Oil sand , also known as asphalt sand or raw asphalt, or more technically asphalt sand , is an unconventional type of crude oil deposit. Oil sand is loose sand or partially consolidated sand containing a mixture of sand, clay, and water naturally, which is saturated with a solid and highly viscous petroleum form technically referred to as asphalt (or everyday language such as tar due to its apparent very similar).
Natural bitumen deposits are reported in many countries, but are especially found in very large numbers in Canada. Other large reserves are located in Kazakhstan, Russia, and Venezuela. World oil deposits estimate more than 2 trillion barrels (320 billion cubic meters); estimates include undiscovered deposits. The proven asphalt reserves contain about 100 billion barrels, and the total natural bitumen reserves are estimated at 249.67 Gbbl (39,694 ÃÆ'â € "span> 10 9 m 3 ) around the world, where 176.8 Gbbl (28.11 ÃÆ'â € " 10 9 m 3 ), or 70.8%, is in Alberta, Canada.
The raw asphalt contained in Canadian oil sands is described by the Canadian National Energy Board as "a very thick mixture of hydrocarbons heavier than pentane which, in its natural state, can not normally be recovered at commercial level through wells because it is too thick to flow." Raw asphalt is a thick and sticky form of crude oil, so heavy and thick (thick) that it will not flow unless heated or diluted with light hydrocarbons such as light crude or natural gas condensate. At room temperature, it's like cold molasses. The World Energy Council (WEC) defines natural asphalt as "oil having a viscosity greater than 10,000 sentipoise under reservoir conditions and an API weight of less than 10Ã, Â ° API". The Orinoco belt in Venezuela is sometimes described as oil sands, but these deposits are not bituminous, falling into the category of heavy oil or extra weight due to its lower viscosity. Natural bitumen and extra-heavy oil differ in degrees where they have been degraded from the original conventional oil by bacteria. According to WEC, extra-heavy oils have a "less than 10 Å ° API and a reservoir viscosity of no more than 10,000 centipoise".
Oil sand has recently been considered part of the world's oil reserves, as historically high oil prices and new technologies allow profitable extraction and processing. Together with the so-called non-conventional oil extraction practices, oil sands are involved in a non-combustible carbon debate, but also contribute to energy security and counteract the OPEC international price cartel. According to a study commissioned by the Government of Alberta, Canada, conducted by Jacobs Engineering Group, carbon emissions from crude oil-sand is 12% higher than that of conventional oil.
Video Oil sands
History
Exploitation of bituminous deposits and seeps dates back to the Paleolithic period. The earliest use of asphalt was discovered by Neanderthals, some 40,000 years ago. Bitumen has been found following the stone tools used by Neanderthals on sites in Syria. Upon the arrival of Homo sapiens, humans used asphalt for building construction and waterproofing of reeds, among other uses. In ancient Egypt, the use of asphalt was important in preparing Egyptian mummies.
In ancient times, asphalt was primarily a Mesopotamian commodity used by the Sumerians and Babylonians, though it was also found in the Levant and Persia. The areas along the Tigris and Euphrates rivers are filled with hundreds of pure bitumen bursts. Mesopotamia uses asphalt for boats and waterproofing buildings. In Europe, they were extensively mined near the French town of Pechelbronn, where the process of separation of steam was used in 1742.
Nomenclature
The name tar sands was applied to bitumen sand at the end of the nineteenth and early twentieth centuries. People who see bituminous sand during this period are familiar with the large number of tar residues produced in urban areas as a by-product of the manufacture of coal gas for urban heating and lighting. The word "tar" to describe these natural bitumen deposits is completely erroneous, because, chemically, tar is a manmade substance produced by destructive distillation of organic matter, usually coal.
Since then, coal gas has almost completely been replaced by natural gas as fuel, and coal tar as a material for asphalt road has been replaced by asphalt petroleum products. Bitumens that occur naturally are more similar to asphalt than coal tar, and the term oil sand is more commonly used by industry in producing areas than sand asphalt due to synthetic oil made of asphalt, and because of the feeling that the sand terminology is less politically accepted by the public. Oil sand is now an alternative to conventional crude oil.
Initial explorer
In Canada, the First Nation nations have used asphalt from seeps along the Athabasca and Clearwater Rivers to protect their birch bark from early prehistoric times. Canadian oil sands were first recognized by Europeans in 1719 when a native Cree named Wa-Pa-Su brought samples to the Hudsons Bay Company fur trader, Henry Kelsey, who commented on them in his journals. Peter Pond's feather merchant paddled the Clearwater River to Athabasca in 1778, looking at the sediment and writing about "asphalt springs flowing along the ground." In 1787, fur trader and explorer Alexander MacKenzie on his way to the Arctic Ocean saw Athabasca's oil sands, and commented, "Around 24 miles of forks (the Athabasca and Clearwater Rivers) are some bitumen fountains where a 20-foot Long pole can be inserted unhindered smallest. "
Pioneers
The commercial possibilities of large Canadian oil sands were embodied earlier by Canadian government researchers. In 1884, Robert Bell of the Canadian Geological Survey commented, "The banks at Athabasca will provide an inexhaustible supply of fuel... the material happens in very large quantities so a profitable way to extract oil... can found ". In 1915, Sidney Ells of the Federal Mining Branch experimented with separation techniques and used materials to open a 200-foot (200 m) avenue in Edmonton as well as elsewhere. In 1920, chemist Karl Clark of the Alberta Research Council began experimenting with methods to extract asphalt from oil sands and in 1928 he patented the first commercial hot water splitting process.
Commercial development began in 1923 when businessman Robert Fitzsimmons began drilling an oil well in Bitumount, north of Fort McMurray but gained disappointing results with conventional drilling. In 1927 he formed the International Asphalt Company and in 1930 built a small hot splitting plant based on Clark's design. He produced about 300 bbl (50 m mtpl) of asphalt in 1930 and delivered it with a barge and rail to Edmonton. Asphalt from the mine has many uses but is mostly used for waterproof roofing. The cost is too high and Fitzsimmons goes bankrupt. In 1941, the company changed its name to Oil Sands Limited and tried to solve technical problems but never succeeded. He experienced several changes of ownership and in 1958 was permanently closed. In 1974 Bitumount became the Provincial Site of Alberta Province.
In 1930, Max Ball entrepreneur formed Canadian Oil Sand Product, Ltd, which later became Abasand Oils. He built a separation plant capable of handling 250 tons of oil sands per day which opened in 1936 and produced an average of 200 bbl/d (30 m 3 /d) oil. The factory was burned at the end of 1941 but rebuilt in 1942 with a larger capacity. In 1943, the Canadian government took over the Abasand factory under the War of Action Act and planned to expand it further. But in 1945 the factory was burned again and in 1946 the Canadian government abandoned the project because the need for fuel had diminished with the end of the war. The Abasand Site is also an Alberta Historic Site.
Maps Oil sands
Geology
The largest oil sands deposits in the world are in Venezuela and Canada. The geology of sediments in both countries is generally somewhat similar. They are heavy heavy oils, extra heavy oils, and/or bitumen deposits with oils heavier than 20 Â ° APIs, most of which are found in uncon- solidated sandstones of the same nature. "Uncon Consolidated" in this context means the sand has high porosity, no significant cohesion, and tensile strength approaches zero. Sand is saturated with oil that has prevented them from consolidating into hard sandstone.
Resource size
The amount of resources in both countries is on the order of 3.5 to 4 trillion barrels (550 to 650 billion cubic meters) of original oil in place (OOIP). Oil in place does not always reserve oil, and the amount that can be produced depends on technological evolution. Rapid technological developments in Canada in the period 1985-2000 resulted in techniques such as steam-assisted gravity drainage (SAGD) that can recover a much larger OOIP percentage than conventional methods. The Alberta government estimates that with the current technology, 10% of asphalt and heavy oil can be recovered, which will provide about 200 billion barrels (32 billion m 3 ) of recoverable oil reserves. Venezuela estimates its recoverable oil at 267 billion barrels (42 billion m 3 ). It puts Canada and Venezuela in the same league as Saudi Arabia, has three of the largest oil reserves in the world.
Primary deposit
There are many deposits of oil sands in the world, but the biggest and most important ones are in Canada and Venezuela, with fewer deposits in Kazakhstan and Russia. The total volume of non-conventional oils in the oil sands of these countries exceeds the conventional oil reserves in all other countries combined. A large number of bitumens - more than 350 billion cubic meters (2.2 trillion barrels) of oil in place - exist in the provinces of Alberta and Saskatchewan in Canada. If only 30% of this oil can be extracted, it could supply all of North America's needs for more than 100 years at the level of consumption in 2002. These deposits represent abundant oil, but not cheaply. They need advanced technology to extract oil and transport it to an oil refinery.
Canada
The oil sands of the Western Canadian Sedimentary Basin (WCSB) are the result of the formation of the Canadian Rocky Mountains by the Pacific Plate which overshadowed the North American Plate when driven from the west, carrying a chain of formerly large islands now composed of British Columbia. The collision hit the Alberta plains and lifted the Rockies over the plains, forming mountains. The process of building this mountain bury the layers of sedimentary rocks that underlie most of Alberta to a very deep depth, creating a high subsurface temperature, and producing a gigantic pressure cooker effect that transforms kerogens in rich organic flakes that are buried into light oil and natural gas. These source rocks are similar to so-called American oil shales, except that the latter is never buried deep enough to turn the kerogen into it into liquid oil.
This overthrusting also tilts the pre-lime sedimentary rock formations that underlie most of the Alberta sub-surface, suppressing rock formations in southwestern Alberta up to 8 km (5 mi) away near the Rockies, but to a depth of zero in the northeast, where they clamp the frozen stones of the Canadian Shield, exposed on the surface. This slope is not visible on the surface because the resulting moat has been filled by eroded material from the mountains. Light oils migrate upwards through the hydro-dynamic transport of the Rockies in the southwest to the Canadian Shield in the northeast following the pre-Cretaceous unsealed in the formations below Alberta. The total migration distance of southwest oil to the northeast is about 500 to 700 km (300 to 400 mi). At shallow depth of sediment formation in the northeast, biodegradation of very large microbes when oil approaches the surface causes the oil to become very thick and immobile. Almost all remaining oil is found at the northern end of Alberta, in Central Kalimantan limestone silt-shale deposits (115 million years) overlaid by thick flakes, although large amounts of heavy oil lighter than asphalt are found in Heavy Oil Belts along the Alberta-Saskatchewan , extending into Saskatchewan and approaching the Montana border. Note that, although adjacent to Alberta, Saskatchewan does not have a massive deposit of asphalt, only a large reservoir of heavy oil & gt; 10Ã, Â ° API.
Most of Canada's oil sands are located in three main deposits in northern Alberta. They are the Athabasca-Wabiskaw oil sands in northeastern Alberta, Cold Lake sediments northeast of eastern Alberta, and the sediment of the Peace River in northwest Alberta. Among them, they cover more than 140,000 square kilometers (54,000 sq./a mi) - an area larger than the UK - and contain about 1.75 Tbbl (280 ÃÆ'â € " 10 9 m 3 ) from the raw asphalt in it. About 10% of the oil in place, or 173 Gbbl (27.5 ÃÆ'â € 10 9
Canada's largest oil sands deposit, Athabasca oil sands is in the McMurray Formation, centered in the town of Fort McMurray, Alberta. This surface outcrop (zero burial depth) is about 50 km (30 mi) north of Fort McMurray, where a large oil sands mine has been erected, but 400 m (1,300 ft) south east of Fort McMurray. Only 3% of the oil sands area contains about 20% of the recoverable oil that can be produced by surface mining, so the remaining 80% must be produced using in-situ wells. Another Canadian deposit is between 350 to 900 m (1,000 to 3,000 ft) deep and will require in-situ production.
Athabasca
The Athabasca oil sand stretches along the Athabasca River and is the largest natural bitumen deposit in the world, containing about 80% of the Alberta total, and the only suitable for surface mining. With modern non-conventional oil production technology, at least 10% of these deposits, or about 170 Gbbl (27 ÃÆ'â € "span> 10 9 m 3 ) is considered economically recoverable, making Canada the world's third largest proven reserve in the world, after conventional Saudi Arabian oil and Venezuela's Orinoco sand oil.
The Athabasca oil sands are more or less centered around the far northern town of Fort McMurray. They are by far the largest deposit of bitumen in Canada, probably containing more than 150 billion cubic meters (900 billion barrels) of oil in place. Asphalt is very thick and often denser than water (10 Â ° API or 1000 kg/m 3 ). The saturated sand of oil ranges from 15 to 65 meters (49 to 213Ã.ft) thick in some places, and oil saturation in the oil-rich zone is on the order of 90% of the asphalt weight.
The Athabasca River pierces the heart of the deposit, and a heavy oil trail is readily observed as a black spot on the banks of the river. Since parts of the Athabasca sand are shallow enough to be mined on the surface, they are the earliest to see the development. Historically, bitumen was used by indigenous Cree and Aboriginal Dene to protect their canoes. The Athabasca oil sands first became the concern of European feather merchants in 1719 when Wa-pa-su, a Cree merchant, brought samples of asphalt sand to the Hudson Bay Company post at the York Plant in Hudson Bay.
In 1778, Peter Pond, a feather trader for a competing Northwest Company, was the first European to see Athabasca's stock. In 1788, fur trader and explorer Alexander Mackenzie of the Hudson Bay Company, who later discovered the Mackenzie River and routes to the Arctic and Pacific Oceans, described the oil sands in great detail. He said, "Around 24 miles (39 km) from a fork (Athabasca and Clearwater Rivers) are some tar fountains where a 20-foot long (6.1 m) long pole can be inserted without any resistance. when mixed with chewing gum, the resin substance collected from fir spruce, it serves to soothe the Indians.
In 1883, G.C. Hoffman of the Canadian Geological Survey tried to separate the asphalt from the oil sands by using water and reported that it was separated easily. In 1888, Robert Bell of the Canadian Geological Survey reported to the Senate Committee that "Evidence... shows existence in Athabasca and Mackenzie valleys from the most extensive oil field in America, if not the world." In 1926, Karl Clark of the University of Alberta patented a process of splitting hot water which is the pioneer of the current thermal extraction process. However, in 1967 before the first large-scale commercial operation began with the opening of the Great Canadian Oil Sands mine by the Sun Oil Company of Ohio.
Today its successor, Suncor Energy (no longer affiliated with Sun Oil), is Canada's largest oil company. In addition, other companies such as Royal Dutch Shell, ExxonMobil, and various national oil companies are developing the Athabasca oil sands. As a result, Canada is by far the largest oil exporter to the United States.
The smaller Wabasca (or Wabiskaw) oil sands are above the west bank of Athabasca oil sands and overlap with them. They may contain more than 15 billion cubic meters (90 billion barrels) of oil in place. This deposit is buried from a depth of 100 to 700 meters (330 to 2,300Ã, ft) and ranges from 0 to 10 meters (0 to 33Ã, ft) thick. In many areas, oil-rich Wabasca formation underscores the oil-rich formation of McMurray, and as a result two overlapping oil sands are often treated as a deposit of oil sands. However, the two precipitates are unchanged separated by a minimum of 6 meters (20Ã, ft) of clay and clay deposits. The asphalt in Wabasca is very thick as in Athabasca, but it lies too deep to be mined on the surface, so that in-situ production methods must be used to produce raw asphalt.
Cold Lake
Cold Lake oil sand is located in the northeast of Alberta's capital, Edmonton, near the border with Saskatchewan. A small part of the Cold Lake deposit is located in Saskatchewan. Although smaller than the Athabasca oil sands, Cold Lake oil sands are important because some of the oil is sufficiently liquid to be extracted by conventional methods. Asphalt Cold Lake contains more alkanes and less asphalt than any other major Alberta oil sands and more liquid oil. As a result, cyclic steam stimulation (CSS) is generally used for production.
The Cold Lake oil sand is a rough circle, centered around Bonnyville, Alberta. They may contain more than 60 billion cubic meters (370 billion barrels) of extra heavy oil in place. The oil is very thick, but much less than the Athabasca oil sands, and somewhat less sulfuric. Depth of storage is 400 to 600 meters (1300 to 2,000 feet) and thickness between 15 to 35 meters (49 to 115 feet). They're too deep to mine mine.
Most of the oil sands are in the Canadian Forces, Base Cold Lake. The CF-18 Hornet CFB Cold Lake fighter jets defend the western half of Canada's airspace and covers the Arctic region of Canada. The range of Cold Lake Wind Guns (CLAWR) is one of the largest ranges of live-drop bombs in the world, including cruise missile testing. As oil sand production continues to grow, various sectors compete for access to air space, soil, and resources, and this makes it difficult to drill oil and production well.
Peace River
The Pacific River oil sands located in northwest-northwest Alberta are the smallest of the three major oil sands deposits in Alberta. The Peace River sands are generally located in the Peace River basin, the largest river in Alberta. The River of Peace and Athabasca, which is by far the largest river in Alberta, flows through each oil sands and joins on Lake Athabasca to form the Slave River, which flows into the MacKenzie River, one of the largest rivers in the world. All the water from these rivers flows into the Arctic Ocean.
The River's Peace River oil may contain more than 30 billion cubic meters (200 billion barrels) of oil-in-place. The thickness of the sediment ranges from 5 to 25 meters (16 to 82 feet) and is buried about 500 to 700 meters (1,600 to 2,300 feet).
While the Athabasca oil sands are located close enough to the surface that the asphalt can be dug in the open pit, the smaller Peat River sediments are too deep, and should be exploited using in situ methods such as steam assisted gravity drainage and Cold Heavy. Production of Oil with Sand (CHOPS).
Venezuela
The Venezuelan Basin has a structure similar to WCSB, but on a shorter scale. The oil spacings have migrated upwards from the Sierra Orientale mountain slope to the Orinoco oil sands where it pinches against the frozen rocks of the Guyana Shield only around 200 to 300 km (100 to 200 mi). The hydrodynamic conditions of oil transportation are similar, the source rocks embedded in by the emergence of the Sierra Orientale mountains produce light oils moving southward, gradually immobilized by increased viscosity caused by near surface biodegradation. Orinoco deposits are the sequence of early-silt-shale sand rocks (50 to 60 million years old) that are overlapped by continuous thick bits, similar to Canadian deposits.
In Venezuela, Orinoco Belt oil sands range from 350 to 1,000 m (1,000 to 3,000 feet) deep and no outcrops exist. This deposit is about 500 km (300 mi) long from east to west and 50 to 60 km (30 to 40 mi) wide north-to-south, far less than the combined area covered by Canadian deposits. In general, Canada's deposits are found in much larger areas, have a wider range of properties, and have larger reservoir types than those in Venezuela, but similar geological structures and mechanisms are similar. The main difference is that oil in the sand in Venezuela is less viscous than in Canada, allowing some of it to be produced by conventional drilling techniques, but nothing approaches the surface as in Canada, meaning that nothing can be produced using surface mining. Canadian deposits will almost all be produced by mining or using new non-conventional techniques.
Orinoco
The Orinoco Belt is a region in the southern strip of the Orinoco River Basin in Venezuela that underlines one of the world's largest oil deposits. The Orinoco Belt follows the river line. It is about 600 kilometers (370 miles) from east to west, and 70 kilometers (43 mi) from north to south, with an area of ​​about 55,314 square kilometers (21,357 square meters).
Oil sand consists of large deposits of extra heavy crude oil. Venezuela's heavy oil deposits around 1,200 Gbbl (190 ÃÆ'â € 10
In 2009, the US Geological Survey (USGS) increased its estimated reserves to 513 Gbbl (81.6 ÃÆ'â € 10 9 m 3 ) of "technically recoverable" oil (available using current industry technology and practice). " There is no estimate of how much oil can be recovered economically. Other deposits
In addition to the three major Canadian oil sands in Alberta, there is a fourth large sandstone deposit in Canada, Melville Island oil sands on the Canadian Arctic archipelago, which is too far away to expect commercial production in the future.
Regardless of the megagiant oil reserves in Canada and Venezuela, many other countries have smaller reserves of oil sands. In the United States, there is a source of supergiant oil sands mainly concentrated in East Utah, totaling 32 Gbbl (5.1 ÃÆ'â € 10 9 xm 3 ) of the oil (known and potential) in eight major deposits in Carbon, Garfield, Grand, Uintah, and Wayne County. In addition to much smaller than Canadian oil sands deposits, US oil sands are wet-hydrocarbons, while Canadian oil sands are wet water. This requires a slightly different extraction technique for Utah oil sands than those used for Alberta oil sands.
Russia has oil sands in two main areas. Large resources are present in the Tunguska Basin, East Siberia, with the largest deposits being Olenek and Siligir. Other deposits are located in the basin of Timan-Pechora and Volga-Uals (in and around Tatarstan), which is an important but very mature province in terms of conventional oil, storing large quantities of oil sands in shallow permian formations. In Kazakhstan, large bitumen deposits are located in the North Caspian Basin.
In Madagascar, Tsimiroro and Bemolanga are two heavy oil sands of oil, with pilots already producing oil in small quantities in Tsimiroro. and large-scale exploitation in the early planning phase. In the Republic of Congo the reserves are estimated between 0.5 and 2.5 Gbbl (79 ÃÆ'â € " 10 < soup> 6 and 397 10 6 m 3 ).
Production
Asphalt sand is a major source of non-conventional oil, although only Canada has a large-scale commercial oil sands industry. In 2006, asphalt production in Canada averaged 1.25 Mbbl/d (200,000 m 3 /d) through 81 oil sands projects. 44% of Canada's oil production in 2007 came from oil sands. This proportion (in 2008) is expected to increase in the coming decades as asphalt production grows while conventional oil production declines, although due to the 2008 economic downturn, work on new projects has been suspended. Oil is not produced from oil sands at a significant level in other countries.
Canada
The oil sands of Alberta have been in commercial production since the original Canadian Yellow Oil mines (now Suncor Energy) began operations in 1967. Despite the increased production levels, the extraction and processing of oil sands can still be considered to be in its infancy; with new technology and stakeholder oversight providing an ever-lower environmental footprint. The second mine, operated by the Syncrude consortium, began operations in 1978 and is the largest mine of any type in the world. The third mine at Athabasca Oil Sands, an Albian Sands consortium from Shell Canada, Chevron Corporation, and Western Oil Sands Inc. [purchased by Marathon Oil Corporation in 2007] commenced operations in 2003. Petro-Canada is also developing the $ 33 billion Fort Hills Project, in partnership with UTS Energy Corporation and Teck Cominco, who lost momentum after the 2009 Petro-Canada merger to Suncor.
In 2013 there are nine oil sands mining projects in the Athabasca oil sands deposit: Suncor Energy Inc. (Suncor), Syncrude Canada Limited (Syncrude) Mildred Lake and Aurora North, Shell Canada Limited (Shell) Muskeg and Jackpine Rivers, Natural Resources Canada Limited (CNRL), Horizon, Imperial Ventures (Imperial) Oil Resources, Sand Project Kearl Oil (KOSP), Total E & amp; P Canada Ltd. Northern Mine Joslyn and Fort Hills Energy Corporation (FHEC). In 2011 alone they produced more than 52 million cubic meters of asphalt.
Venezuela
There was no significant development of Venezuela's extra-heavy oil deposits made before 2000, except for BITOR operations that produced less than 100,000 barrels of oil per day (16,000 m 3 /d) of 9Ã, API oil by primary production. It is mostly shipped as an emulsion (Orimulsion) of 70% oil and 30% water with similar characteristics as heavy fuel oil for combustion in thermal power plants. However, when a large strike hit the Venezuelan state oil company PDVSA, most of the engineers were dismissed as punishment. Orimulsion has become the pride of PDVSA engineers, so Orimulsion is disliked by the main political leaders. As a result, the government has tried the "Wind Down" Orimulsion program.
Despite the fact that Orinoco oil sands contain extra heavy oils that are easier to produce than Canadian-sized bituminous reserves, Venezuela's oil production has declined in recent years due to the country's political and economic problems, while Canada has increased. As a result, Canada's huge oil and bitumin exports have supported heavy and heavy oil from Venezuela in the US market, and Canada's total oil exports to the US have become several times larger than Venezuela.
By 2016, with Venezuelan economies in chaos and food shortages, power cuts, riots and anti-government protests, it is not clear how much new oil sands production will occur in the near future.
Other countries
In May 2008, Italian oil company Eni announced a project to develop a small oil sands deposit in the Republic of Congo. Production is scheduled to begin in 2014 and is expected to produce a total of 40,000 bbl/d (6,400 m 3 /d).
Extraction method
Except for the fraction of oil or extra-heavy asphalt that can be extracted with conventional well oil technology, oil sands must be produced by mining or oil made flowing into wells using state-of-the-art techniques. These methods usually use more water and require more energy than conventional oil extraction. While many Canadian oil sands are produced using open pit mining, about 90% of Canadian oil sands and all of Venezuela's oil sands are too far below the surface to use surface mining.
Primary production
Conventional crude oil is usually extracted from the ground by drilling an oil well into an oil reservoir, allowing the oil to flow into it under natural reservoir pressure, although artificial removal and techniques such as horizontal drilling, water flooding and gas injection are often necessary to maintain production.. When primary production is used in the oil sands of Venezuela, where extra-heavy oil is about 50 degrees Celsius, the oil recovery rate is generally around 8-12%. Canadian oil sand is much cooler and more biodegradable, so asphalt recovery rate is usually only about 5-6%. Historically, primary recovery was used in the more liquid areas of Canadian oil sands. However, it only restores a small part of the oil in its place, so it is not often used today.
Surface mining
The Athabasca oil sand is the only major oil sludge that is shallow enough to mine the mine. In the Athabasca sands, there are numerous asphalt covered by excess soil layers, making surface mining the most efficient method of extraction. Overburden consists of muskeg containing water (peat peat) on clay and barren sand. The oil sand itself is usually 40 to 60 meters (130 to 200 feet) thick of raw asphalt deposits embedded in unconsolidated sandstone, sitting on flat limestone. Since Great Canadian Oil Sands (now Suncor Energy) started the operation of the first large-scale oil sands in 1967, bitumen has been extracted on a commercial scale and its volume has grown steadily ever since.
A large number of oil sands are currently operating and many more are in the approval or development stage. The Syncrude Canada Mine was the second to open in 1978, Shell Canada opened the Muskeg River (Albian Sands) mine in 2003 and Canadian Natural Resources Ltd (CNRL) opened the Horizon Oil Sands project in 2009. The new mine includes the Canadian Shell Mine, Imperial Oil's Kearl Oil Sands project, Synenco Energy (now owned by Total SA) of Northern Lights mine, and Suncor's Fort Hills mine.
Pond oil tailings pond
Tailings of oil mine tailings are engineered dam and embankment system containing salt, suspended solids and other soluble chemical compounds such as naphthenic acid, benzene, residual hydrocarbon bitumen, fine mud (MFT soft ripen), and water. The large volume of tailings is a byproduct of surface mining of oil sands and managing these tailings is one of the most difficult environmental challenges facing the oil sands industry. The Alberta government reported in 2013 that the tailings pool in Alberta oil sands covers an area of ​​approximately 77 square kilometers (30 m²). The Syncrude Tailings Dam or Mildred Lake Settling Basin (MLSB) is an embankment dam that, based on the volume of construction material, the world's largest earth structure in 2001.
Production of Heavy Cold Oil with Sand (CHOPS)
A few years ago Canadian oil companies discovered that if they released sand filters from heavy oil wells and produced as much sand as possible with oil, the production rate increased significantly. This technique is known as Cold Heavy Oil Production with Sand (CHOPS). Further research reveals that pumping out the sand opens a "wormhole" in a sand formation that allows more oil to reach the wellbore. The advantage of this method is better production rates and recovery (about 10% versus 5-6% with on-site sand filters) and the resulting losses from sand produced are a problem. A new way to do this is to spread it on rural roads, favored by the village government as the oily sand reduces the dust and oil companies do their road maintenance. However, the government has been concerned about the large volume and composition of oil deployments on the road. so in recent years throwing oily sand in the underground salt caves has become more common. Cyclic_Steam_Stimulation_ (CSS) "> Cyclic Steam Stimulation (CSS)
The use of steam injection to recover heavy oil has been used in California oil fields since the 1950s. The cuff-huff-and-puff cyclic (HSS) cyclic stimulation method is now widely used in heavy oil production worldwide due to the rapid initial production rate; However the recovery factor is relatively low (10-40% oil in place) compared to SAGD (60-70% of OIP).
CSS has been used by Imperial Oil in 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, wells are introduced through steam injection cycles, soak, and oil production. First, steam is injected into the well at a temperature of 300 to 340 degrees Celsius for several weeks to months; then, the well is allowed to sit for days to weeks to allow the heat to seep into the formation; and, later, hot oil is pumped out of the well for several weeks or months. After the production level falls, the well is inserted through the injection cycle, soak, and other production. This process is repeated until the cost of steam injection becomes higher than the money generated from oil production.
Steam Gravity Channel (SAGD)
Steam-assisted gravity drainage was developed in 1980 by Alberta Oil Sands Technology and the Research Authority and coincidentally coincided with improvements in directed drilling technology that made it fast and cheap to do in the mid-1990s. In SAGD, two horizontal wells are drilled in oil sands, one at the base of the formation and the other about 5 meters above it. These wells are usually drilled in groups from the central bearing and can extend for miles in all directions. In each pair of wells, the steam is injected into the top well, the heat melts the asphalt, allowing it to flow into the bottom well, where it is pumped to the surface.
SAGD has proven to be a major breakthrough in production technology because it is cheaper than CSS, enabling extremely high oil production rates, and recovering up to 60% of the oil in place. Because of its economic viability and its application to the vast area of ​​oil sands, this method alone doubles North American oil reserves and allows Canada to move into second place in world oil reserves after Saudi Arabia. Most Canadian oil companies now have SAGD projects in production or are being built in the oil sands of Alberta and in Wyoming. Examples include the projects of Japan Canada Oil Sands Ltd (JACOS), the Firebag Suncor project, the Long Lake Nexen project, Suncor's MacKay River project (formerly Petro-Canada), Husky Energy's Tucker Lake and Sunrise Project, the Peace River project from Shell Canada, Cenovus Energy's Foster Creek and the development of Christina Lake, the Surmont ConocoPhillips project, the Devon Canada Jackfish project, and Derek Oil & amp; LAK Ranch Gas Project. OSUM Corp. Alberta has incorporated proven underground mining technology with SAGD to enable higher recovery rates by running underground wells from within the oil sands deposit, thereby also reducing energy requirements compared to traditional SAGD. This special technology application is in the testing phase.
Steam Extraction (VAPEX)
Some methods use solvents, not steam, to separate asphalt from sand. Several methods of solvent extraction work better in in situ production and others in mining. Solvents can be beneficial if producing more oil while requiring less energy to produce steam.
The Steam Extraction Process (VAPEX) is an in situ technology, similar to SAGD. Instead of steam, the hydrocarbon solvent is injected into the top well to dilute the asphalt and allow the diluted bitumen to flow to the lower well. It has a much better energy efficiency advantage than steam injection, and does some partial increase of asphalt to the right of the oil in the formation. The process has attracted the attention of the oil companies, who experimented with it.
The above methods are not mutually exclusive. It is common for wells to be incorporated through a single CSS-injection production cycle to condition formation before going to SAGD production, and the company experiments with incorporating VAPEX with SAGD to improve recovery rates and lower energy costs.
Foot to Heel Air Injection (THAI)
This is a very new and experimental method that incorporates vertical air injection wells with horizontal production well. This process burns the oil in the reservoir and creates a vertical flame wall that moves from the "end" of the horizontal well toward the heel, which burns heavier oil components and increases some of the heavy bitumen into light oils right in the formation.. Historically forest fire projects have not gone well because of difficulties in controlling the fire front and the tendency to regulate burning production wells. However, some oil companies feel that the THAI method will be more controllable and practical, and has the advantage of not requiring energy to create steam.
Proponents of this method of extraction claim that it uses less fresh water, produces 50% less greenhouse gases, and has a smaller footprint than other production techniques.
Petrobank Energy and Resources has reported encouraging results from their test well in Alberta, with production rates up to 400 bbl/d (64 m 3 /d) per well, and oil increased from 8 to 12 API Degrees. The company hopes to get a further 7 degree increase from the CAPRI system (infusion of atmospheric pressure), which attracts the oil through the catalyst lining the bottom pipe.
After several years of in situ production, it has become clear that the current THAI method is not working as planned. In the midst of a steady decline in production from their THAI well in Kerrobert, Petrobank has written down their THAI patents and reserves at the facility to zero. They have plans to experiment with new configurations they call "multi-THAI," which involves adding more air injection wells.
Burning Overhead Gravity Drainage (COGD)
This is an experimental method that uses a number of vertical air injection wells above the horizontal production well located at the bottom of the asphalt payment zone. The initial Steam Cycle is similar to CSS used to prepare the asphalt for ignition and mobility. After that cycle, the air is injected into the vertical well, triggering the upper asphalt and mobilizing (through heating) the lower asphalt to flow into the production well. COGD is expected to generate water savings of 80% compared with SAGD.
Energy balance
Approximately 1.0-1.25 gigajoules (280-350 kWh) of energy is needed to extract one barrel of bitumen and upgrade to synthetic crude. In 2006, most were produced by burning natural gas. Since an oil equivalent barrel is about 6,117 gigajoules (1,699 kWh), its EROEI is 5-6. That means the extract is about 5 or 6 times more energy consumed. Energy efficiency is expected to increase to an average of 900 cubic feet (25 m 3 ) of natural gas or 0.945 gigajoules (262 kWh) of energy per barrel by 2015, giving EROEI about 6.5.
Alternatives to natural gas exist and are available in the area of ​​oil sands. Bitumen alone can be used as fuel, consuming about 30-35% of the raw bitumes per unit produced from synthetic crude oil. The Long Lake Nexen project will use special deasphalting technology to increase the asphalt, using asphaltene residues fed to a gasifier syngas that will be used by cogeneration turbines and hydrogen generating units, providing all the energy needs of the project: steam, hydrogen, and electricity. Thus, it will produce syncrude without consuming natural gas, but the cost of capital is very high.
The shortage of natural gas for project fuels is expected to be a problem for Canadian oil sands production a few years back, but the recent increase in US shale gas production has eliminated many problems for North America. With increasing use of hydraulic fractures making the US largely self-sufficient in natural gas and exporting more natural gas to eastern Canada to replace Alberta gas, the Alberta government uses its power under NAFTA and the Canadian Constitution to reduce natural gas shipments to the US and East Canada and divert gas to Alberta's domestic use, especially for fuel-oil sand. Natural gas pipelines to the east and south are being converted to bring increased oil sand production to these destinations in lieu of gas. Canada also has large undeveloped shale gas reserves other than the US, so natural gas for future oil sand production does not seem to be a serious problem. The low price of natural gas as a result of new production has greatly improved the oil production of oil sands.
Upgrade and/or blend
Extra-heavy or raw bituminous crude extracted from oil sands is a very viscous semisolid form that does not flow easily at normal temperatures, making it difficult to transport to the market through pipelines. To flow through oil pipelines, it must be upgraded to lightweight synthetic crude (SCO), mixed with diluents to form dillit, or heated to reduce its properties.
Canada
In Canadian oil sands, the asphalt produced by surface mining is generally upgraded on-site and delivered as synthetic crude oil. This makes oil deliveries to the market through conventional oil pipelines quite easy. On the other hand, bitumes generated by in-situ projects are generally not improved but delivered to the market in raw form. If an agent used to upgrade bitumes to synthetic crude is not produced on the site, it should be sourced elsewhere and transported to the upgrade site. If upgraded crude is transported from the site through pipelines, and additional pipes will be required to bring in sufficient upgrade agents. The cost of producing the improvement agent, the pipe to transport it and the cost to operate the pipe must be calculated into the production cost of synthetic crude.
Upon reaching the refinery, synthetic crude is processed and most of the improvement agents will be removed during the refining process. This can be used for other fuel fractions, but the end result is that the liquid fuel must be channeled to the upgrade facility just to make the asphalt can be transported by pipeline. If all costs are considered, the production and transfer of synthetic crude oil using asphalt and enhancement agents can prove economically unsustainable.
When the first oil sands factory was built more than 50 years ago, most of the refineries in their market area were designed to handle light or medium crude oils with lower than 4-7% sulfur content normally found in bitumens. The original oil sands processor is designed to produce high quality synthetic crude oil (SCO) with low density and lower sulfur content. This is a large and expensive plant that is similar to a heavy oil refinery. Research is currently underway to design simple upgraders that do not produce SCO but only treat asphalt to reduce its viscosity, allowing it to be transported unhindered like conventional heavy oils.
Western Canadian Select, launched in 2004 as a new heavy oil stream, mixed at the Husky Energy terminal in Hardisty, Alberta, is the largest flow of crude oil derived from Canadian oil sands and a benchmark for heavy heavy (heavy) US crude.. WCS is traded in Cushing, Oklahoma, the main oil supply center that connects oil suppliers to the Gulf Coast, which has become the most significant trading hub for North American crude. While the main component is asphalt, it also contains a combination of synthetic sweetener and condensate sweetener, and 25 existing streams of both conventional and nonconventional oils that make it a sindilbit - both dile and synbit.
The first step in the improvement is the vacuum distillation to separate the lighter fractions. After that, de-asphalting is used to separate the asphalt from raw materials. Cracking is used to break up heavy hydrocarbon molecules to be simpler. Because cracking produces sulfur-rich products, desulfurization should be done to obtain sulfur content below 0.5% and create a sweet and light synthetic crude.
In 2012, Alberta produces about 1,900,000 bbl/d (300,000 m 3 /d) of raw asphalt from its three main oil sands, of which about 1,044,000 bbl/d (166,000 m 3 /d) is upgraded to lighter products and the rest is sold as raw bitumes. Increased and non-upgraded asphalt volume increases every year. Alberta has five oil-processing oils producing various products. These include:
- Suncor Energy can raise 440,000 bbl/d (70,000 m 3 /d) bitumen to light sweet and medium sized crude oil (SCO), plus produce diesel fuel for its oil sand operations in upgrader.
- Syncrude can raise 407,000 bbl/d (64,700 m 3 /d) from bitumen to lightweight SCO.
- Canadian Natural Resources Limited (CNRL) can increase 141,000 bbl/d (22,400 m 3 /d) from bitumen to lightweight SCO.
- Nexen, since 2013 wholly owned by China National Offshore Oil Corporation (CNOOC), can increase 72,000 bbl/d (11,400 m 3 /d) from bitumen to lightweight SCO.
- Shell Canada operates its Scotford Upgrader combined with an oil refinery and chemical plant in Scotford, Alberta, near Edmonton. This complex can increase 255,000 bbl/d (40,500 m 3 /d) the asphalt into a sweet and heavy SCO as well as various refineries and chemical products.
Modern and new modern refineries such as those found in the United States of the Middle West and in the Gulf Coast of the United States, as well as many in China, can handle the increase in heavy oil itself, so their demand is for non-enhanced and extra-heavy oil asphalt SCO. The main problem is that the raw materials will be too thick to flow through the pipes, so unless it is delivered by a tanker or train, it should be mixed with the diluent to allow it to flow. This requires mixing raw asphalt with lighter hydrocarbon diluents such as condensate from gas wells, pentanes and other light products from oil refineries or gas mills, or synthetic crude from oil-processing processors to enable it to flow through pipelines to the market.
Typically, mixed asphalt contains about 30% natural gas condensate or other diluents and 70% bitumen. Alternatively, asphalt can also be delivered to the market by specially designed rail tankers, tank trucks, liquid cargo tanks, or marine oil tankers. This does not necessarily require asphalt mixed with diluents because the tank can be heated to allow the oil to be pumped out.
The demand for condensate for oil-sand diluents is estimated to be more than 750,000 bbl/d (119,000 m 3 /d) by 2020, the double volume of 2012. Because Western Canada produces only about 150,000 bbl/d (24,000 m 3 /d) condensate, supply is expected to be a major constraint on bitumen transport. However, a major increase in US tight oil production has recently solved this problem, as most of the production is too light for the use of US refineries, but ideal for thinning asphalt. The excess of American condensate and light oil is exported to Canada and mixed with asphalt, and then imported back into the US as raw material for refineries. Since the diluent is only exported and then immediately re-imported, it is not subject to US ban on crude oil exports. Upon returning to the US, refineries separate the diluents and re-export them to Canada, which again violates US crude oil export laws because it is now a refinery product. To assist in this process, Kinder Morgan Energy Partners reverses its Cochin Pipeline, used to carry propane from Edmonton to Chicago, to transport 95,000 bbl/d (15,100 m 3 /d) condensate from Chicago to Edmonton in mid 2014; and Enbridge is considering expanding the South Lamp pipe, which currently ships 180,000 bbl/d (29,000 m 3 /d) diluents from the Chicago area to Edmonton, adding another 100,000 bbl/d (16,000m < > 3 /d).
Venezuela
Although Venezuela's extra-heavy oil is less viscous than Canadian asphalt, much of the difference is due to the temperature. Once the oil is out of the ground and cools down, it has the same difficulty because it is too thick to flow through the pipeline. Venezuela is now producing more extra crude oil in Orinoco oil sands than its four upgraders, built by foreign oil companies more than a decade ago, can handle. The upgraders have a combined capacity of 630,000 bbl/d (100,000 m 3 /d), which is only half of the extra-heavy oil production. In addition, Venezuela produces inadequate naphtha volume to be used as a diluent to move extra heavy oil to the market. Unlike Canada, Venezuela does not produce much of its natural gas condensate from its own gas well, and unlike Canada, it does not have easy access to condensate from the new US shale gas production. Since Venezuela also has inadequate refinery capacity to supply its domestic market, naptha supplies are not sufficient to be used as pipeline diluents, and it must import naphtha to fill the gap. Since Venezuela also has financial problems - as a result of the country's economic crisis - and political disagreements with the US government and oil companies, the situation remains unsolved.
Transportation
The collection and feeder pipe network collects raw asphalt and SCO from Northern Alberta's sandstone deposits (mainly Athabasca, Cold Lake, and Peace River), and gives them two main collection points for shipping south: Edmonton, Alberta and Hardisty, Alberta. Most feeder pipes move the mixed asphalt or SCO to the south and diluent to the north, but some products move laterally within the oil sands region. In 2012, the feeder feeder capacity to the south is over 300,000 mÃ,³/d (2 million bbl/d) and more capacity is being added. The construction of new oil-sanding pipe only requires approval from Alberta Energy Regulator, an agency that handles the full problems in Alberta and is likely to pay little attention to the disruption of political and environmental interests outside of Alberta.
Existing pipeline
From Edmonton and Hardisty, major transmission pipes move asphalt and SCO, as well as conventional crude and various oil and natural products to market destinations throughout North America. The main transmission systems include:
- Enbridge has an existing elaborate piping system that takes crude oil from Edmonton and Eastern Hardisty to Montreal and south as far as the Gulf Coast of the United States, with a total capacity of 2.5 ÃÆ'â € 10 6 bbl/d (400,000 m 3 /d). It also has a northern pipe line that takes evaporation from refineries in Illinois and other Midwestern states to Edmonton with a capacity of 160,000 bbl/d (25,000 m 3 /d) light hydrocarbons.
- Kinder Morgan has a Trans Mountain Pipeline that takes crude oil from Edmonton over the Rocky Mountains to the west coast of British Columbia and Washington State, with an existing capacity of 300,000 bbl/d (48,000 m 3 /d ). It has plans to add an additional 450,000 bbl/d (72,000 m 3 /d) capacity to this pipe in the ease of existing pipeline.
- Spectra Energy has a pipeline system that takes crude oil from Hardisty south to Casper, Wyoming and then east to Wood River, Illinois. The first segment has a capacity of 280,000 bbl/d (45,000 m 3 /d) and a second segment of 160,000 bbl/d (25,000 m 3 /d).
- TransCanada Corporation has a Keystone Pipeline system. Phase 1 is currently taking crude oil from southern Hardisty to Steele City, Nebraska and then east to Wood River, Illinois. The existing Phase 2 moves crude oil from Steele City to a major US oil marketing center in Cushing, Oklahoma. Phases 1 and 2 have a combined capacity of 590,000 bbl/d (94,000 m 3 /d).
Overall, the total pipeline capacity for crude oil movements from Edmonton and Hardisty throughout North America is about 3.5 ÃÆ'â € "span> 10 6 bbl/d (560,000 m 3 /d). However, other substances such as conventional crude oil and pure oil products also share this pipeline. The rapidly rising oil production from Bakken formation from North Dakota also competes for space in Canada's export pipeline system. North Dakota oil producers use Canadian pipes to deliver their oil to US refineries.
In 2012, Canada's export pipeline system starts to overload with new oil production. As a result, Enbridge implements the distribution of pipes on its southern route, and Kinder Morgan is on the westbound path. The pipe space is rationed by reducing the monthly allocation of each sender to a certain percentage of the requirements. Chevron Corporation Burnaby Refinery, the last remaining oil refinery on Canada's west coast, applied to NEB for preferential access to Canadian oil because American refineries in Washington and California defeated it for piped-out space but were rejected as it would violate NAFTA equivalent access. for energy rules. Similarly, North Dakota's new tight oil production is beginning to block new Canadian production from using Enbridge, Kinder Morgan, and the southern TransCanada system.
Additionally, the US oil marketing hub at Cushing is flooded with new oil as much of the new North American production from Canada, North Dakota, and Texas gathers at that point, and there is not enough capacity to take it from there to the Gulf Coast refinery. , in which half of the US refineries capacity is located. The American pipeline system is designed to take imported oil from the Gulf Coast and Texas to a refinery in the northern US, and new oil flows in the opposite direction, toward the Gulf Coast. The West Texas Intermediate price sent to Cushing, which is a major benchmark for US oil prices, fell to unprecedented lows below other international benchmarks such as Brent Crude and Dubai Crude. Since the price of WTI in Cushing is usually cited by US media as oil prices, this gives many Americans a distorted view of world oil prices lower than theirs, and supply is better than that internationally. Canada used to be in the same position as the US in offshore oil is cheaper than domestic oil, so oil pipelines used to walk west from the east coast to Central Canada are now being reversed to bring in cheaper domestic oil sand production from Alberta to the east coast.
New pipeline
Lack of access to markets, limited export capacity, and oversupply in the US market have been a problem for oil sand producers in recent years. They have led to lower prices for Canadian oil sands producers and reduced royalty and tax revenues to the Canadian government. The pipeline companies have moved forward with a number of solutions to transportation problems:
- The Enbridge line from Sarnia, Ontario to Westover, Ontario near the head of Lake Erie has been reversed. This line is used to take offshore oil to a refinery in the Sarnia area. Now it takes Alberta SCO and mixed asphalt for most of the refineries in Ontario.
- Enbridge has applied to reverse its line from Westover to Montreal, Quebec. This line is used to take offshore oil to a refinery in southern Ontario. After the reversal, it will take Alb
Source of the article : Wikipedia
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