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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 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 Canadian authorities as "petroleum that exists in the semi-solid or solid phase in natural deposits. Bitumen is a thick, sticky form of hydrocarbon, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons. 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.
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.
According to the WEC, natural bitumen is reported in 598 deposits in 23 countries, with the largest deposits in Canada, Kazakhstan, and Russia. Discovered original oil in place is 2,511.326 billion barrels (399.2689×109 m3) and total original oil in place is estimated 3,328.598 billion barrels (529.2048×109 m3). 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) are in Canada, 42.009 billion barrels (6.6789×109 m3) in Kazakhstan and 28.38 billion barrels (4.512×109 m3) in Russia.
Most of the oil sands of Canada are located in three major deposits in northern Alberta. These 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 hold proven reserves of 1.75 trillion barrels (280×109 m3) of bitumen in place. About 10% of this, 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. The Cold Lake deposits extend across the Alberta's eastern border into Saskatchewan. In addition to the Alberta oil sands, there are major oil sands deposits on Melville Island in the Canadian Arctic islands, which are unlikely to see commercial production in the foreseeable future. The largest bitumen deposit, containing about 80% of the Alberta total, and the only one suitable for surface mining, is the Athabasca oil sands along the Athabasca River. The mineable area (as defined by the Alberta government) includes 37 townships covering about 3,400 square kilometres (1,300 sq mi) near Fort McMurray. The smaller Cold Lake deposits are important because some of the oil is fluid enough to be extracted by conventional methods. All three Alberta areas are suitable for production using in-situ methods, such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD).
Several 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 400×106 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 the Utah counties of Carbon, Garfield, Grand, Uintah, and Wayne. 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 than 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.
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).
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.
|This section may stray from the topic of the article into the topic of another article, Athabasca Oil Sands. (November 2012)|
Since Great Canadian Oil Sands (now Suncor) started operation of its mine in 1967, bitumen has been extracted on a commercial scale from the Athabasca Oil Sands by surface mining. In the Athabasca sands there are very large amounts of bitumen covered by little overburden, making surface mining the most efficient method of extracting it. The overburden consists of water-laden muskeg (peat bog) over top of clay and barren sand. The oil sands themselves are typically 40 to 60 metres (130 to 200 ft) deep, sitting on top of flat limestone rock. Originally, the sands were mined with draglines and bucket-wheel excavators and moved to the processing plants by conveyor belts. In recent years, companies such as Syncrude and Suncor have switched to much cheaper shovel-and-truck operations using the biggest power shovels (100 or more tons) and dump trucks (400 tons) in the world. This has held production costs to around US$27 per barrel of synthetic crude oil despite rising energy and labour costs.
After excavation, hot water and caustic soda (NaOH) 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. Provided that the water chemistry is appropriate to allow bitumen to separate from sand and clay, the combination of hot water and agitation releases bitumen from the oil sand, and allows small air bubbles to attach to the bitumen droplets. The bitumen froth floats to the top of separation vessels, and is further treated to remove residual water and fine solids.
About two tons of oil sands are required to produce one barrel (roughly 1/8 of a ton) of oil. Originally, roughly 75% of the bitumen was recovered from the sand. However, recent enhancements to this method include Tailings Oil Recovery (TOR) units which recover oil from the tailings, Diluent Recovery Units to recover naptha from the froth, Inclined Plate Settlers (IPS) and disc centrifuges. These allow the extraction plants to recover well over 90% of the bitumen in the sand. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.
Alberta Taciuk Process technology extracts bitumen from oil sands through a dry-retorting. During this process, oil sand is moved through a rotating drum, cracking the bitumen with heat and producing lighter hydrocarbons. Although tested, this technology is not in commercial use yet.
Four oil sands mines are currently in operation and two more (Jackpine and Kearl) are in the initial stages of development. The original Suncor mine opened in 1967, while 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 Project in 2009. New mines under construction or undergoing approval include Shell Canada's, 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.
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 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.
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. 
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.
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:
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)|
|This section's factual accuracy may be compromised due to out-of-date information. (April 2013)|
As of 2007, crude oil prices were significantly in excess of the average cost of production, which was about $28 per barrel of bitumen. However, bitumen production costs are rising rapidly, with production cost increases of 55% from 2005 to 2007, due to shortages of labor and materials.
In mid-2007, Royal Dutch Shell announced that in 2006 its Canadian oil sands unit made an after tax profit of $21.75 per barrel, nearly double its worldwide profit of $12.41 per barrel on conventional crude oil.
The minority Conservative government of Canada, pressured to do more on the environment, announced in its 2007 budget that it would phase out some oil sands tax incentives over coming years. The provision allowing accelerated write-off of oil sands investments will be phased out gradually, so projects that had relied on them can proceed. For new projects the provision will be phased out between 2011 and 2015. However, as of the 2012 fall budget, these accelerated write-offs were still in place.
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. 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.
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.
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 2006–2007, about 420 square kilometres (160 sq mi) of land in the oil sands region have been disturbed, and 65 square kilometres (25 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. Despite recycling, almost all of it ends up in tailings ponds. As of 2007[update], tailing ponds in Canada covered an area of approximately 50 square kilometres (19 sq mi). 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. 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 recent breakthrough in analysis has begun to reveal what is in the oil sands-produced waters.
In October 2009, Suncor announced it was seeking government approval for a new process to recover tailings called Tailings Reduction Operations, which accelerates the settling of fine clay, sand, water, and residual bitumen in ponds after oil sands extraction. The technology involves dredging mature tailings from a pond bottom, mixing the suspension with a polymer flocculant, and spreading the sludge-like mixture over a "beach" with a shallow grade. According to the company, the process could reduce the time for water reclamation from tailings to weeks rather than years, with the recovered water being recycled into the oil sands plant. In addition to reducing the number of tailing ponds, Suncor claims that the process could reduce 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.
In January 2013, scientists from Queen's University published a report analyzing lake sediments in the Athabasca region over the past fifty years. They found that levels of polycyclic aromatic hydrocarbons (PAHs) had increased as much as 23-fold since bitumen extraction began in the 1960s. Levels of carcinogenic, mutagenic, and teratogenic PAHs were substantially higher than guidelines for lake sedimentation set by the Canadian Council of Ministers of the Environment in 1999. The team discovered that the contamination spread farther than previously thought.
The Pembina Institute suggested that the huge investments by many companies in Canadian oil sands leading to increased production results in excess bitumen with no place to store it. It added that by 2022 a month’s output of waste-water could result in a toxic reservoir the size of New York City’s Central Park and 11 feet deep.
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-barrel (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.
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.
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. 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. It has also been suggested that other 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).
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 (263 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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