Tar sands Totally Explained

Tar sands is a common name of what are more properly called bituminous sands, but also commonly referred to as oil sands or (in Venezuela) extra-heavy oil. They are a mixture of sand or clay, water, and extremely heavy crude oil. The use of the word tar to describe these deposits is a misnomer, since tar is a man-made substance produced by the destructive distillation of organic material. Although it appears similar, the material in tar sands is a naturally-occurring, extremely heavy form of crude oil in which the lighter fractions of the oil have been lost, and the remaining fractions have been partially biodegraded by bacteria. As a result, the term "oil sands" is technically more accurate.
   Conventional crude oil is easily extracted from the ground by drilling wells into the formations, into which light or medium density oil flows under natural reservoir pressures, but tar sand deposits must be strip mined or made to flow into producing wells by in situ techniques which reduce the oils viscosity using steam and/or solvents. These processes use a great deal of water and require large amounts of energy.
   The heavy crude oil or crude bitumen extracted from these deposits is a viscous, solid or semisolid form of oil that doesn't easily flow at normal ambient temperatures and pressures, making it difficult and expensive to process into gasoline, diesel fuel, and other products. Despite the difficulty and cost, oil sands are now being mined on a vast scale to extract the oil, which is then converted into synthetic oil by oil upgraders, or refined directly into petroleum products by specialized refineries.
   Many countries in the world have large deposits of oil sands, including the United States, Russia, and various countries in the Middle East. However, the world's largest deposits occur in two countries: Canada and Venezuela, both of which have oil sands reserves approximately equal to the world's total reserves of conventional crude oil. As a result of the development of these reserves, most Canadian oil production in the 21st century is from oil sands or heavy oil deposits, and Canada is now the largest single supplier of oil and refined products to the United States. Venezuelan production is also very large, but due to political problems its oil production has been declining since the start of the 21st century.

As oil source, by location

Oil sands, also known as tar sands, were used by the ancient Mesopotamians and Canadian First Nations, among others.
   Oil sand deposits are found in over 70 countries worldwide, but three quarters of the world's reserves are found in only two countries: Venezuela and Canada.
   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 tar sands from the free-flowing hydrocarbon mixtures known as crude oil traditionally produced from oil wells. See Bituminous rocks.
   Oil sands may represent as much as 2/3 of the world's total petroleum resource, with at least 1.7 trillion barrels (270 km³) in the Canadian Athabasca Oil Sands and perhaps 1.8 trillion barrels (280 km³) in the Venezuelan Orinoco tar sands, compared to 1.75 trillion barrels (278 km³) of conventional oil worldwide, most of it in Saudi Arabia and other Middle-Eastern countries. Between them, the Canadian and Venezuelan deposits contain about 3.6 trillion barrels (422 km³) of oil in place. This is only the remnant of vast petroleum deposits which once totaled as much as 18 trillion barrels (2,100 km³), most of which has escaped or been destroyed by bacteria over the eons. See also below notes about limits to production capacity.

Canada

Canada is the largest supplier of oil to the U.S., with over a million barrels per day coming from tar sands.
   Most of the oil sands of Canada are located in three major deposits in northern Alberta. The three deposits 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 kilometers (54,000 square miles), an area larger than Florida, and hold at least 175 billion barrels (175×10⁹ bbl) or 28 billion cubic metres (28×10⁹ m³) of recoverable crude bitumen, which amounts to three-quarters of North American petroleum reserves. In addition to the Alberta deposits, there are major oil sands deposits on Melville Island in the Canadian Arctic islands but they're unlikely to see commercial production in the foreseable future.
   The Alberta deposits contain at least 85% of the world's total bitumen reserves but are so concentrated as to be the only such deposits that are economically recoverable for conversion to oil. 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 covers 37 contiguous townships (about 3400 square kilometres or ) north of the city of Fort McMurray. The smaller Cold Lake deposits are important because some of the oil is fluid enough to be produced by conventional production 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 Canadian 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 of 2004-2006, there were several dozen companies planning nearly 100 oil sands mines and in-situ 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 for tar sands of $28 per barrel all of these projects appear likely to be profitable. However, tar sands 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'll 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 counted on them can proceed. Existing developments will get the allowance; for new projects the provision will be phased out between 2011 and 2015.
   However, with oil prices setting new highs in 2007, tax incentives were no longer be 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.

Venezuela

Located in eastern Venezuela, north of the Orinoco River, the Orinoco oil belt vies with the Canadian tar sand for largest known accumulation of bitumen in the world. Venezuela prefers to call its tar sands "extra heavy oil", and although the distinction is somewhat academic, the extra heavy crude oil deposit of the Orinoco Belt represent nearly 90% of the known global reserves of extra heavy crude oil.
   Bitumen and extra-heavy oil are closely related types of petroleum, differing only in the degree by which they've 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's easier to produce, it's still too heavy to transport by pipeline or process in normal refineries. Lacking access to first-world capital and technological prowess, Venezuela hasn't been able to design and build the kind of bitumen upgraders and heavy oil refineries that Canada has. However, 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 (which is a modern, politically stable democracy), 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 tar sands crude production, which sometimes wasn't counted in its total, has increased from 125,000 bpd to 500,000 bpd between 2001 and 2006 (Venezuela's figures; IAEA says 300,000 bpd).

USA

Utah's Tar Sand Resource consists of eight major deposits with a combined shallow oil resource of 32.0 billion barrels of oil. The largest of these deposits, the Tar Sand Triangle as it's known, covers an area of and is located in Wayne and Garfield Counties, between the Dirty Devil and Colorado Rivers.
The Utah Tar 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 reported 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 of these methods 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 due to inefficient processing technologies.

Extraction process

Surface Mining

For the last 38 years or so, bitumen has been extracted from the Athabasca Oil Sands by surface mining. In these tar sands there are large deposits of bitumen with little overburden, making 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 tar sands themselves are typically 40 to 60 metres 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. However, 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 reduced production costs to around $15 per barrel of synthetic crude oil.
   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's 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 tar 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 tar 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 tar 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 around 80% of the Alberta tar sands and nearly all of Venezuelan sands are too far below the surface to use the open-pit mining technique used by the large producers. A number of in-situ techniques have been developed to extract this deeper oil.

Cold Flow

In this technique, the oil is simply pumped out of the sands, often using specialized pumps called progressive cavity pumps. This only works well in areas where the oil is fluid enough to pump. 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, Alberta 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 how thick the roads were becoming, so in recent years disposing of sand in underground salt caverns has become common.

Cyclic Steam Stimulation (CSS)

See also Steam Injection 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 then 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 an Alberta government research center 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 tar 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's pumped to the surface. SAGD has proved to be a major breakthrough in production technology since it's cheaper than CSS, allows very high oil production rates, and recovers up to 60% of the oil in place. Because of its very favorable economics and applicability to a vast area of tar 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 tar sands areas and in Wyoming. Examples include Japan Canada Oil Sands Ltd's (JACOS) Hangingstone

project, Suncor’s Firebag

project, Nexen's Long Lake

project, Petro-Canada's MacKay River

project, Husky Energy's Tucker Lake and Sunrise

projects, Shell Canada's Peace River project, Encana's Foster Creek

development, ConocoPhillips Surmont

project, and 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 from underground within the tar sands deposit, thus also reducing energy requirements compared to traditional SAGD. This particular technology application is in its testing phase and has stranded oil and other carbonate applications as well.

Vapor Extraction Process (VAPEX)

VAPEX is similar to SAGD but instead of steam, hydrocarbon solvents are injected into the upper well to dilute the bitumen and allow it to flow into the lower well. It has the advantage of much better energy efficiency than steam injection and it does some partial upgrading of bitumen to oil right in the formation. It is very new but 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 drives the lighter components into the production well, where it's pumped out. In addition, the heat from the fire 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.

Environmental effects

Tar sands development has both indirect and direct effect on local and planetary ecosystems. The indirect effects are common to any fossil fuel producer, in that the products sold are mostly burned and the combustion products released into the atmosphere.

Local direct effects

In Alberta, the strip mining of tar sands modifies the natural landscape of boreal forest and bogs, turning it into grazing and park land. As a condition of licensing, projects are required to implement a reclamation plan . The mining industry plans that the boreal forest will eventually colonize the reclaimed lands. In 2003 (the most recent data available), about 330 square kilometres had been disturbed, and 56 km² of this were being reclaimed. No land had been certified as reclaimed by 2003, but only one application for certification had been received. .
Between 2 to 4.5 volume units of water are used to produce each volume unit of synthetic crude oil (SCO) in an ex-situ mining operation. Despite recycling, almost all of it ends up in tailings ponds. In SAGD operations, 90 to 95 percent of the water is recycled and only about 0.2 volume units of water is used per volume unit of bitumen produced. Future environmental effects could include pipeline developments, and increased oil tanker traffic in northern coastal waters of British Columbia.

Global direct effects

Large amounts of energy are needed to extract and upgrade the bitumen to synthetic crude. At this point in time, most of this is produced by burning natural gas which is widely available in the tar sands area. Approximately 1.0 to 1.25 gigajoules of natural gas are needed per barrel of bitumen extracted. Since a barrel of oil equivalent is about 6.1 gigajoules, this produces about 5 or 6 times as much energy as is consumed. Energy efficiency is expected to improve to 0.7 gigajoules of energy per barrel by 2015, giving an energy multiplier of about 9:1. However, since natural gas production in Alberta peaked in 2001 and has been static ever since, it's likely tar sands requirements will be met by cutting back natural gas exports to the U.S.
   Alternatives to natural gas exist and are available in the tar sands area. Bitumen can itself be used as the fuel, consuming about 30-35% of the raw bitumen per produced unit of synthetic crude. 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 didn't appear to be economic as of 2005. Nonetheless, Energy Alberta Corporation announced in 2007 that they'd 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 ACR-1000 plant go online in 2017, producing 2.2 gigawatt (electric).
   Future plants are expected to sequester the combustion products, but for now most ex-situ CO₂ is released to the atmosphere.
   A major Canadian initiative called the Integrated CO2 Network (ICO2N) is a proposed system for the capture, transport and storage of carbon dioxide (CO₂). ICO2N members represent a group of industry participants providing a framework for carbon capture and storage development in Canada.

Environmental Advocacy

Any large resource project such as these attracts a large advocacy effort on environmental issues from global organizations such as the Greenpeace Campaign to Stop the Tar Sands

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