Unconventional oil reserves

What are oil sands
Oil sands, tar sands or, more technically, bituminous sands, are a type of unconventional petroleum deposit.

Oil sands are either loose sands or partially consolidated sandstone containing a naturally occurring mixture of sand, clay, and water, saturated with a dense and extremely viscous form of petroleum technically referred to as bitumen (or colloquially as tar due to its superficially similar appearance). 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 been discovered. Proven reserves of bitumen contain approximately 100 billion barrels, and total natural bitumen reserves are estimated at 249.67 Gbbl (39.694×109 m3) worldwide, of which 176.8 Gbbl (28.11×109 m3), or 70.8%, are in Alberta, 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 the National Energy Board of Canada as "a highly viscous mixture of hydrocarbons heavier than pentanes which, in its natural state, is not usually recoverable at a commercial rate through a well because it is too thick to flow." Crude bitumen is a thick, sticky form of crude oil, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons such as light crude oil or natural-gas condensate. At room temperature, it is much like cold molasses. The World Energy Council (WEC) defines natural bitumen as "oil having a viscosity greater than 10,000 centipoise under reservoir conditions and an API gravity of less than 10° API". The Orinoco Belt in Venezuela is sometimes described as oil sands, but these deposits are non-bituminous, falling instead into the category of heavy or extra-heavy oil due to their lower viscosity. Natural bitumen and extra-heavy oil differ in the degree by which they have been degraded from the original conventional oils by bacteria. According to the WEC, extra-heavy oil has "a gravity of less than 10° API and a reservoir viscosity of no more than 10,000 centipoise".

According to the study ordered by the Government of Alberta and conducted by Jacobs Engineering Group, emissions from oil-sand crude are 12% higher than from conventional oil.

What are oil shales


Oil shale, also known as kerogen shale, is an organic-rich fine-grained sedimentary rock containing kerogen (a solid mixture of organic chemical compounds) from which liquid hydrocarbons called shale oil (not to be confused with tight oil—crude oil occurring naturally in shales) can be produced. Shale oil is a substitute for conventional crude oil; however, extracting shale oil from oil shale is more costly than the production of conventional crude oil both financially and in terms of its environmental impact. Deposits of oil shale occur around the world, including major deposits in the United States. Estimates of global deposits range from 4.8 to 5 trillion barrels (760×109 to 790×109 m3) of oil in place.

Heating oil shale to a sufficiently high temperature causes the chemical process of pyrolysis to yield a vapor. Upon cooling the vapor, the liquid shale oil—an unconventional oil—is separated from combustible oil-shale gas (the term shale gas can also refer to gas occurring naturally in shales). Oil shale can also be burned directly in furnaces as a low-grade fuel for power generation and district heating or used as a raw material in chemical and construction-materials processing.

Oil shale gains attention as a potential abundant source of oil whenever the price of crude oil rises. At the same time, oil-shale mining and processing raise a number of environmental concerns, such as land use, waste disposal, water use, waste-water management, greenhouse-gas emissions and air pollution. Estonia and China have well-established oil shale industries, and Brazil, Germany, and Russia also utilize oil shale.

General composition of oil shales constitutes inorganic matrix, bitumens, and kerogen. Oil shales differ from oil-bearing shales, shale deposits that contain petroleum (tight oil) that is sometimes produced from drilled wells. Examples of oil-bearing shales are the Bakken Formation, Pierre Shale, Niobrara Formation, and Eagle Ford Formation.

Oil shale, an organic-rich sedimentary rock, belongs to the group of sapropel fuels. It does not have a definite geological definition nor a specific chemical formula, and its seams do not always have discrete boundaries. Oil shales vary considerably in their mineral content, chemical composition, age, type of kerogen, and depositional history and not all oil shales would necessarily be classified as shales in the strict sense. According to the petrologist Adrian C. Hutton of the University of Wollongong, oil shales are not "geological nor geochemically distinctive rock but rather 'economic' term." Their common feature is low solubility in low-boiling organic solvents and generation of liquid organic products on thermal decomposition.

Oil shale differs from bitumen-impregnated rocks (oil sands and petroleum reservoir rocks), humic coals and carbonaceous shale. While oil sands do originate from the biodegradation of oil, heat and pressure have not (yet) transformed the kerogen in oil shale into petroleum, that means that its maturation does not exceed early mesocatagenetic.

General composition of oil shales constitutes inorganic matrix, bitumens, and kerogen. While the bitumen portion of oil shales is soluble in carbon disulfide, kerogen portion is insoluble in carbon disulfide and can contain iron, vanadium, nickel, molybdenum, and uranium. Oil shale contains a lower percentage of organic matter than coal. In commercial grades of oil shale the ratio of organic matter to mineral matter lies approximately between 0.75:5 and 1.5:5. At the same time, the organic matter in oil shale has an atomic ratio of hydrogen to carbon (H/C) approximately 1.2 to 1.8 times lower than for crude oil and about 1.5 to 3 times higher than for coals. The organic components of oil shale derive from a variety of organisms, such as the remains of algae, spores, pollen, plant cuticles and corky fragments of herbaceous and woody plants, and cellular debris from other aquatic and land plants. Some deposits contain significant fossils; Germany's Messel Pit has the status of a Unesco World Heritage Site. The mineral matter in oil shale includes various fine-grained silicates and carbonates. Inorganic matrix can contain quartz, feldspars, clays (mainly illite and chlorite), carbonates (calcite and dolomites), pyrite and some other minerals.

Geologists can classify oil shales on the basis of their composition as carbonate-rich shales, siliceous shales, or cannel shales.

Another classification, known as the van Krevelen diagram, assigns kerogen types, depending on the hydrogen, carbon, and oxygen content of oil shales' original organic matter. The most commonly used classification of oil shales, developed between 1987 and 1991 by Adrian C. Hutton, adapts petrographic terms from coal terminology. This classification designates oil shales as terrestrial, lacustrine (lake-bottom-deposited), or marine (ocean bottom-deposited), based on the environment of the initial biomass deposit. Known oil shales are predominantly aquatic (marine, lacustrine) origin. Hutton's classification scheme has proven useful in estimating the yield and composition of the extracted oil.

Historic examples
Humans have used oil shale as a fuel since prehistoric times, since it generally burns without any processing. Anncient Britons of the Iron Age also used to polish it and form it into ornaments. The first patent for extracting oil from oil shale was British Crown Patent 330 granted in 1694 to three persons named Martin Eele, Thomas Hancock and William Portlock who had "found a way to extract and make great quantities of pitch, tarr, and oyle out of a sort of stone."

In Canada, the First Nation peoples had used bitumen from seeps along the Athabasca and Clearwater Rivers to waterproof their birch bark canoes from early prehistoric times. The Canadian oil sands first became known to Europeans in 1719 when a Cree native named Wa-Pa-Su brought a sample to Hudsons Bay Company fur trader Henry Kelsey, who commented on it in his journals. Fur trader Peter Pond paddled down the Clearwater River to Athabasca in 1778, saw the deposits and wrote of "springs of bitumen that flow along the ground." In 1787, fur trader and explorer Alexander MacKenzie on his way to the Arctic Ocean saw the Athabasca oil sands, and commented, "At about 24 miles from the fork (of the Athabasca and Clearwater Rivers) are some bituminous fountains into which a pole of 20 feet long may be inserted without the least resistance."

The Athabasca River cuts through the heart of the deposit, and traces of the heavy oil are readily observed as black stains on the river banks. Since portions of the Athabasca sands are shallow enough to be surface-mineable, they were the earliest ones to see development. Historically, the bitumen was used by the indigenous Cree and Dene Aboriginal peoples to waterproof their canoes. The Athabasca oil sands first came to the attention of European fur traders in 1719 when Wa-pa-su, a Cree trader, brought a sample of bituminous sands to the Hudson's Bay Company post at York Factory on Hudson Bay.

Modern industrial mining of oil shale began in 1837 in Autun, France, followed by exploitation in Scotland, Germany, and several other countries.

Operations during the 19th century focused on the production of kerosene, lamp oil, and paraffin; these products helped supply the growing demand for lighting that arose during the Industrial Revolution. Fuel oil, lubricating oil and grease, and ammonium sulfate were also produced. The European oil-shale industry expanded immediately before World War I due to limited access to conventional petroleum resources and to the mass production of automobiles and trucks, which accompanied an increase in gasoline consumption.

WW1 and WW2 usage


Although the Estonian and Chinese oil-shale industries continued to grow after World War II, most other countries abandoned their projects due to high processing costs and the availability of cheaper petroleum.

China had discovered the outer edges of the region's oil, oil shale, oil sand, coal and natural gas reserves in 1929. Oil shale were extracted in rising amounts between 1929 to 1937, when it leveled off until 1944, with a fall in 1945. Tarakan crude oil from Bornio was mixed with lesser quantities of Manchurian oil shale distillates to make the primary feedstock for the production of Japanese diesel fuel in 1942. Australian troops ended the occupation of Tarakan and surrounding parts of Borneo in the June of 1945.

Romania had been a major power in the oil industry since the 1800s. It was one of the largest producers in Europe and Ploiesti was a major part of that production. (see Bombing of Romania in World War II). The Ploiești oil refineries provided about 30% of all Axis oil production.

Operation Tidal Wave was an air attack by bombers of the United States Army Air Forces (USAAF) based in Libya and Southern Italy on nine oil refineries around Ploiești, Romania on 1 August 1943, during World War II. It was a strategic bombing mission and part of the Allies' "oil campaign" to deny petroleum-based fuel to the Axis. The mission resulted in "no curtailment of overall product output".

Romania discovered some oil sands and shale near the oil producing town of Ploiești in the run up to WW2 and plans were made to use them if the conventional oil ran out, but it did not.

Cold War usage
The then high oil prices, hostile Arabs and falling supplies in the 1970s lead to a plan to exploit many unusual, remote and/or marginal fields in order to secure oil new supplies and as a possible way of earning more revenue as rising prices made them economically viable.

Following the 1973 oil crisis, world production of oil shale reached a peak of 46 million tonnes in 1980 before falling to about 16 million tonnes in 2000, due to competition from cheap conventional petroleum in the 1980s.

It would also have provided a theoretical alternative if the Middle East went crazy and the Gulf States were destroyed.

On 2 May 1982, known in some circles as "Black Sunday", Exxon canceled its US$5 billion Colony Shale Oil Project near Parachute, Colorado because of low oil-prices and increased expenses, laying off more than 2,000 workers and leaving a trail of home-foreclosures and small-business bankruptcies. In 1986, President Ronald Reagan signed into law the Consolidated Omnibus Budget Reconciliation Act of 1985 which among other things abolished the United States' Synthetic Liquid Fuels Program.

Modern usage
The global oil-shale industry began to revive at the beginning of the 21st century. In 2003, an oil-shale development program restarted in the United States. Authorities introduced a commercial leasing program permitting the extraction of oil shale and oil sands on federal lands in 2005, in accordance with the Energy Policy Act of 2005.

Venezuela's Orinoco Belt was discovered in 2003 and has been experimentally tapped for oil and gas since 2003. Oil sand/shale mining was planned for 2013, but is now planned for some time in the the 2020s.

As of 2008, industry uses oil shale in Brazil, China, Estonia and to some extent in Germany, and Russia. Several additional countries started assessing their reserves or had built experimental production plants, while others had phased out their oil shale industry. Oil shale serves for oil production in Estonia, Brazil, and China; for power generation in Estonia, China, and Germany; for cement production in Estonia, Germany, and China; and for use in chemical industries in China, Estonia, and Russia.As of 2009, 80% of oil shale used globally is extracted in Estonia, mainly due to the Oil-shale-fired power plants.

Oil shale serves as the main fuel for power generation only in Estonia, where the oil-shale-fired Narva Power Plants accounted for 95% of country's electrical generation in 2005.

Athabasca oil sands and shales



 * 1) Country- Canada
 * 2) Region- Northern Alberta
 * 3) Offshore/onshore- Onshore, mining
 * 4) Coordinates- 57.02°N 111.65°WCoordinates: 57.02°N 111.65°W
 * 5) Site operators- Syncrude, Suncor, CNRL, Shell, Total, Imperial Oil, Petro Canada, Devon, Husky, Statoil and Nexen
 * 6) Corporate partners- Chevron, Marathon, ConocoPhillips, BP and Oxy
 * 7) Discovery- 1848
 * 8) Start of production- 1967
 * 9) Current production of oil- 1,300,000 barrels per day (~6.5×107 t/a)
 * 10) Estimated oil in place- 133,000 million barrels (~1.81×1010 t)
 * 11) Producing formations- McMurray, Clearwater and Grand Rapids

The Athabasca oil sands are large deposits of bitumen or extremely heavy crude oil, located in northeastern Alberta, Canada – roughly centred on the boomtown of Fort McMurray. These oil sands, hosted primarily in the McMurray Formation, consist of a mixture of crude bitumen (a semi-solid rock-like form of crude oil), silica sand, clay minerals, and water. The Athabasca deposit is the largest known reservoir of crude bitumen in the world and the largest of three major oil sands deposits in Alberta, along with the nearby Peace River and Cold Lake deposits (the latter stretching into Saskatchewan).

Together, these oil sand deposits lie under 141,000 square kilometres (54,000 sq mi) of boreal forest and muskeg (peat bogs) and contain about 1.7 trillion barrels (270×109 m3) of bitumen in-place, comparable in magnitude to the world's total proven reserves of conventional petroleum. The International Energy Agency (IEA) lists the economically recoverable reserves, at 2006 prices and modern unconventional oil production technology, to be 178 billion barrels (28.3×109 m3), or about 10% of these deposits. These contribute to Canada's total proven reserves being the third largest in the world, after Saudi Arabia and Venezuela's Orinoco Belt.

In Canada, the First Nation peoples had used bitumen from seeps along the Athabasca and Clearwater Rivers to waterproof their birch bark canoes from early prehistoric times. The Canadian oil sands first became known to Europeans in 1719 when a Cree native named Wa-Pa-Su brought a sample to Hudsons Bay Company fur trader Henry Kelsey, who commented on it in his journals. Fur trader Peter Pond paddled down the Clearwater River to Athabasca in 1778, saw the deposits and wrote of "springs of bitumen that flow along the ground." In 1787, fur trader and explorer Alexander MacKenzie on his way to the Arctic Ocean saw the Athabasca oil sands, and commented, "At about 24 miles from the fork (of the Athabasca and Clearwater Rivers) are some bituminous fountains into which a pole of 20 feet long may be inserted without the least resistance."

The Athabasca River cuts through the heart of the deposit, and traces of the heavy oil are readily observed as black stains on the river banks. Since portions of the Athabasca sands are shallow enough to be surface-mineable, they were the earliest ones to see development. Historically, the bitumen was used by the indigenous Cree and Dene Aboriginal peoples to waterproof their canoes. The Athabasca oil sands first came to the attention of European fur traders in 1719 when Wa-pa-su, a Cree trader, brought a sample of bituminous sands to the Hudson's Bay Company post at York Factory on Hudson Bay.

Minor exploration and mining activity started up for a while in 1900. Operations were mooted in 1924-26, 1940, 1958 and 1962. The 1962 plans were take up in 1965 and enacted in 1967. It's development was inhibited by the declining world oil prices in the late 1960s. The second mine, operated by the Syncrude consortium, did not begin operating until 1978, after the 1973 oil crisis had caused prices to rise, thus sparking investors' interest.

By 2009, the two extraction methods used were in situ extraction, when the bitumen occurs deeper within the ground, (which will account for 80 percent of oil sands development) and surface or open-pit mining, when the bitumen is closer to the surface. Only 20 percent of bitumen can be extracted using open pit mining methods, which involves large scale excavation of the land with huge hydraulic power shovels and 400-ton heavy hauler trucks. Surface mining leaves toxic tailings ponds. In contrast, in situ uses more specialized techniques such as steam-assisted gravity drainage (SAGD). "Eighty percent of the oil sands will be developed in situ which accounts for 97.5 percent of the total surface area of the oil sands region in Alberta." In 2006 the Athabasca deposit was the only large oil sands reservoir in the world which was suitable for large-scale surface mining, although most of this reservoir can only be produced using more recently developed in-situ technology.

Critics contend that government and industry measures taken to reduce environmental and health risks posed by large-scale mining operations are inadequate, causing unacceptable damage to the natural environment and human welfare. Objective discussion of the environmental impacts has often been clouded by polarised arguments from industry and from advocacy groups.

Melville Island oil shales


Melville Island (Northwest Territories and Nunavut) is a uninhabited island of the Canadian Arctic Archipelago with an area of 42,149 km2 (16,274 sq mi). It is the 33rd largest island in the world and Canada's eighth largest island. Melville Island is shared by the Northwest Territories, which is responsible for the western half of the island, and Nunavut, which is responsible for the eastern half. The border runs along the 110th meridian west. The mountains on Melville Island, some of the largest in the western Canadian Arctic, reach heights of 1,000 m (3,300 ft). There are two subnational pene-exclaves that lie west of the 110th meridian and form part of the Northwest Territories. These can only be reached by land from Nunavut or boat from the Northwest Territories.

Melville has surfaced as a candidate for natural gas deposits. The island was believed to have deposits of coal and oil shale since the first half of the 20th century. The first Canadian Arctic island exploratory well was spudded in 1961 at Winter Harbour. It drilled Lower Paleozoic strata to a total depth of 3,823 m (12,543 ft). In the 1970s, the northern portion of the island on the east side of the Sabine Peninsula proved to contain a major gas field, known as Drake Point. The lease was owned by Panarctic Oils, a joint operation with the Canadian Government.

Utah oil sands


In the United States a large supply of oil sands are found in Eastern Utah. These deposits of bitumenor heavy crude oil have the ability to generate about 12 to 19 billion barrels from a number of prominent sites. the Oil Shale and Tar Sands Programmatic EIS Information Center had confirmed most of this by 2008.

Since the early 1900s the oil sand deposits have been extracted mainly for the use of road pavement. Later, in the 1970s, oil companies began to experiment with the deposits in the hope of using it for their benefit. These experiments ended in the late 1980s when the technologies being used were concluded inefficient and too expensive. Recently, oil companies have again become interested in Utah's oil sands. Now that conventional oil is becoming harder to find, oil sands have become an alternative fuel source.

Utah's oil sands are made up of several different deposits all consisting of different amounts of heavy or crude oil. These sites are mostly found on public lands. They are mainly close together and many are found within the Uintah Basin of Utah, which is a section of the Colorado Plateaus province. Some of these sites include Sunnyside, P.R. Spring, Asphalt Ridge, Hill Creek, Circle Ridge, Circle Cliffs, White Rocks, and the Tar Sand Triangle, the highest deposit.

The Tar Sand Triangle is located in Southeastern Utah and covers an area of 148,000 acres. It is located between the Dirty Devil and Colorado Rivers in Wayne and Garfield Counties. The Tar Sand Triangle is the largest deposit of oil sands in the United States known today. It contains about 6.3 billion barrels of heavy oil, but is thought to have originally held more. At one point the Tar Sand Triangle could have consisted of 16 billion barrels of heavy oil, almost as much as in Utah today.

In the United States a large supply of oil sands are found in Eastern Utah. These deposits of bitumen or heavy crude oil have the ability to generate about 12 to 19 billion barrels from a number of prominent sites.

Since the early 1900s the oil sand deposits have been extracted mainly for the use of road pavement. Later, in the 1970s, oil companies began to experiment with the deposits in the hope of using it for their benefit. These experiments ended in the late 1980s when the technologies being used were concluded inefficient and too expensive. Recently, oil companies have again become interested in Utah's oil sands. Now that conventional oil is becoming harder to find, oil sands have become an alternative fuel source.

The Utah Oil Sands Joint Venture is a joint venture between Nevtah Capital Management, Inc., and Black Sands Energy Corp. to develop oil sands resources at the Uintah Basin in Utah.

Oil-sands extraction in Utah started in the 1960s when two extraction plants were constructed. Western Industries opened a strip-mine and built a pilot plant along the east side of the Whiterocks River and Major Oil Company opened a strip-mine and built a pilot plant on the west side off the Whiterocks River. In 2005, Nevtah Capital Management and Cassandra Energy (now: Black Sands Energy) formed a joint venture to develop Utah's oil sands and opened a pilot plant at the Asphalt Ridge lease location. The pilot plant became in operation in November 2005.

The joint venture uses closed-loop solvent extraction process originally proven by X-TRAC Energy in Wyoming in 1998, with a full-scale production plant. Black Sands Energy has exclusive rights to a technology.

The above-ground extraction process dissolute crushed, 1" minus oil sands materials through contact with a benign non-toxic solvent in an enclosed extractor vessel at temperatures up to 300 °F (149 °C) at near-atmospheric pressures. As the material dissolves, it is passed to a wash chamber where any remaining oil is removed. The oil-free sand is then desolventised with heat, which converts the liquid solvent to a gas, leaving dry solids suitable for mine backfill. The solvent-oil mixture is pumped into a critical unit for the removal of asphalt and oil from the solvent through heating and cooling. The recovered solvent is compressed back to a liquid, cooled and re-circulated to the extractor vessel in an endless loop. The system consists of only few moving parts and it operates on a gravity principle. Since the process does not use water to recover the oil, energy requirements are minimal.

The partnership holds the rights to 13 oil sands leases in Utah consisting of 11,535 acres (46.68 km2) containing over 650,000,000 bbl of recoverable oil.

The joint venture owns a 200 bbl per day mobile pilot plant and preparing a 2,000 bbl per day commercial production unit. The production capacity is expected to increase up 50,000 bbl per day by the end of 2009. The system has been improved to maintain processing levels at cold temperatures. A steam jacket has been installed which creates drier sand and keeps the pumps, plumbing and the extraction chamber warmer during standby time, minimizing warm-up time. System performance has improved with the installation of more powerful pumps and additional sensors for better indications of mass flow, temperature and material levels. The upgraded process control provides more precise data required in order to measure the system's performance.

The partnership is between Nevtah Capital Management, Inc., and Black Sands Energy Corp. The extraction technology is provided by development by Black Sands Energy nd the financing is provided by Nevtah Capital Management. On 12 January 2007, Nevtah Capital Management and Black Sands Energy announced a joint venture agreement with Korea Technology Industry. According to the agreement, Korea Technology Industry provides $19 million for the development of the Whiterocks Deposit, in exchange of 50% of net profit. The joint venture agreement is limited to 100 million barrels of oil.

Manchurian oil sands and shales
China had discovered the outer edges of the region's oil, oil shale, oil sand, coal and natural gas reserves in 1929. Oil shale were extracted in rising amounts between 1929 to 1937, when it leveled off until 1944, with a fall in 1945. Tarakan crude oil from Bornio was mixed with lesser quantities of Manchurian oil shale distillates to make the primary feedstock for the production of Japanese diesel fuel in 1942. Australian troops ended the occupation of Tarakan and surrounding parts of Borneo in the June of 1945.

China tried to rebuild the Japanese plants and expand on them in 1959-1960 under a plan to increase thier fule supply so as to maintain fule indipendence once industry had eventuly taken of. Plans emerged in the 1970s and early 1980s. Modern activity started with plans in the late 1980 along with the growing industrial sector and exploration started in the 1990's, which in turn lead to the discovery of major finds in the local basin. Test drilling and mining started in the 2000s and major extraction work go underway in the 2010s.

Ploiești oil sands and shales
In the mid-19th century the Ploiești region was one of the world's leading oil extraction and refinery sites. The world's first large refinery opened at Ploiești in 1856-1857, with US investment.

Romania had been a major power in the oil industry since the 1800s. It was one of the largest producers in Europe and Ploiești was a major part of that production, hence it's fate in the Allied bombing of Romania in World War II. The Ploiești oil refineries provided about 30% of all Axis oil production.

Romania discovered some oil sands and shale near the oil producing town of Ploiești during the run up to WW2 and plans were made to use them if the conventional oil ran out, but it did not.

Operation Tidal Wave was an air attack by bombers of the United States Army Air Forces (USAAF) based in Libya and Southern Italy on nine oil refineries around Ploiești, Romania on 1 August 1943, during World War II. It was a strategic bombing mission and part of the "oil campaign" to deny petroleum-based fuel to the Axis. The mission resulted in "no curtailment of overall product output".

In 1950, as a milestone in the development of the petroleum, hydrocarbon processing, and petrochemical industries, the Engineering and Design Institute for Oil Refineries and Petrochemical Plants, SC IPIP SA, a Romanian company with a large range of capabilities and experience, was established at Ploiești. The oil and gas field still produces a modest amount of oil to date.

Télots\Autun oil shales


The mine of Télots operated the oil shale in Autun which lay on the edge of the city of Autun in   Saint-Forgeot,  Saône-et-Loire, eastern France.

Extraction begins in 1824 and was produced in 1837 for public lighting and facilities, but it soon diversified production. More mining concessions were granted in 1865.

The refinery was completed in in 1936 and employed several hundred workers who produced fuel for automobiles.

It was sabotaged by the locals and bombed in the ailed Scullion raids. In retaliation the local occupation militia killed five workers.

Upon it's closing due falling reserves in 1957, the site was dismantled and partially demolished. The ruins and two large fly ash\slag heaps mark the landscape still early in the early 21st century, and is invaded by a particular vegetation that is studied for its biodiversity.

Kimmeridge oil shale and clays
The Kimmeridge Oil Field is to the northwest of Kimmeridge Bay, on the south coast of the Isle of Purbeck, in Dorset, England.

The small village Kimmeridge is about 6 kilometres (3.7 mi) south of Wareham and about 8 kilometres (5.0 mi) west of Swanage. The Kimmeridge oil field is part of the Wytch Farm oil field and processing facility operated by Perenco. Wytch Farm is on the southern shore of Poole Harbour and about 12 kilometres (7.5 mi) northeast of the oil well. Kimmeridge Bay and its cliffs are part of the Jurassic Coast, a World Heritage Site, because of the quality and variety of geological landforms along the coast.

Ancient Britons and Romans used polished 'Black stone', a shiny type of oil shale, for ornaments. Local Romans also burnt the duller stones for fuel in-lieu for coal and wood when supplies were short.

Victorians began mining the shales on a formal basis in around the 1850s for a local source of industrial fule. Oil prospecting began in the 1920s and a reserve was found in 1935. Drilling was at 6 poinis between 1958 and 1980.

The dried (of water, not oil) clay and shales are still used by locals as a informal domestic fuel.

Synthetic crude
Synthetic crude oil, also known as syncrude, is the output from a bitumen upgrader facility used in connection with oil sand production in Canada. Bituminous sands are mined using enormous (100 ton capacity) power shovels and loaded into even larger (400 ton capacity) dump trucks for movement to an upgrading facility. The process used to extract the bitumen from the sand is a hot water process originally developed by Dr. Karl Clark of the University of Alberta during the 1920s. After extraction from the sand, the bitumen is fed into a bitumen upgrader which converts it into a light crude oil equivalent. This synthetic substance is fluid enough to be transferred through conventional oil pipelines and can be fed into conventional oil refineries without any further treatment. By 2015 Canadian bitumen upgraders were producing over 1 million barrels (160×103 m3) per day of synthetic crude oil, of which 75% was exported to oil refineries in the United States.

In Alberta, five bitumen upgraders produce synthetic crude oil and a variety of other products: The Suncor Energy upgrader near Fort McMurray, Alberta produces synthetic crude oil plus diesel fuel; the Syncrude Canada, Canadian Natural Resources, and Nexen upgraders near Fort McMurray produce synthetic crude oil; and the Shell Scotford Upgrader near Edmonton produces synthetic crude oil plus an intermediate feedstock for the nearby Shell Oil Refinery. A sixth upgrader, under construction in 2015 near Redwater, Alberta, will upgrade half of its crude bitumen directly to diesel fuel, with the remainder of the output being sold as feedstock to nearby oil refineries and petrochemical plants.

Synthetic crude is the output from a bitumen/extra heavy oil upgrader facility used in connection with oil sand production. It may also refer to shale oil, an output from an oil shale pyrolysis. The properties of the synthetic crude depend on the processes used in the upgrading. Typically, it is low in sulfur and has an API gravity of around 30. It is also known as "upgraded crude".

Synthetic crude is an intermediate product produced when an extra-heavy or unconventional oil source is upgraded into a transportable form. Synthetic crude is then shipped to oil refineries where it is further upgraded into finished products. Synthetic crude may also be mixed, as a diluent, with heavy oil to create synbit. Synbit is more viscous than synthetic crude, but can be a less expensive alternative for transporting heavy oil to a conventional refinery.

Syncrude Canada, Suncor Energy Inc., and Canadian Natural Resources Limited are the three largest worldwide producers of synthetic crude with a cumulative production of approximately 600,000 barrels per day (95,000 m3/d). The NewGrade Energy Upgrader became operational in 1988, and was the first upgrader in Canada, now part of the CCRL Refinery Complex.

Overview
Syncrude Canada Ltd. is one of the world's largest producers of synthetic crude oil from oil sands and the largest single source producer in Canada. It is located just outside Fort McMurray in the Athabasca Oil Sands, and has a nameplate capacity of 350,000 barrels per day (56,000 m3/d) of oil, equivalent to about 13% of Canada's consumption. It has approximately 5.1 billion barrels (810,000,000 m3) of proven and probable reserves (11.9 billion when including contingent and prospective resources) situated on 8 leases over 3 contiguous sites. Including fully realized prospective reserves, current production capacity could be sustained for well over 90 years.

The company is a joint venture between five partners. As a result, Syncrude is not traded directly, but rather through the individual owners. As of June 2016, the partners (by percentage): Suncor Energy (53.74%), Imperial Oil (25%), Sinopec (9.03%), Nexen (7.23%), and Mocal Energy (a subsidiary of Nippon Oil Exploration) (5%). Because of Nexen's subsequent takeover by CNOOC, over 16% of the shares in Syncrude are controlled by State Owned Enterprises (SOE).

The ownership board must approve all annual operating budgets and proposed capital spending projects, and are required to provide the funding for said activities based on their ownership share.

Corporate History
Syncrude was formed as a research consortium in 1964. Construction at the Syncrude site began in 1973, and it officially opened in 1978. Starting in 1996, Syncrude has been expanding its operations. Between 1996 and 1999, the original mine was expanded and the plant was "debottlenecked", increasing production from 73.5 million barrels (11,690,000 m3) per year in 1996 to 81.4 million in 1999. The total cost of this stage of expansion was $470 million. Between 1998 and 2001, a new mine, Aurora, was opened 35 km north of the original site, and further debottlenecking was undertaken. Production started in Aurora in July 2001. Syncrude's production increased to 90 million barrels (14,000,000 m3) per year by the end of 2001. Total cost for this stage was $1 billion.

A third stage of expansion was undertaken between 2001 and 2006, in which a second train at the Aurora line came online and the Mildred Lake upgrader was expanded. The expansion added 100,000 barrels per day (16,000 m3/d) to Syncrude's production (36.5 million barrels (5,800,000 m3) a year assuming this is average). The cost was $8.4 billion, a substantial cost overrun over the original estimate of $5.7 billion.

On April 12, 2010, ConocoPhillips agreed to sell its share to Sinopec, a Chinese state-owned oil company. The sale, for $4.65 billion, was completed on June 25, 2010.

A 183 m (600 ft) smokestack is located at the facility which is the second tallest in western Canada.

In April 2016, Suncor announced that they had reached a $937-million deal to acquire Murphy Oil Corp.'s five per cent stake in the Syncrude project north of Fort McMurray, Alta. This follows the hostile takeover of Canadian Oil Sands less than a year ago, and will increase its interest in Syncrude from just under 49 per cent to nearly 54 per cent, making it the majority shareholder of the project.

The 2016 Fort McMurray wildfire forced a complete shutdown of Syncrude's facilities.

Pollution controversy
Air releases of combined gases without volatile organic compounds (VOCs) by Syncrude Canada in 2005 were 129,741,321 (kg) in total, including ammonia (4,302,361 kg), sulphuric acid (1,129,425 kg), xylene (501,461 kg), etc. The company was also ranked as having the seventh highest air releases of combined gases (without VOC) in Canada in 2005. Syncrude's Mildred Lake Plant Site is the largest greenhouse gas emitter in Canada emitting 12,359,420 tonnes of CO2 equivalent in 2012.

Corporate stats

 * 1) Name- Syncrude Canada Ltd.
 * 2) Corporate type- Joint Venture
 * 3) Industry- Oil and Gas
 * 4) Founded- December 1964
 * 5) Headquarters- Fort McMurray, Alberta
 * 6) Products- Petroleum
 * 7) Number of employees- 5,600 (2009)
 * 8) Website- www.syncrude.ca

Oil sand locations

 * 1) Canada
 * 2) Melville Island
 * 3) Baffin Island
 * 4) Athabasca oil sands
 * 5) Northern Sesckatuain
 * 6) Northern Manitoba
 * 7) South eastern British Colombia
 * 8) Southern Yukon
 * 9) Venezuela
 * USA
 * 1) Utah
 * 2) Southern Alaska
 * 3) California
 * 4) Louisiana
 * 5) Montana
 * 6) Texas
 * 7) New York
 * 8) Connecticut
 * 9) Ohio
 * 10) Illinois
 * 11) Florida
 * 12) N. Dakota
 * 13) Australia
 * 14) Uganda
 * 15) Kenya
 * 16) Burundi
 * 17) Rwanda
 * 18) Tanzania
 * 19) Greenland
 * 20) France
 * 21) Poland
 * 22) Greece
 * 23) Bulgaria
 * 24) Iceland
 * 25) Sweden
 * 26) Norway
 * 27) Finland
 * 28) Spain
 * 29) Italy
 * 30) Bosnia
 * 31) Madagascar
 * 32) S. Africa
 * 33) Barbados
 * 34) Bahamas
 * 35) Cuba
 * 36) Oman
 * 37) Argentina
 * 38) China
 * 39) Junggar Basin
 * 40) Tarim Basin
 * 41) Turpan Basin
 * 42) Qaidam Basin
 * 43) Ordos Basin
 * 44) Scichuan Basin
 * 45) Jianghan Basin
 * 46) Subie Basin
 * 47) Songlaio Basin
 * 48) Pearl River Mouth Basin
 * 49) South China Basin
 * 50) Yangtze Basin
 * 51) Kazakhstan
 * 52) To the north of the Caspian Sea
 * 53) In the north of the Caspian Sea
 * 54) Russia
 * 55) Tunguska Basin
 * 56) Tatarstan
 * 57) Dagestan
 * 58) Central Urals Mountains
 * 59) Sakhalin Island
 * 60) Mongolia
 * 61) Estonia
 * 62) Latvia
 * 63) Lithuania
 * 64) Belorussian
 * 65) Ukraine
 * 66) Nova-Russia
 * 67) Afghanistan
 * 68) Pakistan
 * 69) Tajikistan
 * 70) Turkmenistan
 * 71) Uzbekistan
 * 72) Azerbaijan
 * 73) Armenian
 * 74) Georgia
 * 75) Moldavia
 * 76) Transdentstria
 * 77) Nagorno-Karabach
 * 78) N. Osetia
 * 79) Chechnya
 * 80) Albania,
 * 81) Trinidad
 * 82) N. Korea
 * 83) Romania
 * 84) Serbia
 * 85) Bosnia
 * 86) Hungary
 * 87) Croatia
 * 88) Macedonia
 * 89) Greece
 * 90) Slovenia
 * 91) Italy
 * 92) Poland
 * 93) Madagascar
 * 94) Tsimiroro
 * 95) Bemolanga
 * 96) Republic of the Congo
 * 97) Brazil
 * 98) Guyana
 * 99) Colombia
 * 100) Equator
 * 101) Peru
 * 102) Nigeria
 * 103) India
 * 104) Iran
 * 105) Ghana
 * 106) Egypt
 * 107) North Sudan
 * 108) South Sudan
 * 109) Mexico
 * 110) Saudi Arabia
 * 111) Kuwait
 * 112) Iraq
 * 113) Turkey
 * 114) Jordan
 * 115) Syria
 * 116) Vietnam
 * 117) Burma
 * UK
 * 1) Mid Wales coastline
 * 2) Dorset
 * 3) Lankashire,
 * 4) Durhamshire,
 * 5) E. Yorkshire
 * 6) Oxfordshire
 * 7) Berkshire
 * 8) Surrey
 * 9) Essex
 * 10) North Norfolk
 * 11) South Lincolnshire
 * 12) Bukinghamshire
 * 13) Derbyshire
 * 14) Staffordshire
 * 15) Devon
 * 16) Sterlingshire
 * 17) Cornwall
 * 18) Vale of Glamorgan
 * 19) Monmouthshire
 * 20) Tayside
 * 21) Northumbrian coast
 * 22) Cumbrian coast
 * 23) Dumfress-shire
 * 24) Inverness-shire.
 * 25) Easter Ross
 * 26) Malaysia
 * 27) Indonesia
 * 28) Thailand
 * 29) Uganda
 * 30) Niger
 * 31) Kenya
 * 32) Tanzania
 * 33) Senegal
 * 34) Mozambique
 * 35) Somalia
 * 36) Ethiopia
 * DRC
 * 1) Congo (Brazaville)
 * 2) Angola
 * 3) Mexico
 * 4) Bolivia
 * 5) Paraguay
 * 6) Uruguay
 * 7) Brazil
 * 8) Pakistan
 * 9) Morocco
 * 10) Libya
 * 11) Algeria
 * 12) Slovakia
 * 13) Austria
 * 14) Luxembourg
 * 15) Switzerland
 * 16) Liechtenstein
 * 17) France
 * 18) Belgian
 * 19) Netherlands
 * 20) Denmark
 * 21) Hungary
 * 22) Czech Republic

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 bbl/d (6,400 m3/d). The reserves are estimated between 0.5 and 2.5 Gbbl (79×106 and 397×106 m3).

Methods for extraction include Cold heavy oil production with sand, steam assisted gravity drainage, steam injection, vapor extraction, Toe-to-Heel Air Injection (THAI), and open-pit mining for extremely sandy and oil-rich deposits.

Oil shales locations

 * 1) Serbia
 * 2) Croatia
 * 3) Slovenia
 * 4) Macedonia
 * 5) Austria
 * 6) Switzerland
 * 7) Hungary
 * 8) Slovakia
 * 9) Hungray
 * 10) Georgia
 * 11) Armenia
 * 12) Uganda
 * 13) S. Sudan
 * 14) N. Sudan
 * 15) Ethiopia
 * 16) Zambia
 * 17) Malawi
 * 18) S. Africa
 * 19) Botswana
 * 20) Somalia
 * 21) Kenya
 * 22) Tanzania
 * 23) Brazil,
 * 24) China,
 * 25) Estonia
 * 26) Germany
 * 27) Russia.
 * 28) Estonia,
 * 29) Israel,
 * 30) Romania
 * 31) Jordan
 * 32) Egypt
 * 33) Canada
 * 34) Turkey
 * 35) Palestine
 * 36) Syria
 * 37) Lebanon
 * 38) Azerbaijan
 * 39) Iran
 * 40) Iraqi Kurdistan
 * 41) Albania
 * 42) Greece
 * DRC
 * 1) Peru
 * USA
 * 1) Mongolia
 * 2) Kazakhstan
 * 3) Australia
 * 4) France
 * 5) Belgium
 * 6) Sweden
 * 7) Greenland
 * 8) Indonesia
 * 9) Estonia
 * 10) Latvia
 * 11) Lituania
 * 12) Poland
 * 13) Sweden
 * 14) United States,
 * 15) Australia,
 * 16) Sweden
 * 17) Estonia,
 * 18) Jordan,
 * 19) France,
 * 20) Germany,
 * 21) Brazil,
 * 22) China
 * 23) Mongolia
 * 24) Russia.
 * 25) Brazil
 * 26) Romania
 * 27) Moldova
 * 28) Transdenstria
 * 29) Ukraine
 * 30) Belorussian
 * 31) Argentina
 * 32) Paraguay
 * 33) Brazil
 * 34) Bolivia
 * 35) Colombia
 * 36) Valenzuela
 * 37) Mexico
 * 38) Guyana
 * 39) Suriname
 * 40) Aruba
 * 41) Trinidad and Tobago
 * 42) French Gueania

The largest deposits in the world occur in the United States in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming; about 70% of this resource lies on land owned or managed by the United States federal government. Deposits in the United States constitute 62% of world resources; together, the United States, Russia and Brazil account for 86% of the world's resources in terms of shale-oil content. These figures remain tentative, with exploration or analysis of several deposits still outstanding. Professor Alan R. Carroll of University of Wisconsin–Madison regards the Upper Permian lacustrine oil-shale deposits of northwest China, absent from previous global oil shale assessments, as comparable in size to the Green River Formation.

According to the World Energy Council, in 2008 the total production of shale oil from oil shale was 930,000 tonnes, equal to 17,700 barrels per day (2,810 m3/d), of which China produced 375,000 tonnes, Estonia 355,000 tonnes, and Brazil 200,000 tonnes. In comparison, production of the conventional oil and natural gas liquids in 2008 amounted 3.95 billion tonnes or 82.1 million barrels per day (13.1×106 m3/d).

Shale oil extraction
Shale oil extraction is an industrial process for unconventional oil production. This process converts kerogen in oil shale into shale oil by pyrolysis, hydrogenation, or thermal dissolution. The resultant shale oil is used as fuel oil or upgraded to meet refinery feedstock specifications by adding hydrogen and removing sulfur and nitrogen impurities.

Shale oil extraction is usually performed above ground (ex situ processing) by mining the oil shale and then treating it in processing facilities. Other modern technologies perform the processing underground (on-site or in situ processing) by applying heat and extracting the oil via oil wells.

The earliest description of the process dates to the 10th century. In 1684, Great Britain granted the first formal extraction process patent. Extraction industries and innovations became widespread during the 19th century. The industry shrank in the mid-20th century following the discovery of large reserves of conventional oil, but high petroleum prices at the beginning of the 21st century have led to renewed interest, accompanied by the development and testing of newer technologies.

As of 2010, major long-standing extraction industries are operating in Estonia, Brazil, and China. Its economic viability usually requires a lack of locally available crude oil. National energy security issues have also played a role in its development. Critics of shale oil extraction pose questions about environmental management issues, such as waste disposal, extensive water use, waste water management, and air pollution.

Internal combustion
Internal combustion technologies burn materials (typically char and oil shale gas) within a vertical shaft retort to supply heat for pyrolysis. Typically raw oil shale particles between 12 millimetres (0.5 in) and 75 millimetres (3.0 in) in size are fed into the top of the retort and are heated by the rising hot gases, which pass through the descending oil shale, thereby causing decomposition of the kerogen at about 500 °C (932 °F). Shale oil mist, evolved gases and cooled combustion gases are removed from the top of the retort then moved to separation equipment. Condensed shale oil is collected, while non-condensable gas is recycled and used to carry heat up the retort. In the lower part of the retort, air is injected for the combustion which heats the spent oil shale and gases to between 700 °C (1,292 °F) and 900 °C (1,650 °F). Cold recycled gas may enter the bottom of the retort to cool the shale ash. The Union A and Superior Direct processes depart from this pattern. In the Union A process, oil shale is fed through the bottom of the retort and a pump moves it upward. In the Superior Direct process, oil shale is processed in a horizontal, segmented, doughnut-shaped traveling-grate retort.

Internal combustion technologies such as the Paraho Direct are thermally efficient, since combustion of char on the spent shale and heat recovered from the shale ash and evolved gases can provide all the heat requirements of the retort. These technologies can achieve 80-90% of Fischer assay yield. Two well-established shale oil industries use internal combustion technologies: Kiviter process facilities have been operated continuously in Estonia since the 1920s, and a number of Chinese companies operate Fushun process facilities.

Common drawbacks of internal combustion technologies are that the combustible oil shale gas is diluted by combustion gases and particles smaller than 10 millimeters (0.4 in) can not be processed. Uneven distribution of gas across the retort can result in blockages when hot spots cause particles to fuse or disintegrate.

Hot recycled solids
Hot recycled solids technologies deliver heat to the oil shale by recycling hot solid particles—typically oil shale ash. These technologies usually employ rotating kiln or fluidized bed retorts, fed by fine oil shale particles generally having a diameter of less than 10 millimeters (0.4 in); some technologies use particles even smaller than 2.5 millimeters (0.10 in). The recycled particles are heated in a separate chamber or vessel to about 800 °C (1,470 °F) and then mixed with the raw oil shale to cause the shale to decompose at about 500 °C (932 °F). Oil vapour and shale oil gas are separated from the solids and cooled to condense and collect the oil. Heat recovered from the combustion gases and shale ash may be used to dry and preheat the raw oil shale before it is mixed with the hot recycle solids.

In the Galoter and Enefit processes, the spent oil shale is burnt in a separate furnace and the resulting hot ash is separated from the combustion gas and mixed with oil shale particles in a rotating kiln. Combustion gases from the furnace are used to dry the oil shale in a dryer before mixing with hot ash. The TOSCO II process uses ceramic balls instead of shale ash as the hot recycled solids. The distinguishing feature of the Alberta Taciuk Process (ATP) is that the entire process occurs in a single rotating multi–chamber horizontal vessel.

Because the hot recycle solids are heated in a separate furnace, the oil shale gas from these technologies is not diluted with combustion exhaust gas. Another advantage is that there is no limit on the smallest particles that the retort can process, thus allowing all the crushed feed to be used. One disadvantge is that more water is used to handle the resulting finer shale ash.

It is a horizontal cylinder 8.2 meters (27 ft) high and 62.5 meters (205 ft) wide. The raw oil shale is fed from the right side and it moves to a section where it is dried and preheated by hot oil shale ash. The temperature in this section is around 250 °C (482 °F). At the same time, the raw oil shale in this section serves to cool the resultant oil shale ash before its removal. In the retorting section, the temperature is around 500 °C (932 °F). Oil vapors are removed through the vapor tube. The spent oil shale is again heated in the combustion section to a temperature of 750 °C (1,380 °F) and ash is generated. The ash is then sent to the retorting section as a heat carrier, or to the cooling zone for removal.

Conduction through a wall
These technologies transfer heat to the oil shale by conducting it through the retort wall. The shale feed usually consists of fine particles. Their advantage lies in the fact that retort vapors are not combined with combustion exhaust. The Combustion Resources process uses a hydrogen–fired rotating kiln, where hot gas is circulated through an outer annulus. The Oil-Tech staged electrically heated retort consists of individual inter-connected heating chambers, stacked atop each other. Its principal advantage lies in its modular design, which enhances its portability and adaptability. The Red Leaf Resources EcoShale In-Capsule Process combines surface mining with a lower-temperature heating method similar to in situ processes by operating within the confines of an earthen structure. A hot gas circulated through parallel pipes heats the oil shale rubble. An installation within the empty space created by mining would permit rapid reclamation of the topography. A general drawback of conduction through a wall technologies is that the retorts are more costly when scaled-up due to the resulting large amount of heat conducting walls made of high-temperature alloys.

Externally generated hot gas
In general, externally generated hot gas technologies are similar to internal combustion technologies in that they also process oil shale lumps in vertical shaft kilns. Significantly, though, the heat in these technologies is delivered by gases heated outside the retort vessel, and therefore the retort vapors are not diluted with combustion exhaust. The Petrosix and Paraho Indirect employ this technology. In addition to not accepting fine particles as feed, these technologies do not utilize the potential heat of combusting the char on the spent shale and thus must burn more valuable fuels. However, due to the lack of combustion of the spent shale, the oil shale does not exceed 500 °C (932 °F) and significant carbonate mineral decomposition and subsequent CO2 generation can be avoided for some oil shales. Also, these technologies tend to be the more stable and easier to control than internal combustion or hot solid recycle technologies.

Reactive fluids
Kerogen is tightly bound to the shale and resists dissolution by most solvents. Despite this constraint, extraction using especially reactive fluids has been tested, including those in a supercritical state. Reactive fluid technologies are suitable for processing oil shales with a low hydrogen content. In these technologies, hydrogen gas (H2) or hydrogen donors (chemicals that donate hydrogen during chemical reactions) react with coke precursors (chemical structures in the oil shale that are prone to form char during retorting but have not yet done so). Reactive fluid technologies include the IGT Hytort (high-pressure H2) process, donor solvent processes, and the Chattanooga fluidized bed reactor. In the IGT Hytort oil shale is processed in a high-pressure hydrogen environment. The Chattanooga process uses a fluidized bed reactor and an associated hydrogen-fired heater for oil shale thermal cracking and hydrogenation. Laboratory results indicate that these technologies can often obtain significantly higher oil yields than pyrolysis processes. Drawbacks are the additional cost and complexity of hydrogen production and high-pressure retort vessels.

Plasma gasification
Several experimental tests have been conducted for the oil-shale gasification by using plasma technologies. In these technologies, oil shale is bombarded by radicals (ions). The radicals crack kerogen molecules forming synthetic gas and oil. Air, hydrogen or nitrogen are used as plasma gas and processes may operate in an arc, plasma arc, or plasma electrolysis mode. The main benefit of these technologies is processing without using water.

In situ technologies
In situ technologies heat oil shale underground by injecting hot fluids into the rock formation, or by using linear or planar heating sources followed by thermal conduction and convection to distribute heat through the target area. Shale oil is then recovered through vertical wells drilled into the formation. These technologies are potentially able to extract more shale oil from a given area of land than conventional ex situ processing technologies, as the wells can reach greater depths than surface mines. They present an opportunity to recover shale oil from low-grade deposits that traditional mining techniques could not extract.

During World War II a modified in situ extraction process was implemented without significant success in Germany. One of the earliest successful in situ processes was underground gasification by electrical energy (Ljungström method)—a process exploited between 1940 and 1966 for shale oil extraction at Kvarntorp in Sweden. Prior to the 1980s, many variations of the in situ process were explored in the United States. The first modified in situ oil shale experiment in the United States was conducted by Occidental Petroleum in 1972 at Logan Wash, Colorado. Newer technologies are being explored that use a variety of heat sources and heat delivery systems.

Wall conduction
A simplified cross section of Shell's in situ process shows a number of vertical holes that have been drilled into the oil shale deposit, surrounded by a "freeze wall" intended to prevent leakage into the surrounding area. The process has an ecological footprint also on the ground. Shell's freeze wall for in situ shale oil production separates the process from its surroundings

Wall conduction in situ technologies use heating elements or heating pipes placed within the oil shale formation. The Shell in situ conversion process (Shell ICP) uses electrical heating elements for heating the oil shale layer to between 650 and 700 °F (340 and 370 °C) over a period of approximately four years. The processing area is isolated from surrounding groundwater by a freeze wall consisting of wells filled with a circulating super-chilled fluid. Disadvantages of this process are large electrical power consumption, extensive water use, and the risk of groundwater pollution. The process was tested since the early 1980s at the Mahogany test site in the Piceance Basin. 1,700 barrels (270 m3) of oil were extracted in 2004 at a 30-by-40-foot (9.1 by 12.2 m) testing area.

In the CCR Process proposed by American Shale Oil, superheated steam or another heat transfer medium is circulated through a series of pipes placed below the oil shale layer to be extracted. The system combines horizontal wells, through which steam is passed, and vertical wells, which provide both vertical heat transfer through refluxing of converted shale oil and a means to collect the produced hydrocarbons. Heat is supplied by combustion of natural gas or propane in the initial phase and by oil shale gas at a later stage.[10][49]

The Geothermic Fuels Cells Process (IEP GFC) proposed by Independent Energy Partners extracts shale oil by exploiting a high-temperature stack of fuel cells. The cells, placed in the oil shale formation, are fueled by natural gas during a warm-up period and afterward by oil shale gas generated by its own waste heat.

Externally generated hot gas
Schematic overview of the Chevron CRUSH process. Vertical wells inject hot gas, recover the oil, and house groundwater monitors. Oil pumps, hot gas compressors, and oil treatment units and tanks are located on the surface. The oil shale formation is fractured to enable gas circulation between wells and to increase oil recovery.

Chevron CRUSH process
Externally generated hot gas in situ technologies use hot gases heated above-ground and then injected into the oil shale formation. The Chevron CRUSH process, which was researched by Chevron Corporation in partnership with Los Alamos National Laboratory, injects heated carbon dioxide into the formation via drilled wells and to heat the formation through a series of horizontal fractures through which the gas is circulated. General Synfuels International has proposed the Omnishale process involving injection of super-heated air into the oil shale formation. Mountain West Energy's In Situ Vapor Extraction process uses similar principles of injection of high-temperature gas.

ExxonMobil Electrofrac
Main article: ExxonMobil Electrofrac ExxonMobil's in situ technology (ExxonMobil Electrofrac) uses electrical heating with elements of both wall conduction and volumetric heating methods. It injects an electrically conductive material such as calcined petroleum coke into the hydraulic fractures created in the oil shale formation which then forms a heating element. Heating wells are placed in a parallel row with a second horizontal well intersecting them at their toe. This allows opposing electrical charges to be applied at either end.

Volumetric heating
An artist's cross section of an oil shale processing facility using radio waves to deliver heat to the formation. On a plateau surrounded by mountains, transmission towers, an oil derrick, and a few supporting structures are shown above ground. Large opaque pipes represent its underground infrastructure network. The Illinois Institute of Technology developed the concept of oil shale volumetric heating using radio waves (radio frequency processing) during the late 1970s. This technology was further developed by Lawrence Livermore National Laboratory. Oil shale is heated by vertical electrode arrays. Deeper volumes could be processed at slower heating rates by installations spaced at tens of meters. The concept presumes a radio frequency at which the skin depth is many tens of meters, thereby overcoming the thermal diffusion times needed for conductive heating. Its drawbacks include intensive electrical demand and the possibility that groundwater or char would absorb undue amounts of the energy. Radio frequency processing in conjunction with critical fluids is being developed by Raytheon together with CF Technologies and tested by Schlumberger.

Microwave heating technologies are based on the same principles as radio wave heating, although it is believed that radio wave heating is an improvement over microwave heating because its energy can penetrate farther into the oil shale formation. The microwave heating process was tested by Global Resource Corporation. Electro-Petroleum proposes electrically enhanced oil recovery by the passage of direct current between cathodes in producing wells and anodes located either at the surface or at depth in other wells. The passage of the current through the oil shale formation results in resistive Joule heating.

Methods of extraction[edit] Except for a fraction of the extra-heavy oil or bitumen which can be extracted by conventional oil well technology, oil sands must be produced by strip mining or the oil made to flow into wells using sophisticated in-situ techniques. These methods usually use more water and require larger amounts of energy than conventional oil extraction. While much of Canada's oil sands are being produced using open-pit mining, approximately 90% of Canadian oil sands and all of Venezuela's oil sands are too far below the surface to use surface mining.[39]

Primary production[edit] 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 horizontal drilling, water flooding and gas injection are often required to maintain production. When primary production is used in the Venezuelan oil sands, where the extra-heavy oil is about 50 degrees Celsius, the typical oil recovery rates are about 8-12%. Canadian oil sands are much colder and more biodegraded, so bitumen recovery rates are usually only about 5-6%. Historically, primary recovery was used in the more fluid areas of Canadian oil sands. However, it recovered only a small fraction of the oil in place, so it not often used today.[40]

Surface mining[edit] Main article: History of the petroleum industry in Canada (oil sands and heavy oil) § Surface extraction See also: Athabasca oil sands § Surface mining See also: Surface mining

Mining operations in the Athabasca oil sands. NASA Earth Observatory image, 2009. The Athabasca oil sands are the only major oil sands deposits which are shallow enough to surface mine. In the Athabasca sands there are very large amounts of bitumen covered by little overburden, making surface mining the most efficient method of extracting it. The overburden consists of water-laden muskeg (peat bog) over top of clay and barren sand. The oil sands themselves are typically 40 to 60 metres (130 to 200 ft) thick deposits of crude bitumen embedded in unconsolidated sandstone, sitting on top of flat limestone rock. Since Great Canadian Oil Sands (now Suncor Energy) started operation of the first large-scale oil sands mine in 1967, bitumen has been extracted on a commercial scale and the volume has grown at a steady rate ever since.

A large number of oil sands mines are currently in operation and more are in the stages of approval or development. The Syncrude Canada mine was the second to open in 1978, Shell Canada opened its Muskeg River mine (Albian Sands) in 2003 and Canadian Natural Resources Ltd (CNRL) opened its Horizon Oil Sands project in 2009. Newer mines include Shell Canada's Jackpine mine,[41] Imperial Oil's Kearl Oil Sands Project, the Synenco Energy (now owned by Total S.A.) Northern Lights mine, and Suncor's Fort Hills mine.

Oil sands tailings ponds[edit] Main article: Oil sands tailings ponds

Syncrude's Mildred Lake site, plant and tailings ponds Fort McMurray, Alberta Oil sands tailings ponds are engineered dam and dyke systems that contain salts, suspended solids and other dissolvable chemical compounds such as acids, benzene, hydrocarbons[42] residual bitumen, fine silts (mature fine tails MFT), and water.[43] Large volumes of tailings are a byproduct of surface mining of the oil sands and managing these tailings is one of the most difficult environmental challenges facing the oil sands industry.[43] The Government of Alberta reported in 2013 that tailings ponds in the Alberta oil sands covered an area of about 77 square kilometres (30 sq mi).[43] The Syncrude Tailings Dam or Mildred Lake Settling Basin (MLSB) is an embankment dam that is, by volume of construction material, the largest earth structure in the world in 2001.[44]

Cold Heavy Oil Production with Sand (CHOPS)[edit] Main article: Cold heavy oil production with sand Some years ago Canadian oil companies discovered that if they removed the sand filters from heavy oil wells and produced as much sand as possible with the oil, production rates improved significantly. 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% versus 5-6% with sand filters in place) 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.[45] so in recent years disposing of oily sand in underground salt caverns has become more common.

Cyclic Steam Stimulation (CSS)[edit] See also: Steam injection (oil industry) 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 (CSS) "huff-and-puff" method is now widely used in heavy oil production world-wide due to its quick early production rates; however recovery factors are relatively low (10-40% of oil in place) compared to SAGD (60-70% of OIP).[46]

CSS 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.[47]

Steam Assisted Gravity Drainage (SAGD)[edit] Main article: Steam assisted gravity drainage 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.[47]

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[48] and Christina Lake[49] 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.

Vapor Extraction (VAPEX)[edit] Several methods 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.[50] Solvent can be beneficial if it produces more oil while requiring less energy to produce steam.

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. The process has attracted attention from oil companies, who are experimenting with it.

The above 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.[51]

Toe to Heel Air Injection (THAI)[edit] 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.[52]

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.[53]

Petrobank Energy and Resources has reported encouraging results from their test wells in Alberta, with production rates of up to 400 bbl/d (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)[54] system, which pulls the oil through a catalyst lining the lower pipe.[55][56][57]

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. [58]

Combustion Overhead Gravity Drainage (COGD)[edit] 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.[59]

The meaning of the terms "Barrel of Oil Equivalent" (BOE) and "Barrel of Oil" (BO)
BOE is the acronym of Barrel of Oil Equivalent – a unit of energy based on the approximate energy released by burning one barrel of crude oil (BO).
 * One BOE is roughly equivalent to 5,800 cf of natural gas or 58 CCF. The USGS takes a BOE for 6,000 cubic feet (170 cubic meters) of typical natural gas.
 * One Barrel contains 42 US gallons or 158.9873 litres of light crude oil which will produce 5.8 × 106 British Thermal Units (million BTU or mBTU) according to the US Internal Revenue Service.
 * 1 barrel (42 gallons) of crude oil = 5,800,000 Btu (for U.S. produced crude oil)
 * 1 gallon of gasoline = 120,476 Btu
 * 1 gallon of diesel fuel = 137,381 Btu (distillate fuel with less than 15 parts per million sulfur content)
 * 1 gallon of heating oil = 138,500 Btu (distillate fuel with 15 to 500 parts per million sulfur content)
 * 1 barrel of residual fuel oil = 6,287,000 Btu
 * 1 cubic foot of natural gas = 1,028 Btu
 * 1 gallon of propane = 91,333 Btu
 * 1 short ton (2,000 pounds) of coal = 19,622,000 Btu
 * 1 kilowatt-hour of electricity = 3,412 Btu
 * 1 barrel (b) of petroleum or related products = 42 gallons
 * 1 barrel of Portland cement = 376 pounds
 * 1 barrel of flour = 196 pounds
 * 1 barrel of pork or fish = 200 pounds
 * 1 barrel of (U.S.) dry measure = 3.29122 bushels or 4.2104 cubic feet
 * A barrel may be called a "drum," but a drum usually holds 55 gallons.
 * Barrels or gallons for petroleum and alike (such as gasoline, diesel fuel, and jet fuel)
 * Cubic feet for natural gas
 * Tons for coal
 * Kilowatthours for electricity
 * Bushels for cereals and alike (such as rye, wheat and barley)

Note that all wights and thermal values are all set to pan-global averages since oil is not a uniform constant due to the natural global variations (light crude, heavy crude, super-heavy crude, etc) so some cases are inevitably going to be different.

Also see

 * 1) 1970s energy crises
 * 2) Atomic power stations
 * 3) Energy
 * 4) Time line of Iraq

Links

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 * 6) https://en.wikipedia.org/wiki/Kimmeridge_Oil_Field
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 * 28) http://ostseis.anl.gov/guide/maps/index.cfm http://ostseis.anl.gov/documents/maps/OSTS002_UtahTarSands.pdf
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 * 30) http://cat.inist.fr/?aModele=afficheN&cpsidt=1708232
 * 31) http://cat.inist.fr/?aModele=afficheN&cpsidt=1708232
 * 32) http://www.nevtahoilsands.com/the-utah-tar-sands.htm The Utah Tar Sands.
 * 33) http://findarticles.com/p/articles/mi_m5CNK/is_2007_Jan_12/ai_n24998908
 * 34) https://www.flickr.com/photos/boobook48/8231343515
 * 35) https://www.flickr.com/photos/boobook48/8231344141?ytcheck=1
 * 36) http://www.avalanchepress.com/ManchurianOil.php
 * 37) http://www.bloomberg.com/news/articles/2013-02-28/sunshine-oilsands-taps-china-for-output-boost-corporate-canada
 * 38) https://www.amazon.com/Fragrance-Oil-Reminiscence-jasmine-mandarin/dp/B00D9DEWUE?ie=UTF8&ascsubtag=shopzilla_mp_1199-20%3B14693722069003189705010090302008005&creative=395105&creativeASIN=B00D9DEWUE&linkCode=df0&ref_=asc_df_B00D9DEWUE4348016&smid=A3A63D76HKPKJO&tag=shopz0d-20
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 * 41) http://www.theglobeandmail.com/news/politics/chinas-oil-sands-deal-will-have-lasting-impact/article1357620/
 * 42) http://energychinaforum.com/news/88918.shtml
 * 43) http://www.hellenicshippingnews.com/wp-content/uploads/2015/05/china_oil_basin_map.png
 * 44) http://boereport.com/2013/10/25/north-america-leads-the-world-in-production-of-shale-gas/
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 * 46) http://www.nexencnoocltd.com/en/Operations/OilSands.aspx
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 * 50) https://www.theguardian.com/environment/2011/nov/27/canada-oil-sands-uk-backing
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 * 52) http://www.bbc.co.uk/news/business-15889665
 * 53) http://www.rcinet.ca/en/2014/11/18/u-k-groups-protest-canadian-oilsands-lobbying/
 * 54) http://subscribe.energyandcapital.com/97584
 * 55) http://www.plus500.co.uk/Instruments/CL
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 * 59) http://berkshireoilinc.com/
 * 60) https://en.wikipedia.org/wiki/Oil_sands
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 * 62) http://ostseis.anl.gov/guide/tarsands/index.cfm
 * 63) https://en.wikipedia.org/wiki/Oil_sands
 * 64) https://en.wikipedia.org/wiki/Asphalt
 * 65) https://en.wikipedia.org/wiki/Synthetic_crude
 * 66) https://www.youtube.com/watch?v=86NG0j0wi1s
 * 67) https://en.wikipedia.org/wiki/Athabasca_oil_sands
 * 68) https://en.wikipedia.org/wiki/Oil_sands
 * 69) https://en.wikipedia.org/wiki/Oil_sands
 * 70) http://www.2b1stconsulting.com/boe/
 * 71) http://ostseis.anl.gov/guide/tarsands/
 * 72) http://www.oilsandsfactcheck.org/what-are-oil-sands/
 * 73) http://jobs.bakkenshale.com/
 * 74) https://en.wikipedia.org/wiki/Ploie%C8%99ti#Economy
 * 75) https://en.wikipedia.org/wiki/Operation_Tidal_Wave
 * 76) http://www.osti.gov/scitech/biblio/6567632
 * 77) http://www.southampton.ac.uk/~imw/Kimmeridge-Oil-Shale.htm
 * 78) https://www.geolsoc.org.uk/Groups-and-Networks/Specialist-Groups/History-of-Geology-Group/~/media/shared/documents/specialist%20and%20regional%20groups/hogg/hogg_weymouth%20abstract%20book.ashx
 * 79) http://one-potato-two-potato.blogspot.co.uk/
 * 80) http://www.hubbertpeak.com/laherrere/oilshalereview200509.pdf
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 * 82) http://www.sdnp.jo/International_Oil_Conference/rtos-A106.pdf
 * 83) https://e-reports-ext.llnl.gov/pdf/243505.pdf
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 * 88) https://fr.wikipedia.org/wiki/Mine_des_Télots