Oil sands

The Athabasca Oil Sands in Alberta, Canada, are a very large source of bituminous sands.

Oil sands, extra heavy oil, bituminous sands, or tar sands, are a type of unconventional petroleum deposit. The sands contain naturally occurring mixtures of sand, clay, water, and an extremely dense and viscous form of petroleum technically referred to as bitumen. Oil sands are found in large amounts in many countries throughout the world, but are found in extremely large quantities in Canada and Venezuela.[1]

The crude bitumen contained in the Canadian oil sands is described by Canadian authorities as petroleum that exists in the semi-solid or solid phase in natural deposits. 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. At room temperature, it is much like cold molasses.[2] Venezuelan authorities often refer to similar types of crude oil as extra-heavy oil, because Venezuelan reservoirs are warmer and the oil is somewhat less viscous, allowing it to flow more easily.

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 them to be profitably extracted and upgraded to usable products. They are often referred to as unconventional oil or crude bitumen, in order to distinguish the bitumen extracted from oil sands from the free-flowing hydrocarbon mixtures known as crude oil traditionally produced from oil wells.

Making liquid fuels from oil sands requires energy for steam injection and refining. This process generates two to four times the amount of greenhouse gases per barrel of final product as the production of conventional oil.[3] If combustion of the final products is included, the so-called "Well to Wheels" approach, oil sands extraction, upgrade and use emits 10 to 45% more greenhouse gases than conventional crude.[4]

Contents

History

The exploitation of bituminous sands dates back to paleolithic times. The earliest known use of bitumen was by Neanderthals, some 40,000 years ago. Bitumen has been found adhering to stone tools used by Neanderthals at sites in Syria. After the arrival of Homo sapiens, humans used bitumen for construction of buildings and water proofing of reed boats, among other uses. In ancient Egypt, the use of bitumen was important in creating Egyptian mummies—in fact, the word mummy is derived from the Arab word mūmiyyah, which means bitumen.[5]

In ancient times, bitumen was primarily a Mesopotamian commodity used by the Sumerians and Babylonians, although it was also found in the Levant and Persia. Along the Tigris and Euphrates rivers, the area was littered with hundreds of pure bitumen seepages. The Mesopotamians used the bitumen for waterproofing boats and buildings. In North America, the early European fur traders found Canadian First Nations using bitumen from the vast Athabasca oil sands to waterproof their birch bark canoes.[6] In Europe, they were extensively mined near the European city of Pechelbronn, where the vapor separation process was in use in 1742.[7]

The name tar sands was applied to bituminous sands in the late 19th and early 20th century. People who saw the bituminous sands during this period were familiar with the large amounts of tar residue produced in urban areas as a by-product of the manufacture of coal gas for urban heating and lighting.[8] The word "tar" to describe these natural bitumen deposits is really a misnomer, since, chemically speaking, tar is a man-made substance produced by the destructive distillation of organic material, usually coal. Since then, coal gas has almost completely been replaced by natural gas as a fuel, and coal tar as a material for paving roads has been replaced by the petroleum product asphalt. Naturally occurring bitumen is chemically more similar to asphalt than to tar, and the term oil sands (or oilsands) is more commonly used in the producing areas than tar sands because synthetic oil is what is manufactured from the bitumen.[9]

Oil sands are now considered a serious alternative to conventional crude oil, since crude oil is becoming scarce. Oil sands and oil shale have the potential to generate oil for centuries.[10]

Reserves

Many countries in the world have large deposits of oil sands, including the United States, Russia, and various countries in the Middle East. However, the world's largest deposits occur in two countries: Canada and Venezuela, each of which has oil sand reserves approximately equal to the world's total reserves of conventional crude oil. As a result of the development of Canadian oil sands reserves, 44% of Canadian oil production in 2007 was from oil sands, with an additional 18% being heavy crude oil, while light oil and condensate had declined to 38% of the total.[11] Because growth of oil sands production has exceeded declines in conventional crude oil production, Canada has become the largest supplier of oil and refined products to the United States, ahead of Saudi Arabia and Mexico. Venezuelan production is also very large, but due to political problems within its national oil company,[12] estimates of its production data are not reliable. Outside analysts believe Venezuela's oil production has declined in recent years,[13] though there is much debate on whether this decline is depletion-related or not.

Oil sands may represent as much as two-thirds of the world's total petroleum resource, with at least 1.7 trillion barrels (270×10^9 m3) in the Canadian Athabasca Oil Sands.

In October 2009, the USGS updated the Orinoco tar sands (Venezuela) mean estimated recoverable value to 513 billion barrels (8.16×1010 m3), making it "one of the world's largest recoverable" oil deposits.[14]

Between them, the Canadian and Venezuelan deposits contain about 3.6 trillion barrels (570×10^9 m3) of oil in place, compared to 1.75 trillion barrels (280×10^9 m3) of conventional oil worldwide, most of it in Saudi Arabia and other Middle-Eastern countries.

Production

Bituminous sands are a major source of unconventional oil. 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 water flooding and gas injection are usually required to maintain production as reservoir pressure drops toward the end of a field's life. Because extra-heavy oil and bitumen flow very slowly, if at all, toward producing wells under normal reservoir conditions, the sands must be extracted by strip mining or the oil made to flow into wells by in situ techniques which reduce the viscosity by injecting steam, solvents, and/or hot air into the sands. These processes can use more water and require larger amounts of energy than conventional oil extraction, although many conventional oil fields also require large amounts of water and energy to achieve good rates of production.

This is because heavy crude feedstock needs pre-processing before it is fit for conventional refineries. This pre-processing is called 'upgrading', the key components of which are as follows:

  1. removal of water, sand, physical waste and lighter products
  2. catalytic purification by hydrodemetallisation (HDM), hydrodesulfurization (HDS) and hydrodenitrogenation (HDN)
  3. hydrogenation through carbon rejection or catalytic hydrocracking (HCR)

As carbon rejection is very inefficient and wasteful in most cases, catalytic hydrocracking is preferred in most cases. All these processes take large amounts of energy and water, while emitting more carbon dioxide than conventional oil.

Catalytic purification and hydrocracking are together known as hydroprocessing. The big challenge in hydroprocessing is to deal with the impurities found in heavy crude, as they poison the catalysts over time. Many efforts have been made to deal with this to ensure high activity and long life of a catalyst. Catalyst materials and pore size distributions are key parameters that need to be optimized to deal with these challenge and this varies from place to place depending on the kind of feedstock present.[15]

At the present time, only Canada has a large-scale commercial oil sands industry, though a small amount of oil from oil sands is produced in Venezuela. Because of increasing oil sands production Canada has become the largest single supplier of oil and products to the United States. Oil sands now are the source of almost half of Canada's oil production, although due to the 2008 economic downturn work on new projects has been deferred, while Venezuelan production has been declining in recent years. Oil is not produced from oil sands on a significant level in other countries.[16]

Transportation and refining

The heavy crude oil or crude bitumen extracted from oil sands is a viscous, solid or semisolid form that does not easily flow at normal oil pipeline temperatures, making it difficult to transport to market and expensive to process into gasoline, diesel fuel, and other products. Despite the difficulty and cost, oil sands are now being mined by energy companies on a vast scale to extract the bitumen, which is then converted into synthetic oil (syncrude) by bitumen upgraders, or refined directly into petroleum products by specialized refineries.[17]

As oil source, by location

Canada

See also: Athabasca Oil Sands and History of the petroleum industry in Canada (oil sands and heavy oil)
Syncrude's Mildred Lake mine site and plant near Fort McMurray, Alberta

Canada is the largest supplier of crude oil and refined products to the United States, supplying about 20% of total U.S. imports, and exports more oil and products to the U.S. than it consumes itself.[18] In 2006, bitumen production averaged 1.25 million barrels per day (200,000 m3/d) through 81 oil sands projects, representing 47% of total Canadian petroleum production. This proportion is expected to increase in coming decades as bitumen production grows while conventional oil production declines.[1]

Most of the oil sands of Canada are located in three major deposits in northern Alberta. These are the Athabasca-Wabiskaw oil sands of north northeastern Alberta, the Cold Lake deposits of east northeastern Alberta, and the Peace River deposits of northwestern Alberta. Between them they cover over 140,000 square kilometres (54,000 sq mi) - an area larger than England - and hold proven reserves of 1.75 trillion barrels (280×10^9 m3) of bitumen in place. About 10% of this, or 173 billion barrels (27.5×10^9 m3), is estimated by the government of Alberta to be recoverable at current prices using current technology, which amounts to 97% of Canadian oil reserves and 75% of total North American petroleum reserves.[1] The Cold Lake deposits extend across the Alberta's eastern border into Saskatchewan. In addition to the Alberta oil sands, there are major oil sands deposits on Melville Island in the Canadian Arctic islands which are unlikely to see commercial production in the foreseeable future.

The Alberta oil sand deposits contain at least 85% of the world's reserves of natural bitumen (representing 40% of the combined crude bitumen and extra-heavy crude oil reserves in the world), but are the only bitumen deposits concentrated enough to be economically recoverable for conversion to synthetic crude oil at current prices. The largest bitumen deposit, containing about 80% of the Alberta total, and the only one suitable for surface mining, is the Athabasca Oil Sands along the Athabasca River. The mineable area (as defined by the Alberta government) includes 37 townships covering about 3,400 square kilometres (1,300 sq mi) near Fort McMurray. The smaller Cold Lake deposits are important because some of the oil is fluid enough to be extracted by conventional methods. All three Alberta areas are suitable for production using in-situ methods such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD).

The Alberta oil sands have been in commercial production since the original Great Canadian Oil Sands (now Suncor) mine began operation in 1967. A second mine, operated by the Syncrude consortium, began operation in 1978 and is the biggest mine of any type in the world. The third mine in the Athabasca Oil Sands, the Albian Sands consortium of Shell Canada, Chevron Corporation and Western Oil Sands Inc. [purchased by Marathon Oil Corporation in 2007] began operation in 2003. Petro-Canada was also developing a $33 billion Fort Hills Project, in partnership with UTS Energy Corporation and Teck Cominco, which lost momentum after the 2009 merger of Petro-Canada into Suncor. If approved, Fort Hills Oilsands upgraders were slated to begin output in 4–5 years.

With the development of new in-situ production techniques such as steam assisted gravity drainage, and with the oil price increases since 2003, there were several dozen companies planning nearly 100 oil sands projects in Canada, totaling nearly $100 billion in capital investment. With 2007 crude oil prices significantly in excess of the current average cost of production of $28 per barrel of bitumen,[19] all of these projects appear likely to be profitable. However, bitumen production costs are rising rapidly, with production cost increases of 55% since 2005, due to shortages of labor and materials.[19]

The minority Conservative government of Canada, pressured to do more on the environment, announced in its 2007 budget that it would phase out some oil sands tax incentives over coming years. The provision allowing accelerated write-off of oil sands investments will be phased out gradually so projects that had relied on them can proceed. For new projects the provision will be phased out between 2011 and 2015.[20]

With oil prices setting new highs in 2007, tax incentives were no longer necessary to encourage oil sands projects in Canada. In July of that year Royal Dutch Shell released its 2006 annual report and announced that its Canadian oil sands unit made an after tax profit of $21.75 per barrel, nearly double its worldwide profit of $12.41 per barrel on conventional crude oil.[21] A few days later Shell announced it had filed for regulatory approval to build a $27 billion oil sands refinery in Alberta, one of $38 billion in new oil sands projects announced that week.[22]

Venezuela

Located in eastern Venezuela, north of the Orinoco River, the Orinoco oil belt vies with the Canadian oil sand for largest known accumulation of bitumen in the world. Venezuela prefers to call its oil sands "extra heavy oil", and although the distinction is somewhat academic, the extra heavy crude oil deposit of the Orinoco Belt represent nearly 90% of the known global reserves of extra heavy crude oil, and nearly 45% of the combined crude bitumen and extra-heavy crude oil reserves in the world.

Bitumen and extra-heavy oil are closely related types of petroleum, differing only in the degree by which they have been degraded from the original crude oil by bacteria and erosion. The Venezuelan deposits are less degraded than the Canadian deposits and are at a higher temperature (over 50 degrees Celsius versus freezing for northern Canada), making them easier to extract by conventional techniques.

Although Venezuela's extra-heavy oil is easier to produce than Canada's bitumen, it is still too heavy to transport by pipeline or process in normal refineries. Lacking access to first-world capital and technological prowess, Venezuela has not been able to design and build the kind of upgraders and heavy oil refineries that Canada has. In the early 1980s the state oil company, PDVSA, developed a method of using the extra-heavy oil resources by emulsifying it with water (70% extra-heavy oil, 30% water) to allow it to flow in pipelines. The resulting product, called Orimulsion, can be burned in boilers as a replacement for coal and heavy fuel oil with only minor modifications. Unfortunately, the fuel’s high sulphur content and emission of particulates make it difficult to meet increasingly strict international environmental regulations.

Further development of the Venezuelan resources has been impeded by political unrest. Venezuela is less politically stable than a country such as Canada, and a two-month strike in 2002-2003 by employees of the state oil company was followed by the dismissal of most of its staff. As tensions resolved, strike leaders pointed to the reduction in Venezuela's domestic crude output as an argument that Venezuela's oil production had fallen. However, Venezuela's oil sands crude production, which sometimes wasn't counted in its total, has increased from 125,000 bbl/d (19,900 m3/d) to 500,000 bbl/d (79,000 m3/d) between 2001 and 2006 (Venezuela's figures; IAEA says 300,000 bpd).[23][24][25]

USA

In the United States, oil sands resources are primarily concentrated in Eastern Utah. With a total of 32 billion barrels of oil(known and potential) in eight major deposits[26] in the Utah counties of Carbon, Garfield, Grand, Uintah and Wayne. Currently, oil is not produced from oil sands on a significant commercial level in the United States, although the U.S. imports twenty percent of its oil and refined products from Canada, and over fifty percent of Canadian oil production is from oil sands. In addition to being much smaller than the oil sands deposits in Alberta, Canada, the U.S. oil sands are hydrocarbon wet, whereas the Canadian oil sands are water wet. As a result of this difference, extraction techniques for the Utah oil sands will be different than those used for the Alberta oil sands. A considerable amount of research has been done in the quest for commercially viable production technology to be employed in the development of the Utah oil sands. A special concern is the relatively arid climate of eastern Utah, as a large amount of water may be required by some processing techniques.[16] Section 526 of the Energy Independence And Security Act prohibits United States government agencies from buying oil produced by processes that produce more greenhouse gas emissions than would traditional petroleum including oil sands.[27][28]

Other countries

Several other countries hold oil sands deposits which are smaller by orders of magnitude. Russia holds oil sands in two main regions[29]. The Volga-Urals basins (in and around Tatarstan), which is an important but very mature province in terms of conventional oil, holds large amounts of oil sands in a shallow permian formation. Exploitation has not gone beyond pilot stage yet. Other, less known, deposits are located in eastern Siberia.

In the Republic of the Congo the Italian oil company Eni have announced in May 2008 a project to develop the small oil sands deposit in order to produce 40,000 barrels per day in 2014.[30] Reserves are estimated between 0.5 and 2.5 billion barrels.

In Madagascar, Tsimiroro and Bemolanga are two heavy oil sands deposits with a pilot well already producing small amounts of oil in Tsimiroro[31] and larger scale exploitation in the early planning phase.[32]

Extraction process

Surface mining

Since Great Canadian Oil Sands (now Suncor) started operation of its mine in 1967, bitumen has been extracted on a commercial scale from the Athabasca Oil Sands by surface mining. 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 deep, sitting on top of flat limestone rock. Originally, the sands were mined with draglines and bucket-wheel excavators and moved to the processing plants by conveyor belts. In recent years companies such as Syncrude and Suncor have switched to much cheaper shovel-and-truck operations using the biggest power shovels (100 or more tons)[33] and dump trucks (400 tons) in the world. This has held production costs to around $27 per barrel of synthetic crude oil despite rising energy and labour costs.[34]

After excavation, hot water and caustic soda (NaOH) is added to the sand, and the resulting slurry is piped to the extraction plant where it is agitated and the oil skimmed from the top.[35] Provided that the water chemistry is appropriate to allow bitumen to separate from sand and clay, the combination of hot water and agitation releases bitumen from the oil sand, and allows small air bubbles to attach to the bitumen droplets. The bitumen froth floats to the top of separation vessels, and is further treated to remove residual water and fine solids. Bitumen is much thicker than traditional crude oil, so it must be either mixed with lighter petroleum (either liquid or gas) or chemically split before it can be transported by pipeline for upgrading into synthetic crude oil.

The bitumen is then transported and eventually upgraded into synthetic crude oil. About two tons of oil sands are required to produce one barrel (roughly 1/8 of a ton) of oil. Originally, roughly 75% of the bitumen was recovered from the sand. However, recent enhancements to this method include Tailings Oil Recovery (TOR) units which recover oil from the tailings, Diluent Recovery Units to recover naptha from the froth, Inclined Plate Settlers (IPS) and disc centrifuges. These allow the extraction plants to recover well over 90% of the bitumen in the sand. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.

Alberta Taciuk Process technology extracts bitumen from oil sands through a dry-retorting. During this process, oil sand is moved through a rotating drum, cracking the bitumen with heat and producing lighter hydrocarbons. Although tested, this technology is not in commercial use yet.[36]

Four oil sands mines are currently in operation and two more (Jackpine and Kearl) are in the initial stages of development. The original Suncor mine opened in 1967, while the Syncrude mine started in 1978, Shell Canada opened its Muskeg River mine (Albian Sands) in 2003 and Canadian Natural Resources Ltd opened its Horizon Project in 2009. New mines under construction or undergoing approval include Shell Canada's Jackpine mine, Imperial Oil's Kearl Oil Sands Project, Synenco Energy's Northern Lights mine, and Suncor's Fort Hills mine.

It is estimated that approximately 90% of the Alberta oil sands and nearly all of Venezuelan sands are too far below the surface to use open-pit mining. Several in-situ techniques have been developed to extract this oil.[37]

Cold flow

In this technique, also known as cold heavy oil production with sand (CHOPS), the oil is simply pumped out of the sands, often using progressive cavity pumps. This only works well in areas where the oil is fluid enough. It is commonly used in Venezuela (where the extra-heavy oil is at 50 degrees Celsius), and also in the Wabasca, Alberta Oil Sands, the southern part of the Cold Lake, Alberta Oil Sands and the Peace River Oil Sands. It has the advantage of being cheap and the disadvantage that it recovers only 5-6% of the oil in place.[38]

Some years ago Canadian oil companies discovered that if they removed the sand filters from the wells and produced as much sand as possible with the oil, production rates improved remarkably. This technique became known as Cold Heavy Oil Production with Sand (CHOPS). Further research disclosed that pumping out sand opened "wormholes" in the sand formation which allowed more oil to reach the wellbore. The advantage of this method is better production rates and recovery (around 10%) and the disadvantage that disposing of the produced sand is a problem. A novel way to do this was spreading it on rural roads, which rural governments liked because the oily sand reduced dust and the oil companies did their road maintenance for them. However, governments have become concerned about the large volume and composition of oil spread on roads,[39] so in recent years disposing of oily sand in underground salt caverns has become more common.

Cyclic Steam Stimulation (CSS)

The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s. The Cyclic Steam Stimulation or "huff-and-puff" method has been in use by Imperial Oil at Cold Lake since 1985 and is also used by Canadian Natural Resources at Primrose and Wolf Lake and by Shell Canada at Peace River. In this method, the well is put through cycles of steam injection, soak, and oil production. First, steam is injected into a well at a temperature of 300 to 340 degrees Celsius for a period of weeks to months; then, the well is allowed to sit for days to weeks to allow heat to soak into the formation; and, later, the hot oil is pumped out of the well for a period of weeks or months. Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes higher than the money made from producing oil. The CSS method has the advantage that recovery factors are around 20 to 25% and the disadvantage that the cost to inject steam is high.

Steam Assisted Gravity Drainage (SAGD)

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. SAGD has proved to be a major breakthrough in production technology since it is cheaper than CSS, allows very high oil production rates, and recovers up to 60% of the oil in place. Because of its very favorable economics and applicability to a vast area of oil sands, this method alone quadrupled North American oil reserves and allowed Canada to move to second place in world oil reserves after Saudi Arabia. Most major Canadian oil companies now have SAGD projects in production or under construction in Alberta's oil sands areas and in Wyoming. Examples include 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[1] and Christina Lake [2] 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 Process (VAPEX)

VAPEX is similar to SAGD but instead of steam, hydrocarbon solvents are injected into the upper well to dilute the bitumen and allow it to flow into the lower well. It has the advantage of much better energy efficiency than steam injection and it does some partial upgrading of bitumen to oil right in the formation. It is very new but has attracted much attention from oil companies, who are beginning to experiment with it.

The above three methods are not mutually exclusive. It is becoming common for wells to be put through one CSS injection-soak-production cycle to condition the formation prior to going to SAGD production, and companies are experimenting with combining VAPEX with SAGD to improve recovery rates and lower energy costs.

Toe to Heel Air Injection (THAI)

This is a very new and experimental method that combines a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the "toe" of the horizontal well toward the "heel", which burns the heavier oil components and 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.[40]

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.[41]

Petrobank Energy and Resources Ltd. has reported encouraging results from their test wells in Alberta, with production rates of up to 400 barrels per day 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)[42] system, which pulls the oil through a catalyst lining the lower pipe.[43][44][45]

Combustion Overhead Gravity Drainage (COGD)

This is an experimental method that employs an 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.[46]

Environmental issues

Mining operations in the Athabasca oil sands. Note the close proximity of the Athabasca River to the tailings pond, which stores contaminated water from processing the oil sands. NASA Earth Observatory image, 2009.

Like all mining and non-renewable resource development projects, oil sands operations have an adverse effect on the environment. Oil sands projects affect: the land when the bitumen is initially mined and with large deposits of toxic chemicals; the water during the separation process and through the drainage of rivers; and the air due to the release of carbon dioxide and other emissions, as well as deforestation. Additional indirect environmental effects are that the petroleum products produced are mostly burned, releasing carbon dioxide into the atmosphere.

Air

The Wood Buffalo Environmental Association (WBEA) monitors the air in the Regional Municipality of Wood Buffalo continuously. This is done through a variety of air, land and human monitoring programs. The information collected is openly shared with stakeholders and the public.

Since 1995, monitoring in the oil sands region shows improved or no change in long term air quality for the five key air quality pollutants — carbon monoxide, nitrogen dioxide, ozone, fine particulate matter (PM2.5) and sulphur dioxide — used to calculate the Air Quality Index.[47] Air monitoring has shown significant increases in exceedances of hydrogen sulfide (H2S) both in the Fort McMurray area and near the oil sands upgraders.

Hydrogen sulfide is the chemical compound with the formula H2S. This colorless, toxic and flammable gas is responsible for the foul odour of rotten eggs. Hydrogen sulfide gas occurs naturally in crude petroleum, natural gas, volcanic gases and hot springs. It also can result from bacterial breakdown of organic matter and be produced by human and animal wastes.

In 2007, the Alberta government issued an Environmental Protection Order to Suncor Energy Inc. The order comes in response to numerous occasions when ground level concentration (GLC) for H2S exceeded acceptable standards.[48] Environmental Protection Orders are issued under the authority of Alberta’s Environmental Protection and Enhancement Act. Alberta Environment can issue Environmental Protection Orders to remedy environmental problems where there has been a release of a substance that has caused or may cause an adverse effect to the environment.

Land

A large part of oil sands mining operations involves clearing trees and brush from a site and removing the "overburden" — the topsoil, muskeg, sand, clay and gravel — that sits atop the oil sands deposit.[49] Approximately two tons of oil sands are needed to produce one barrel of oil (roughly 1/8 of a ton).[50] As a condition of licensing, projects are required to implement a reclamation plan.[51] The mining industry asserts that the boreal forest will eventually colonize the reclaimed lands, but that their operations are massive and work on long-term timeframes. As of 2006/2007 (the most recent data available), about 420 km2 (160 sq mi) of land in the oil sands region have been disturbed, and 65 km2 (25 sq mi) of that land is under reclamation.[52] In March 2008, Alberta issued the first-ever oil sands land reclamation certificate to Syncrude Canada Ltd. for the 1.04 km2 (0.40 sq mi) parcel of land known as Gateway Hill approximately 35 km (22 mi) north of Fort McMurray.[53] Several reclamation certificate applications for oil sands projects are expected within the next 10 years.[54]

Water

Between 2 to 4.5 volume units of water are used to produce each volume unit of synthetic crude oil (SCO) in an ex-situ mining operation. Despite recycling, almost all of it ends up in tailings ponds, which, as of 2007, covered an area of approximately 50 km2 (19 sq mi). In SAGD operations, 90 to 95 percent of the water is recycled and only about 0.2 volume units of water is used per volume unit of bitumen produced.[55] Large amounts of water are used for oil sands operations – Greenpeace gives the number as 349 million cubic metres per year, twice the amount of water used by the city of Calgary. It is unclear if this is the amount of water they are licensed to remove from the Athabasca or the actual use and how up to date the statistic is. The Athabasca River is also much larger than Bow and Elbow rivers that flow through Calgary.[56]

The Athabasca River is the ninth longest river in Canada running 1,231 km (765 mi) from the Athabasca Glacier in west-central Alberta to Lake Athabasca in northeastern Alberta.[57] The average annual flow just downstream of Fort McMurray is 633 cubic metres per second[58] with its highest daily average measuring 1200 cubic metres per second.[59]

Current water license allocations totals about 1.8 percent of the Athabasca river flow. Actual use in 2006 was about 0.4 percent.[60] In addition, the Alberta government sets strict limits on how much water oil sands companies can remove from the Athabasca River. According to the Water Management Framework for the Lower Athabasca River, during periods of low river flow water consumption from the Athabasca River is limited to 1.3 per cent of annual average flow.[61] The province of Alberta is also looking into cooperative withdrawal agreements between oil sands operators.[62]

In October 2009, Suncor Energy announced it was seeking government approval for a new process to recover tailings called Tailings Reduction Operations (TRO), which accelerates the settling of fine clay, sand, water, and residual bitumen in ponds after oil sands extraction. The technology involves dredging mature tailings from a pond bottom, mixing the suspension with a polymer flocculent, and spreading the sludge-like mixture over a “beach” with a shallow grade. According to the company, the process could reduce the time for water reclamation from tailings to weeks rather than years, with the recovered water being recycled into the oil sands plant. In addition to reducing the number of tailing ponds, Suncor claims TRO could reduce the time to reclaim a tailing pond from 40 years at present to 7–10 years, with land rehabilitation continuously following 7 to 10 years behind the mining operations.[63]

Climate change

The production of bitumen and synthetic crude oil emits more greenhouse gas (GHG) than the production of conventional crude oil, and has been identified as the largest contributor to GHG emissions growth in Canada, as it accounts for 40 million tonnes of CO2 emissions per year.[64] Environment Canada claims the oil sands make up 5% of Canada's greenhouse gas emissions, or 0.1% of global greenhouse gas emissions. It predicts the oil sands will grow to make up 8% of Canada's greenhouse gas emissions by 2015.[65] Environmentalists argue that the availability of more oil for the world made possible by oil sands production in itself raises global emissions of CO2.

While the emissions per barrel of bitumen produced decreased 26% over the decade 1992–2002[66], total emissions were expected to increase due to higher production levels.[67] As of 2006, to produce one barrel of oil from the oil sands released almost 75 kg (170 lb) of GHG with total emissions estimated to be 67 megatonnes (66,000,000 LT; 74,000,000 ST) per year by 2015.[68]

In January 2008, the Alberta government released Alberta’s 2008 Climate Change Strategy.[69] Alberta’s emissions are projected to grow to 400 megatonnes (Mt) by 2050, largely due to forecast growth in the oil sands sector.[69] The new plan aims to cut the projected 400 Mt in half by 2050, with a 139 Mt reduction coming from carbon capture and storage — the bulk of those reductions (100 Mt) will come from activities related to oil sands production.[69]

A federal court of Canada ruling on March 6, 2008, found the approval of Imperial Oil Ltd.'s $8-billion oil sands mine insufficient on climate change and greenhouse gas emissions. Proposals in the regulatory system at that date included mines by Total SA of France, by Anglo-Dutch Royal Dutch Shell and by Petro-Canada, as well as steam-injection projects by EnCana of Calgary.[70]

A 2009 study by CERA estimated that production from Canada's oil sands emits "about 5 percent to 15 percent more carbon dioxide, over the "well-to-wheels" lifetime analysis of the fuel, than average crude oil."[71] Author and investigative journalist David Strahan that same year stated that IEA figures show that carbon dioxide emissions from the tar sands are 20% higher than average emissions from oil [72] With coal's CO2 emissions about one-third higher than convention oil's , this would make the tar sands' emissions equal to about 90% of the CO2 released from coal.

Carbon dioxide sequestration

Main article: Carbon capture and storage

To offset greenhouse gas emissions from the oil sands and elsewhere in Alberta, sequestering carbon dioxide emissions inside depleted oil and gas reservoirs has been proposed. This technology is inherited from Enhanced oil recovery methods, which have been in use for several decades.[73] In July 2008, the Alberta government announced a C$2 billion fund to support sequestration projects in Alberta power plants (largely coal) and oil sands extraction and upgrading facilities.[74][75][76]

Concerns of environmentalists

The environmental impact caused by oil sand extraction is frequently criticized by environmental groups such as Greenpeace.[77][78] Environmentalists state that their main concerns with oil sands are land damage, including the substantial degradation in the land's ability to support forestry and farming, greenhouse gas emissions, and water use. Oil sands extraction is generally held to be more environmentally damaging than conventional crude oil — carbon dioxide "well-to-pump" emissions, for example, are estimated to be about 1.3-1.7 times that of conventional crude.[65]

Input energy

Approximately 1.0 – 1.25 gigajoule of energy is needed to extract a barrel of bitumen and upgrade it to synthetic crude. As of 2006, most of this is produced by burning natural gas.[79] Since a barrel of oil equivalent is about 6.117 gigajoules, this extracts about 5 or 6 times as much energy as is consumed. Energy efficiency is expected to improve to 0.7 gigajoules of energy per barrel by 2015,[80] giving an EROEI of about 9. However, since natural gas production in Alberta peaked in 2001 and has been static ever since, it is likely oil sands requirements will be met by cutting back natural gas exports to the U.S.[81]

Alternatives to natural gas exist and are available in the oil sands area. Bitumen can itself be used as the fuel, consuming about 30-35% of the raw bitumen per produced unit of synthetic crude. Nexen's Long Lake project will use a proprietary deasphalting technology to upgrade the bitumen, using asphaltene residue fed to a gasifier whose syngas will be used by a cogeneration turbine and a hydrogen producing unit, providing all the energy needs of the project: steam, hydrogen, and electricity.[82] Thus, it will produce syncrude without consuming natural gas, but the capital cost is very high.

Coal is widely available in Alberta and is inexpensive, but produces large amounts of greenhouse gases. Nuclear power is another option which has been proposed, but did not appear to be economic as of 2005.[83] In early 2007 the Canadian House of Commons Standing Committee on Natural Resources considered that the use of nuclear power to process oil sands could reduce CO2 emissions and help Canada meet its Kyoto commitments, as it would require nearly 12 GW to meet production growth to 2015, but the implications of building reactors in northern Alberta were not yet well understood.[84][85][86] Energy Alberta Corporation announced in 2007 that they had applied for a license to build a new nuclear plant at Lac Cardinal, 30 km west of the town of Peace River. The application would see an initial twin AECL Advanced CANDU Reactor ACR-1000 plant go online in 2017, producing 2.2 GW (electric).[87][88] At 6.117 GJ/barrel, this is equivalent to conserving 31,074 barrels per day (4,940.4 m3/d). On November 30, 2007 Bruce Power, which owns eight CANDU reactors in Ontario, signed a letter of intent to acquire Energy Alberta and take over the project.[89]

See also

References

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