminous sands are a major source of unconventional oil, although only Canada has a large-scale commercial oil sands industry. In 2006, bitumen production in Canada averaged 1.25 million barrels per day (200,000 m3/d) through 81 oil sands projects. 44% of Canadian oil production in 2007 was from oil sands. This proportion is expected to increase in coming decades as bitumen production grows while conventional oil production declines, although due to the 2008 economic downturn work on new projects has been deferred. Petroleum is not produced from oil sands on a significant level in other countries.
The Alberta oil sands have been in commercial production since the original Great Canadian Oil Sands (now Suncor Energy) mine began operation in 1967. Despite the increasing levels of production, the process of extraction and processing of oil sands can still be considered to be in its infancy; with new technologies and stakeholders oversight providing an ever lower environmental footprint. A second mine, operated by the Syncrude consortium, began operation in 1978 and is the biggest mine of any type in the world. The third mine in the Athabasca Oil Sands, the Albian Sands consortium of Shell Canada, Chevron Corporation, and Western Oil Sands Inc. [purchased by Marathon Oil Corporation in 2007] began operation in 2003. Petro-Canada was also developing a $33 billion Fort Hills Project, in partnership with UTS Energy Corporation and Teck Cominco, which lost momentum after the 2009 merger of Petro-Canada into Suncor.
By 2013 there were nine oil sands mining projects in the Athabasca oil sands deposit: Suncor Energy Inc. (Suncor), Syncrude Canada Limited (Syncrude)'s Mildred Lake and Aurora North, Shell Canada Limited (Shell)'s Muskeg River and Jackpine, Canadian Natural Resources Limited (CNRL), Horizon, Imperial Oil Resources Ventures Limited (Imperial), Kearl Oil Sands Project (KOSP), Total E&P Canada Ltd. Joslyn North Mine and Fort Hills Energy Corporation (FHEC). In 2011 alone they produced over 52 million cubic metres of bitumen.
In May 2008, the Italian oil company Eni announced a project to develop a small oil sands deposit in the Republic of the Congo. Production is scheduled to commence in 2014 and is estimated to eventually yield a total of 40,000 barrels per day (6,400 m3/d).
Methods of extraction
Conventional crude oil is normally extracted from the ground by drilling oil wells into a petroleum reservoir, allowing oil to flow into them under natural reservoir pressures, although artificial lift and techniques such as water flooding and gas injection are usually required to maintain production as reservoir pressure drops toward the end of a field's life. Because bitumen flows very slowly, if at all, toward producing wells under normal reservoir conditions, the sands must be extracted by strip mining or the oil made to flow into wells by in-situ techniques, which reduce the viscosity by injecting steam, solvents, and/or hot air into the sands. These processes can use more water and require larger amounts of energy than conventional oil extraction, although many conventional oil fields also require large amounts of water and energy to achieve good rates of production.
The Athabasca oil sands are the only major oil sands deposits which are shallow enough to surface mine. 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) thick deposits of crude bitumen embedded in unconsolidated sandstone, sitting on top of flat limestone rock. Since Great Canadian Oil Sands (now Suncor) started operation of its mine in 1967, bitumen has been extracted on a commercial scale and the volume is growing at a rapid rate.
A large number of oil sands mines are currently in operation and more are in the stages of approval or development. The Syncrude mine started in 1978, Shell Canada opened its Muskeg River mine (Albian Sands) in 2003 and Canadian Natural Resources Ltd opened its Horizon oil sands project in 2009. Newer mines include Shell Canada's Jackpine mine, Imperial Oil's Kearl Oil Sands Project, Synenco Energy's Northern Lights mine, and Suncor's Fort Hills mine.
In this technique, also known as cold heavy oil production with sand (CHOPS), the oil is simply pumped out of the sands, often using progressive cavity pumps. This only works well in areas where the oil is fluid enough. It is commonly used in Venezuela (where the extra-heavy oil is at 50 degrees Celsius), and also in the Wabasca, Alberta Oil Sands, the southern part of the Cold Lake Oil Sands and the Peace River Oil Sands. It has the advantage of being cheap and the disadvantage that it recovers only 5–6% of the oil in place.
Some years ago Canadian oil companies discovered that if they removed the sand filters from the wells and produced as much sand as possible with the oil, production rates improved remarkably. This technique became known as Cold Heavy Oil Production with Sand (CHOPS). Further research disclosed that pumping out sand opened "wormholes" in the sand formation which allowed more oil to reach the wellbore. The advantage of this method is better production rates and recovery (around 10%) and the disadvantage that disposing of the produced sand is a problem. A novel way to do this was spreading it on rural roads, which rural governments liked because the oily sand reduced dust and the oil companies did their road maintenance for them. However, governments have become concerned about the large volume and composition of oil spread on roads, so in recent years disposing of oily sand in underground salt caverns has become more common.
Cyclic Steam Stimulation (CSS)
The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s. The Cyclic Steam Stimulation or "huff-and-puff" method has been in use by Imperial Oil at Cold Lake since 1985 and is also used by Canadian Natural Resources at Primrose and Wolf Lake and by Shell Canada at Peace River. In this method, the well is put through cycles of steam injection, soak, and oil production. First, steam is injected into a well at a temperature of 300 to 340 degrees Celsius for a period of weeks to months; then, the well is allowed to sit for days to weeks to allow heat to soak into the formation; and, later, the hot oil is pumped out of the well for a period of weeks or months. Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes higher than the money made from producing oil. The CSS method has the advantage that recovery factors are around 20 to 25% and the disadvantage that the cost to inject steam is high.
Steam Assisted Gravity Drainage (SAGD)
Steam assisted gravity drainage was developed in the 1980s by the Alberta Oil Sands Technology and Research Authority and fortuitously coincided with improvements in directional drilling technology that made it quick and inexpensive to do by the mid 1990s. In SAGD, two horizontal wells are drilled in the oil sands, one at the bottom of the formation and another about 5 metres above it. These wells are typically drilled in groups off central pads and can extend for miles in all directions. In each well pair, steam is injected into the upper well, the heat melts the bitumen, which allows it to flow into the lower well, where it is pumped to the surface.
SAGD has proved to be a major breakthrough in production technology since it is cheaper than CSS, allows very high oil production rates, and recovers up to 60% of the oil in place. Because of its economic feasibility and applicability to a vast area of oil sands, this method alone quadrupled North American oil reserves and allowed Canada to move to second place in world oil reserves after Saudi Arabia. Most major Canadian oil companies now have SAGD projects in production or under construction in Alberta's oil sands areas and in Wyoming. Examples include Japan Canada Oil Sands Ltd's (JACOS) project, Suncor's Firebag project, Nexen's Long Lake project, Suncor's (formerly Petro-Canada's) MacKay River project, Husky Energy's Tucker Lake and Sunrise projects, Shell Canada's Peace River project, Cenovus Energy's Foster Creek and Christina Lake developments, ConocoPhillips' Surmont project, Devon Canada's Jackfish project, and Derek Oil & Gas's LAK Ranch project. Alberta's OSUM Corp has combined proven underground mining technology with SAGD to enable higher recovery rates by running wells underground from within the oil sands deposit, thus also reducing energy requirements compared to traditional SAGD. This particular technology application is in its testing phase.
Several experiments use solvents, instead of steam, to separate bitumen from sand. Some solvent extraction methods may work better in in situ production and other in mining. Solvent can be beneficial if it does not require the energy needed to produce steam. Also, as opposed to water that must be impounded, solvent may be removed from the sands and re-used.
Vapor Extraction Process (VAPEX) is an in situ technology, similar to SAGD. Instead of steam, hydrocarbon solvents are injected into an upper well to dilute bitumen and enables the diluted bitumen to flow into a lower well. It has the advantage of much better energy efficiency over steam injection, and it does some partial upgrading of bitumen to oil right in the formation. It is very new, but the process has attracted much attention from oil companies, who are beginning to experiment with it.
The above three methods are not mutually exclusive. It is becoming common for wells to be put through one CSS injection-soak-production cycle to condition the formation prior to going to SAGD production, and companies are experimenting with combining VAPEX with SAGD to improve recovery rates and lower energy costs.
Toe to Heel Air Injection (THAI)
This is a very new and experimental method that combines a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the "toe" of the horizontal well toward the "heel", which burns the heavier oil components and upgrades some of the heavy bitumen into lighter oil right in the formation. Historically fireflood projects have not worked out well because of difficulty in controlling the flame front and a propensity to set the producing wells on fire. However, some oil companies feel the THAI method will be more controllable and practical, and have the advantage of not requiring energy to create steam.
Petrobank Energy and Resources has reported encouraging results from their test wells in Alberta, with production rates of up to 400 barrels per day (64 m3/d) per well, and the oil upgraded from 8 to 12 API degrees. The company hopes to get a further 7-degree upgrade from its CAPRI (controlled atmospheric pressure resin infusion) system, which pulls the oil through a catalyst lining the lower pipe.
After several years of production in situ, it has become clear that current THAI methods do not work as planned. Amid steady drops in production from their THAI wells at Kerrobert, Petrobank has written down the value of their THAI patents and the reserves at the facility to zero. They have plans to experiment with a new configuration they call "multi-THAI," involving adding more air injection wells. 
Combustion Overhead Gravity Drainage (COGD)
This is an experimental method that employs a number of vertical air injection wells above a horizontal production well located at the base of the bitumen pay zone. An initial Steam Cycle similar to CSS is used to prepare the bitumen for ignition and mobility. Following that cycle, air is injected into the vertical wells, igniting the upper bitumen and mobilizing (through heating) the lower bitumen to flow into the production well. It is expected that COGD will result in water savings of 80% compared to SAGD.
Transportation and refining
The heavy crude oil or crude bitumen extracted from oil sands is a viscous solid or semisolid form that does not easily flow at normal oil pipeline temperatures, making it difficult to transport to market and expensive to process into gasoline, diesel fuel, and other products. It must be either mixed with lighter petroleum (either liquid or gas) or chemically split before it can be transported by pipeline for upgrading into synthetic crude oil.
Heavy crude feedstock needs pre-processing before it is fit for conventional refineries. This pre-processing is called 'upgrading', the key components of which are as follows:
- removal of water, sand, physical waste, and lighter products
- catalytic purification by hydrodemetallisation (HDM), hydrodesulfurization (HDS) and hydrodenitrogenation (HDN)
- hydrogenation through carbon rejection or catalytic hydrocracking (HCR)
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.
||The examples and perspective in this section may not represent a worldwide view of the subject. (April 2013)|
Canada has abundant resources of bitumen and crude oil, with an estimated remaining ultimate potential of 54 billion cubic metres (340 billion barrels). Of this, oil sands bitumen accounts for 90 per cent. Alberta currently accounts for all of Canada’s bitumen resources. Resources become reserves only after it is proven that economic recovery can be achieved. At current prices using current technology, Canada has remaining oil reserves of 27 billion m3 (170 billion bbls), with 98 per cent of this attributed to oil sands bitumen. This puts its reserves in third place in the world behind Venezuela and Saudi Arabia.
An oil price of $100/bbl is sufficient to promote active growth in oil sands production. Major Canadian oil companies have announced expansion plans and foreign companies are investing significant amounts of capital, in many cases forming partnerships with Canadian companies. Investment has 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.
Oil sands production forecasts released by the Canadian Association of Petroleum Producers (CAPP), the Alberta Energy Regulator (AER), and the Canadian Energy Research Institute (CERI) are comparable to National Energy Board (NEB) projections, in terms of total bitumen production. The list of currently proposed projects, many of which are in the early planning stages, suggest that by 2035 Canadian bitumen production could potentially reach as much as 1.3 million m3/d (8.3 million barrels per day) if most were to go ahead.
A more likely scenario is that by 2035, Canadian oil sands bitumen production will reach 800,000 m3/d (5.0 million barrels/day), 2.6 times the production for 2012. The majority of the growth will likely occur in the in-situ category, as in-situ projects usually have better economics than mining projects. Also, 80% of Canada's oil sands reserves are well-suited to in-situ extraction, versus 20% for mining methods.
A key assumption is that there will be sufficient pipeline infrastructure to deliver increased Canadian oil production to export markets. If this is not the case, there may be impacts on Canadian crude oil prices, and there may be reductions in 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, could reduce 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 the absence of new pipeline capacity, companies are increasingly shipping bitumen to US markets by railway, river barge, tanker, and other transportation methods. Other than ocean tankers, these alternatives are all more expensive than pipelines.
A shortage of skilled workers is developing as overall demand for labor in the oil sands increases. The oil and gas industry needs 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 will continue to get worse. A potential labor shortage may increase construction costs and slow the pace of oil sands development.
In their 2011 commissioned report entitled "Prudent Development: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources," the National Petroleum Council, an advisory committee to the U.S. 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. Heavy metals such as vanadium, nickel, lead, cobalt, mercury, chromium, cadmium, arsenic, selenium, copper, manganese, iron and zinc are naturally present in oil sands and may be concentrated by the extraction process. The environmental impact caused by oil sand extraction is frequently criticized by environmental groups such as Greenpeace, Climate Reality Project, Pembina Institute, 350.org, MoveOn.org, League of Conservation Voters, Patagonia, Sierra Club, and Energy Action Coalition. In particular, mercury contamination has been found around tar sands production in Alberta, Canada. The European Union has indicated that it may vote to label oil sands oil as "highly polluting". Although oil sands exports to Europe are minimal, the issue has caused friction between the EU and Canada. According to the California-based Jacobs Consultancy, the European Union used inaccurate and incomplete data in assigning a high greenhouse gas rating to gasoline derived from Alberta’s oilsands. 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. The Jacobs report pointed out that extra carbon emissions from oil-sand crude are 12 percent higher than from regular crude, although it was assigned a GHG rating 22% above the conventional benchmark by EU.
In 2014 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)." This study found that tailings ponds were an indirect pathway transporting uncontrolled releases of evaporative emissions of three representative polycyclic aromatic hydrocarbon (PAH)s (phenanthrene, pyrene, and benzo(a)pyrene) and that these emissions had been previously unreported.
Air pollution management
Since 1995, monitoring in the oil sands region shows improved or no change in long term air quality for the five key air quality pollutants – carbon monoxide, nitrogen dioxide, ozone, fine particulate matter (PM2.5) and sulfur dioxide – used to calculate the Air Quality Index. Air monitoring has shown significant increases[when?] in exceedances of hydrogen sulfide (H
2S) both in the Fort McMurray area and near the oil sands upgraders.
In 2007, the Alberta government issued an environmental protection order to Suncor in response to numerous occasions when ground level concentration for hydrogen sulfide (formula H
2S) exceeded standards.
Land use and waste management
A large part of oil sands mining operations involves clearing trees and brush from a site and removing the overburden— topsoil, muskeg, sand, clay and gravel – that sits atop the oil sands deposit. Approximately two tons of oil sands are needed to produce one barrel of oil (roughly 1/8 of a ton). As a condition of licensing, projects are required to implement a reclamation plan. The mining industry asserts that the boreal forest will eventually colonize the reclaimed lands, but their operations are massive and work on long-term timeframes. As of 2013, about 715 square kilometres (276 sq mi) of land in the oil sands region have been disturbed, and 72 km2 (28 sq mi) of that land is under reclamation. In March 2008, Alberta issued the first-ever oil sands land reclamation certificate to Syncrude for the 1.04 square kilometres (0.40 sq mi) parcel of land known as Gateway Hill approximately 35 kilometres (22 mi) north of Fort McMurray. Several reclamation certificate applications for oil sands projects are expected within the next 10 years.
Between 2 to 4.5 volume units of water are used to produce each volume unit of synthetic crude oil in an ex-situ mining operation. According to Greenpeace, the Canadian oil sands operations use 349 million cubic metres per annum (12.3×109 cu ft/a) of water, twice the amount of water used by the city of Calgary. However, in SAGD operations, 90–95% of the water is recycled and only about 0.2 volume units of water is used per volume unit of bitumen produced.
For the Athabasca oil sand operations water is supplied from the Athabasca River, the ninth longest river in Canada. The average flow just downstream of Fort McMurray is 633 cubic metres per second (22,400 cu ft/s) with its highest daily average measuring 1,200 cubic metres per second (42,000 cu ft/s). Oil sands industries water license allocations totals about 1.8% of the Athabasca river flow. Actual use in 2006 was about 0.4%. In addition, 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.
In December 2010, 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.
Greenhouse gas emissions
The production of bitumen and synthetic crude oil emits more greenhouse gases than the production of conventional crude oil. A 2009 study by the consulting firm IHS CERA estimated that production from Canada's oil sands emits "about 5% to 15% more carbon dioxide, over the "well-to-wheels" (WTW) lifetime analysis of the fuel, than average crude oil." 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 the petroleum production.
According to the Canadian Association of Petroleum Producers and Environment Canada the industrial activity undertaken to produce oil sands make up about 5% of Canada's greenhouse gas emissions, or 0.1% of global greenhouse gas emissions. It predicts the oil sands will grow to make up 8% of Canada's greenhouse gas emissions by 2015. While the production industrial activity emissions per barrel of bitumen produced decreased 26% over the decade 1992–2002, total emissions from production activity were expected to increase due to higher production levels. As of 2006, to produce one barrel of oil from the oil sands released almost 75 kilograms (165 lb) of greenhouse gases with total emissions estimated to be 67 megatonnes (66,000,000 long tons; 74,000,000 short tons) per year by 2015. A study by IHS CERA found that fuels made from Canadian oil sands resulted in significantly lower greenhouse gas emissions than many commonly cited estimates. A 2012 study by Swart and Weaver estimated that if only the economically viable reserve of 170-billion-barrels (27×109 m3) oil sands was burnt, the global mean temperature would increase by 0.02 to 0.05 °C. If the entire oil-in-place of 1.8 trillion barrels were to be burnt, the predicted global mean temperature increase is 0.24 to 0.50 °C. Bergerson et al. found that while the WTW emissions can be higher than crude oil, the lower emitting oil sands cases can outperform higher emitting conventional crude cases.
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 July 2008, the Alberta government announced a C$2 billion fund to support sequestration projects in Alberta power plants and oil sands extraction and upgrading facilities.
Aquatic life deformities
There is conflicting research on the effects of the oil sands development on aquatic life. In 2007, Environment Canada completed a study that shows high deformity rates in fish embryos exposed to the oil sands. David W. 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. Scientists, local doctors, and residents supported a letter sent to the Prime Minister in September 2010 calling for an independent study of Lake Athabasca (which is downstream of the oil sands) to be initiated due to the rise of deformities and tumors found in fish caught there.
The bulk of the research that defends the oil sands development is done by the Regional Aquatics Monitoring Program (RAMP). RAMP studies show that deformity rates are normal compared to historical data and the deformity rates in rivers upstream of the oil sands. These results are dubious, however, as RAMP is funded largely by those energy companies with direct interests in the relevant environments. Further, unlike academia, where peer review happens on a per study basis, RAMP does a peer review of the entire organization only once every five years. Hence, RAMP cannot be said to meet widely accepted scientific standards.
Public health impacts
In 2007, it was suggested that wildlife has been negatively affected by the oil sands; for instance, moose were found in a 2006 study to have as high as 453 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. However, John O'Connor, the doctor who initially reported the higher cancer rates and linked them to the tar sands development, was subsequently investigated by the Alberta College of Physicians and Surgeons. The College later reported that the O'Connor's statements consisted of "mistruths, inaccuracies and unconfirmed information."
In 2010, 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 2011, 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.
In a report released in 2014, Alberta’s Chief Medical Officer of Health, Dr. James Talbot, stated that "There isn’t strong evidence for an association between any of these cancers and environmental exposure [to tar sands]." Rather, Talbot suggested that the cancer rates at Fort Chipewyan, which were slightly higher compared with the provincial average, were likely due to a combination of factors such as high rates of smoking, obesity, diabetes, and alcoholism as well as poor levels of vaccination."
Approximately 1.0–1.25 gigajoules (280–350 kWh) of energy is needed to extract a barrel of bitumen and upgrade it to synthetic crude. As of 2006, most of this is produced by burning natural gas. Since a barrel of oil equivalent is about 6.117 gigajoules (1,699 kWh), its EROEI is 5–6. That means this extracts about 5 or 6 times as much energy as is consumed. Energy efficiency is expected to improve to average of 900 cubic feet (25 m3) of natural gas or 0.945 gigajoules (262 kWh) of energy per barrel by 2015, giving an EROEI of about 6.5.
Alternatives to natural gas exist and are available in the oil sands area. Bitumen can itself be used as the fuel, consuming about 30–35% of the raw bitumen per produced unit of synthetic crude. Nexen's Long Lake project will use a proprietary deasphalting technology to upgrade the bitumen, using asphaltene residue fed to a gasifier whose syngas will be used by a cogeneration turbine and a hydrogen producing unit, providing all the energy needs of the project: steam, hydrogen, and electricity. Thus, it will produce syncrude without consuming natural gas, but the capital cost is very high.
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|Wikimedia Commons has media related to Oil sands.|
- Oil Sands Discovery Centre, Fort McMurray, Alberta, Canada
- Edward Burtynsky, An aerial look at the Alberta Tar Sands
- G.R. Gray, R. Luhning: Bitumen The Canadian Encyclopedia
- Jiri Rezac, Alberta Oilsands photo story and aerials
- Exploring the Alberta tar sands, Citizenshift, National Film Board of Canada
- Indigenous Groups Lead Struggle Against Canada’s Tar Sands – video report by Democracy Now!
- Extraction of vanadium from oil sands
- Hoffman, Carl (1 October 2009). "New Tech to Tap North America's Vast Oil Reserves". Popular Mechanics.
- Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions Congressional Research Service