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Oil from Tar Sands – Production, Applications - Reference & Resources

 Nature gave us oil from algae; perhaps we should try Nature’s way again

Tar sands – content derived from Wikipedia

Tar sands, also referred to as oil sands or bituminous sands, are a combination of clay, sand, water, and bitumen. On average bitumen contains 83.2% carbon, 10.4% hydrogen, 4.8% sulphur, 0.94% oxygen, and 0.36% nitrogen. 

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Technically speaking, the bitumen is neither oil nor tar, but a semisolid, degraded form of oil that does not flow at normal temperatures and pressures, making it difficult and expensive to extract. Tar sands are mined to extract the oil-like bitumen, which is then converted into synthetic crude oil or refined directly into petroleum products by specialized refineries. Most refineries can only handle about 10-15 per cent of their input coming from these heavy oil sources.

Crude oil is extracted by drilling wells, but oil sand deposits are strip mined or made to flow into producing wells by in situ techniques which reduce the bitumen's viscosity with steam and/or solvents. This latter process uses a great deal of water, which is challenging as the largest deposits are in cold desert areas where, for much of the year, surface water is only present in the form of ice.

As oil source, by location

Tar sands were used by the ancient Mesopotamians and Canadian First Nations.

They have only recently been considered to be part of the world's oil reserves, as they are becoming extractable at current prices with current technology.

 Oil sand is often referred to as non-conventional oil, 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.

Tar sands may represent as much as 2/3 of the world's total petroleum resource, with at least 1.7 trillion barrels (1.7×1012 bbl or 270×109 m³) in the Canadian Athabasca Tar Sands and perhaps 1.8 trillion barrels (1.8×1012 bbl or 280×109 m³) in the Venezuelan Orinoco tar sands [citation needed], compared to 1.75 trillion barrels (1.75×1012 bbl or 278×109 m³) 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 of oil in place. This is only the remnant of vast petroleum deposits which once totaled as much as 18 trillion barrels, most of which has escaped or been destroyed by bacteria over the eons. See also below notes about limits to production capacity.

Tar sand deposits are found in over 70 countries throughout the world, but three quarters of the world's reserves are in two regions: Venezuela and the Athabasca located in northern Alberta and Saskatchewan, Canada.

Canada

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 are 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 1300 square miles) 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. UTS Energy Corporation is also developing its Fort Hills Project, in conjuction with Petro Canada and Teck Cominco.

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 2006 crude oil prices significantly in excess of the current cost of production, all of these projects appear likely to be profitable.

Early optimism fading?

These development plans may be overly optimistic. Low production prices of under $25/barrel are enjoyed only by amortized plants such as the Syncrude operation. New sites such as the The Canadian Natural Resources (CNRL) Horizon Project, typically require at least $30/barrel to be profitable.

There are also efforts, led by prominent former Alberta politician Preston Manning, to charge for the access to water this industry requires. There are health and environment impacts, including greenhouse gas emissions. See below under environmental and health impact. The full cost accounting which Manning advocates could add as much as US$5-10 per barrel to production costs.

Expanding production capacity is also limited by several factors. Any expansion of capacity carries risks: infrastructure is expensive, and oil prices are unpredictable.

In early 2006 US and Canadian executives met in Houston, Texas to discuss the future of the industry. They planned for a five-fold increase in production, in order to wean the US off middle-eastern imports by 2015.

Venezuela

Located in eastern Venezuela, north of the Orinoco River, the Orinoco oil belt vies with the Canadian oil 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 oil.

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. 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 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 tar sands crude production, which sometimes isn'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 is known, covers an area of 148,000 acres 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

Raw bitumen is separated from the sand in giant separation cells.

Surface Mining

For the last 38 years or so, bitumen has been extracted from the Athabasca Oil Sands by surface mining. In these oil 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 oil 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 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 is agitated and the oil skimmed from the top. Oil Sands Discovery Centre 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.

 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 around 80% of the Alberta oil 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. http://www.oilsandsdiscovery.com/oil_sands_story/insitu.html

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 and the southern part of the Cold Lake, Alberta 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)

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. 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 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 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 very favorable economics 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 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,Japan Canada Oil Sands Ltd's (JACOS) Hangingstone project and Derek Oil & Gas`s LAK Ranch projekt. Alberta's OSUM Corp has combined proven underground mining technology with SAGD to enable higher recovery rates by running wells from underground within the oil 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 is 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 impacts

Tar sands development has a direct impact on local and planetary ecosystems.

In Alberta, the strip mining form of oil extraction destroys the boreal forest, the bogs, the rivers as well as the natural landscape. The mining industry believes that the boreal forest will eventually colonize the reclaimed lands, yet 30 years after the opening of the first open pit mine near Fort McMurray, Alberta, no land is considered by the Alberta Government as having been reclaimed.

For every barrel of synthetic oil produced in Alberta, 80 kg of greenhouse gases are released into the atmosphere. About 5-10% of the two to four barrels of water used for processing is considered as wastewater.

Greenhouse gas emissions

In ratifying the Kyoto Protocol, Canada agreed to reduce, by 2012, its greenhouse gas emissions by 6% with respect to the reference year (1990). In 2002, Canada's total greenhouse gas emissions had increased by 24% since 1990. The tar sands projects have been blamed for this increase by certain environmentalists, but no direct proof has been given.

Health impacts

This article or section may use words or ideas of other works in its text without citing sources. Using citations to support claims outside the realm of elementary knowledge helps guard against copyright violations and factual inaccuracies. Please improve the article or discuss this issue on the talk page. Help on using footnotes is available. This article has been tagged since January 2007.

The release of vast amounts of contaminated water into the environment of the Athabasca River has resulted in reports of more frequent cancers downstream. These are blamed on the Tar Sands developments, and would be consistent with the known impacts of petroleum development.

http://en.wikipedia.org/wiki/Tar_sands

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