Oil sands, tar sands, or extra heavy oil is a type of bitumen deposit. Tar sands is a colloquialism for what are technically described as bituminous sands, and commonly known as oil sands or in Venezuela, extra heavy oil. The sands are naturally occurring mixtures of sand or clay, water and an extremely dense and viscous form of petroleum called bitumen. They are found in large amounts in many countries throughout the world, but are found in extremely large quantities in Canada and Venezuela.
They have only recently been considered to be part of the world's oil reserves, as higher oil prices and new technology enable them to be profitably extracted and upgraded to usable products. Oil sand is often referred to as non-conventional oil or crude bitumen, in order to distinguish the bitumen and synthetic oil extracted from oil sands from the free-flowing hydrocarbon mixtures known as crude oil traditionally produced from oil wells. See Bituminous rocks.
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 man-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 Since then, coal gas has almost completely been replaced by natural gas as a fuel, and coal tar as a material for paving roads has been replaced by the petroleum product asphalt.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 tar, and oil sands (or oilsands) is more commonly used in the producing areas than tar sands because synthetic oil is what is manufactured from the bitumen.
Oil sands may represent as much as two-thirds of the world's total petroleum resource, with at least in the Canadian Athabasca Oil Sands and perhaps of extra heavy crude in the Venezuelan Orinoco oil sands . Between them, the Canadian and Venezuelan deposits contain about of oil in place, compared to of conventional oil worldwide, most of it in Saudi Arabia and other Middle-Eastern countries.
At the present time, only Canada has a large-scale commercial oil sands industry, though a small amount of oil from oil sands is produced in Venezuela. Both Canada and Venezuela are major suppliers of oil and refined products to the United States. Oil sands now are the source of almost half of Canada's oil production, and output is expanding rapidly, while Venezuelan production has been declining in recent years. Currently, oil is not produced from oil sands on a significant level in the United States.
Canada is the largest supplier of crude oil and refined products to the United States, supplying about 20% of total U.S. imports, and exports more oil and products to the U.S. than it consumes itself. In 2006, bitumen production averaged through 81 oil sands projects, representing 47% of total Canadian petroleum production. This proportion is expected to increase in coming decades as bitumen production grows while conventional oil production declines.
Most of the 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 - an area larger than England - and hold proven reserves of of bitumen in place. About ten percent of this, or , 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 three-quarters of total North American petroleum reserves. In addition to the Alberta deposits, 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 Alberta deposits contain at least 85% of the world's total reserves of natural bitumen but are concentrated enough to be the only deposits that are economically recoverable for conversion to oil at current prices. The largest bitumen deposit, containing about 80% of the 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 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).
The Alberta oil sands have been in commercial production since the original Great Canadian Oil Sands (now Suncor) mine began operation in 1967. 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. began operation in 2003. Petro Canada is also developing its $33 billion Fort Hills Project, in partnership with UTS Energy Corporation and Teck Cominco. If approved in 2008, Fort Hills Oilsands upgraders are slated to begin output in 2012.
With the development of new in-situ production techniques such as steam assisted gravity drainage, and with the Oil price increases since 2003, there were several dozen companies planning nearly 100 oil sands projects in Canada, totaling nearly $100 billion in capital investment. With 2007 crude oil prices significantly in excess of the current average cost of production of $28 per barrel of bitumen, all of these projects appear likely to be profitable. However, bitumen production costs are rising rapidly, with production cost increases of 55% since 2005, due to shortages of labor and materials.
The minority Conservative government of Canada, pressured to do more on the environment, announced in its 2007 budget that it will 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.
With oil prices setting new highs in 2007, tax incentives were no longer necessary to encourage oil sands projects in Canada. In July Royal Dutch Shell released its 2006 annual report and announced that 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. A few days later Shell announced it filed for regulatory approval to build a $27 billion oil sands refinery in Alberta, one of $38 billion in new oil sands projects announced that week.
Bitumen and extra-heavy oil are closely related types of petroleum, differing only in the degree by which they have been degraded from the original crude oil by bacteria and erosion. The Venezuelan deposits are less degraded than the Canadian deposits and are at a higher temperature (over 50 degrees Celsius versus freezing for northern Canada), making them easier to extract by conventional techniques.
Although it is easier to produce, it is still too heavy to transport by pipeline or process in normal refineries. Lacking access to first-world capital and technological prowess, Venezuela has not been able to design and build the kind of bitumen upgraders and heavy oil refineries that Canada has. In the early 1980’s the state oil company, PDVSA, developed a method of using the extra-heavy oil resources by emulsifying it with water (70% extra-heavy oil, 30% water) to allow it to flow in pipelines. The resulting product, called Orimulsion, can be burned in boilers as a replacement for coal and heavy fuel oil with only minor modifications. Unfortunately, the fuel’s high sulphur content and emission of particulates make it difficult to meet increasingly strict international environmental regulations.
Further development of the Venezuelan resources has been curtailed by political unrest. Venezuela is much less politically stable than a country such as Canada, and a strike by employees of the state oil company was followed by the dismissal of most of its staff. As tensions resolved, strike leaders pointed to the reduction in Venezuela's domestic crude output as an argument that Venezuela's oil production had fallen. However, Venezuela's oil sands crude production, which sometimes wasn't counted in its total, has increased from to between 2001 and 2006 (Venezuela's figures; IAEA says 300,000 bpd).
The Utah Oil Sands have been quarried since the early 1900s primarily for road paving material. Several pilot extraction tests have been operated by oil companies at various times since 1972. The most recent pilot tests at Asphalt Ridge were conducted by the Laramie Energy Technology Center of the U.S. Department of Energy. In 1975 through 1978 they completed experimental testing of a combined reverse-forward combustion and steam injection scheme. It was concluded that additional testing was necessary.
Efforts to develop Utah's heavy oil primarily ended with the sharp drop in oil prices in the mid-1980s and the high costs of extraction.
Currently, oil is not produced from oil sands on a significant commercial level in the United States, although the U.S. imports twenty percent of its oil and refined products from Canada, and over forty percent of Canadian oil production is from oil sands. Section 526 of the Energy Independence And Security Act prohibits United States government agencies from buying oil produced by processes that produce more greenhouse gas emissions than would traditional petroleum including oil sands. In addition to being much smaller than the Canadian deposits, U.S oil sands are hydrocarbon wetted, whereas Canadian sands are water wetted. As a result of this difference, extraction techniques for the oil sands in Utah will be different than for those in Canada. A considerable amount of research must be done before a commercially viable production technique can be developed for the U.S. oil sands. Of special concern in the relatively arid western United States is the large amount of water required for oil sands processing.
Several other countries hold oil sands deposits which are smaller by orders of magnitude. In Congo the Italian oil company Eni have announced in May 2008 a project to develop the small oil sands deposit in order to produce 40 000 barrels per day in 2014. Reserves are estimated between 0.5 and 2.5 billion barrels depending of probability level.
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 .
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. Bitumen is much thicker than traditional crude oil, so 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.
The bitumen is then transported and eventually upgraded into synthetic crude oil. About two tons of oil sands are required to produce one barrel (roughly 1/8 of a ton) of oil. Roughly 75% of the bitumen can be recovered from sand. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.
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 over 90% of the bitumen in the sand.
Three oil sands mines are currently in operation and a fourth is in the initial stages of development. The original Suncor mine opened in 1967, while the Syncrude mine started in 1978 and Shell Canada opened its Muskeg River mine (Albian Sands) in 2003. New mines under construction or undergoing approval include Canadian Natural Resources Ltd Horizon Project (in the initial stages of development), Shell Canada's Jackpine mine, Imperial Oil's Kearl Oil Sands Project, Synenco Energy's Northern Lights mine, and Petro-Canada's Fort Hills mine
It is estimated that approximately 80% of the Alberta oil sands and nearly all of Venezuelan sands are too far below the surface to use open-pit mining. Several in-situ techniques have been developed to extract this oil.
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.
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.
Advocates of this method of extraction state that it uses less freshwater, produces 50% less greenhouse gases, and has a smaller footprint than other production techniques .
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 sulphur dioxide—used to calculate the Air Quality Index (note that carbon dioxide is not included in this measure). Air monitoring has shown significant increases in exceedances of hydrogen sulfide (H2S) both in the Fort McMurray area and near the oil sands upgraders.
Hydrogen sulfide (or hydrogen sulphide) is the chemical compound with the formula H2S. This colorless, toxic and flammable gas is responsible for the foul odour of rotten eggs. Hydrogen sulfide gas occurs naturally in crude petroleum, natural gas, volcanic gases and hot springs. It also can result from bacterial breakdown of organic matter and be produced by human and animal wastes.
In 2007, the Alberta government issued an Environmental Protection Order to Suncor Energy Inc. The order comes in response to numerous occasions when ground level concentration (GLC) for H2S exceeded acceptable standards . Environmental Protection Orders are issued under the authority of Alberta’s Environmental Protection and Enhancement Act. Alberta Environment can issue Environmental Protection Orders to remedy environmental problems where there has been a release of a substance that has caused or may cause an adverse effect to the environment.
Syncrude say that at their Base Mine site, land reclamation now exceeds disturbance as that mine reaches the end of its production life. In 2006, Syncrude spent more than $30 million on reclamation activities. To date, they have reclaimed over 46 km² and planted around 4.5 million tree seedlings.
The Athabasca River is the 9th longest river in Canada running 1,231 kilometres from the Athabasca Glacier in west-central Alberta to Lake Athabasca in northeastern Alberta . The average annual flow just downstream of Fort McMurray is 633 cubic metres per second with its highest daily average measuring 1200 cubic metres per second .
Current water license allocations totals about 1.8 per cent of the Athabasca river flow. Actual use in 2006 was about 0.4 per cent. In addition, the Alberta government sets strict limits on how much water oil sands companies can remove from the Athabasca River. According to the Water Management Framework for the Lower Athabasca River, during periods of low river flow water consumption from the Athabasca River is limited to 1.3 per cent of annual average flow. The province of Alberta is also looking into cooperative withdrawal agreements between oil sands operators.
Future environmental effects could include pipeline developments, and increased oil tanker traffic in northern coastal waters of British Columbia.
While the emissions intensity of producing oil sands has decreased substantially, i.e., 26% over the past decade, total emissions are expected to increase due to higher production levels. Currently, to produce one barrel of oil from the oil sands releases almost 75 kg of GHG with total emissions estimated to be 67 megatonne (Mt) per year by 2015.
In January 2008, the Alberta government released Alberta’s 2008 Climate Change Strategy Alberta’s emissions are projected to grow to 400 megatonnes (Mt) by 2050, largely due to forecast growth in the oil sands sector. The new plan will cut the projected 400 Mt in half by 2050, with a 139 Mt reduction coming from carbon capture and storage—the bulk of those reductions (100 Mt) will come from activities related to oil sands production .
A major Canadian initiative called the Integrated CO2 Network (ICO2N) is a proposed system for the capture, transport and storage of CO2. The members represent a group of industry participants providing a framework for carbon capture and storage development in Canada. On March 10, 2008 the Canadian Environment Ministry announced new controls requiring carbon sequestration from 2010, including criminal sanctions for violators.
Oil sands projects in Canada could face tougher regulatory scrutiny after a federal court ruling on March 6, 2008, which found the approval of Imperial Oil Ltd.'s $8-billion oil sands mine insufficient on climate change and greenhouse gas emissions. Numerous large proposals are in the regulatory system right now, including major mines by Total SA of France, by Anglo-Dutch Royal Dutch Shell and by Petro-Canada, as well as steam-injection projects by EnCana of Calgary.
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 (in construction) will use a proprietary desasphalting technology to upgrade the bitumen, and asphalt will be fed to a gasifier whose syngas will be used by a cogeneration turbine and an hydrogen producting unit, provinding 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.
Coal is widely available in Alberta and is inexpensive, but produces large amounts of greenhouse gases. Nuclear power is another option which has been proposed, but did not appear to be economic as of 2005. In early 2007 the Canadian House of Commons Standing Committee on Natural Resources considered that the use of nuclear power to process oil sands could reduce CO2 emissions and help Canada meet its Kyoto commitments, as it would require nearly 12 GW to meet production growth to 2015, but the implications of building reactors in northern Alberta were not yet well understood. Energy Alberta Corporation announced in 2007 that they had filed application for a license to build a new nuclear plant at Lac Cardinal, 30 km west of the town of Peace River. The application would see an initial twin AECL Advanced CANDU Reactor ACR-1000 plant go online in 2017, producing 2.2 GW (electric). At 6.117 GJ/barrel, this is equivalent to conserving . On November 30 2007 Bruce Power, which owns eight CANDU reactors in Ontario, signed a letter of intent to acquire Energy Alberta and take over the project.