Tar sands – content
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Tar sands, also referred to as oil sands or bituminous sands, are a combination of clay, sand, water, and bitumen. On average bitumen contains 83.2% carbon, 10.4% hydrogen, 4.8% sulphur, 0.94% oxygen, and 0.36% nitrogen.
Technically speaking, the bitumen is neither oil nor tar,
but a semisolid, degraded form of oil that does not flow at normal temperatures
and pressures, making it difficult and expensive to extract. Tar sands are
mined to extract the oil-like bitumen, which is then converted into synthetic
crude oil or refined directly into petroleum products by specialized
refineries. Most refineries can only handle about 10-15 per cent of their
input coming from these heavy oil sources.
Crude oil is extracted by drilling wells, but oil sand deposits are strip mined or made to flow into producing wells by in situ techniques which reduce the bitumen's viscosity with steam and/or solvents. This latter process uses a great deal of water, which is challenging as the largest deposits are in cold desert areas where, for much of the year, surface water is only present in the form of ice.
As oil source, by location
Tar sands were used by the ancient Mesopotamians and
Canadian First Nations.
They have only recently been considered to be part of the world's oil reserves, as they are becoming extractable at current prices with current technology.
Oil sand is often referred to as non-conventional oil, in
order to distinguish the bitumen and synthetic oil extracted from oil sands
from the free-flowing hydrocarbon mixtures known as crude oil traditionally
produced from oil wells. See Bituminous rocks.
Tar sands may represent as much as 2/3 of the world's
total petroleum resource, with at least 1.7 trillion barrels (1.7×1012 bbl or
270×109 m³) in the Canadian Athabasca Tar Sands and perhaps 1.8 trillion
barrels (1.8×1012 bbl or 280×109 m³) in the Venezuelan Orinoco tar sands
, compared to 1.75 trillion barrels (1.75×1012 bbl or
278×109 m³) of conventional oil worldwide, most of it in Saudi Arabia and
other Middle-Eastern countries. Between them, the Canadian and Venezuelan
deposits contain about 3.6 trillion barrels of oil in place. This is only the
remnant of vast petroleum deposits which once totaled as much as 18 trillion
barrels, most of which has escaped or been destroyed by bacteria over the
eons. See also below notes about limits to production capacity.
Tar sand deposits are found in over 70 countries throughout the world, but three quarters of the world's reserves are in two regions: Venezuela and the Athabasca located in northern Alberta and Saskatchewan, Canada.
Most of the oil sands of Canada are located in three major
deposits in northern Alberta. The three deposits are the Athabasca-Wabiskaw
oil sands of north northeastern Alberta, the Cold Lake deposits of east
northeastern Alberta, and the Peace River deposits of northwestern Alberta.
Between them they cover over 140,000 square kilometers (54,000 square miles),
an area larger than Florida, and hold at least 175 billion barrels (175×109
bbl) or 28 billion cubic metres (28×109 m³) of recoverable crude bitumen,
which amounts to three-quarters of North American petroleum reserves. In
addition to the Alberta deposits, there are major oil sands deposits on Melville
Island in the Canadian Arctic islands but they are unlikely to see
commercial production in the foreseable future.
The Alberta deposits contain at least 85% of the world's
total bitumen reserves but are so concentrated as to be the only such
deposits that are economically recoverable for conversion to oil. The largest
bitumen deposit, containing about 80% of the total, and the only one suitable
for surface mining is the Athabasca Oil Sands along the Athabasca River. The mineable
area as defined by the Alberta government covers 37 contiguous townships
(about 3400 square kilometres or 1300 square miles) north of the city of Fort
McMurray. The smaller Cold Lake deposits are important because some of the
oil is fluid enough to be produced by conventional production methods. All
three Alberta areas are suitable for production using in-situ methods such as
cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD).
The Canadian oil sands have been in commercial production
since the original Great Canadian Oil Sands (now Suncor) mine began operation
in 1967. A second mine, operated by the Syncrude consortium, began operation
in 1978 and is the biggest mine of any type in the world. The third mine in
the Athabasca Oil Sands, the Albian Sands consortium of Shell Canada, Chevron
Corporation and Western Oil Sands Inc. began operation in 2003. UTS Energy
Corporation is also developing its Fort Hills Project, in conjuction with Petro
Canada and Teck Cominco.
With the development of new in-situ production techniques such as steam assisted gravity drainage, and with the oil price increases of 2004-2006, there were several dozen companies planning nearly 100 oil sands mines and in-situ projects in Canada, totaling nearly $100 billion in capital investment. With 2006 crude oil prices significantly in excess of the current cost of production, all of these projects appear likely to be profitable.
Early optimism fading?
These development plans may be overly optimistic. Low
production prices of under $25/barrel are enjoyed only by amortized plants such
as the Syncrude operation. New sites such as the The Canadian Natural
Resources (CNRL) Horizon Project, typically require at least $30/barrel to be
There are also efforts, led by prominent former Alberta
politician Preston Manning, to charge for the access to water this industry
requires. There are health and environment impacts, including greenhouse gas
emissions. See below under environmental and health impact. The full cost
accounting which Manning advocates could add as much as US$5-10 per barrel to
Expanding production capacity is also limited by several
factors. Any expansion of capacity carries risks: infrastructure is
expensive, and oil prices are unpredictable.
In early 2006 US and Canadian executives met in Houston, Texas to discuss the future of the industry. They planned for a five-fold increase in production, in order to wean the US off middle-eastern imports by 2015.
Located in eastern Venezuela, north of the Orinoco River,
the Orinoco oil belt vies with the Canadian oil sand for largest known
accumulation of bitumen in the world. Venezuela prefers to call its tar sands
"extra-heavy oil", and although the distinction is somewhat
academic, the extra-heavy crude oil deposit of the Orinoco Belt represent
nearly 90% of the known global reserves of extra-heavy oil.
Bitumen and extra-heavy oil are closely related types of
petroleum, differing only in the degree by which they have been degraded from
the original crude oil by bacteria and erosion. The Venezuelan deposits are
less degraded than the Canadian deposits and are at a higher temperature
(over 50 degrees Celsius versus freezing for northern Canada), making them
easier to extract by conventional techniques.
Although it is easier to produce, it is still too heavy to
transport by pipeline or process in normal refineries. Lacking access to
first-world capital and technological prowess, Venezuela has not been able to
design and build the kind of bitumen upgraders and heavy oil refineries that Canada
has. However, in the early 1980’s the state oil company, PDVSA, developed a
method of using the extra-heavy oil resources by emulsifying it with water
(70% extra-heavy oil, 30% water) to allow it to flow in pipelines. The
resulting product, called Orimulsion, can be burned in boilers as a replacement
for coal and heavy fuel oil with only minor modifications. Unfortunately, the
fuel’s high sulphur content and emission of particulates make it difficult to
meet increasingly strict international environmental regulations.
Further development of the Venezuelan resources has been curtailed by political unrest. Venezuela is much less politically stable than Canada, and a strike by employees of the state oil company was followed by the dismissal of most of its staff. As tensions resolved, strike leaders pointed to the reduction in Venezuela's domestic crude output as an argument that Venezuela's oil production had fallen. However, Venezuela's tar sands crude production, which sometimes isn't counted in its total, has increased from 125,000 bpd to 500,000 bpd between 2001 and 2006 (Venezuela's figures; IAEA says 300,000 bpd).
Utah's Tar Sand Resource consists of eight major deposits
with a combined shallow oil resource of 32.0 billion barrels of oil. The
largest of these deposits, the Tar Sand Triangle as it is known, covers an
area of 148,000 acres and is located in Wayne and Garfield Counties, between
the Dirty Devil and Colorado Rivers.
The Utah Tar Sands have been quarried since the early
1900s primarily for road paving material. Several pilot extraction tests have
been operated by oil companies at various times since 1972. The most recent
reported pilot tests at Asphalt Ridge were conducted by the Laramie Energy Technology
Center of the U.S. Department of Energy. In 1975 through 1978 they completed
experimental testing of a combined reverse-forward combustion and steam
injection scheme. It was concluded that additional testing of these methods
Efforts to develop Utah's heavy oil primarily ended with the sharp drop in oil prices in the mid-1980s and the high costs of extraction due to inefficient processing technologies.
Raw bitumen is separated from the sand in giant separation cells.
For the last 38 years or so, bitumen has been extracted from the Athabasca Oil Sands by surface mining. In these oil sands there are large deposits of bitumen with little overburden, making mining the most efficient method of extracting it. The overburden consists of water-laden muskeg (peat bog) over top of clay and barren sand. The oil sands themselves are typically 40 to 60 metres deep, sitting on top of flat limestone rock. Originally, the sands were mined with draglines and bucket-wheel excavators and moved to the processing plants by conveyor belts. However, in recent years companies such as Syncrude and Suncor have switched to much cheaper shovel-and-truck operations using the biggest power shovels (100 tons) and dump trucks (400 tons) in the world. This has reduced production costs to around $15 per barrel of synthetic crude oil.
After excavation, hot water and caustic soda (NaOH) is added to the sand, and the resulting slurry is piped to the extraction plant where it is agitated and the oil skimmed from the top. Oil Sands Discovery Centre Provided that the water chemistry is appropriate to allow bitumen to separate from sand and clay, the combination of hot water and agitation releases bitumen from the oil sand, and allows small air bubbles to attach to the bitumen droplets. The bitumen froth floats to the top of separation vessels, and is further treated to remove residual water and fine solids. Bitumen is much thicker than traditional crude oil, so it must be either mixed with lighter petroleum (either liquid or gas) or chemically split before it can be transported by pipeline for upgrading into synthetic crude oil.
Recent enhancements to this method include Tailings Oil
Recovery (TOR) units which recover oil from the tailings, Diluent Recovery Units
to recover naptha from the froth, Inclined Plate Settlers (IPS) and disc
centrifuges. These allow the extraction plants to recover over 90% of the
bitumen in the sand.
Three oil sands mines are currently in operation and a
fourth is in the initial stages of development. The original Suncor mine
opened in 1967, while the Syncrude mine started in 1978 and Shell Canada
opened its Muskeg River mine (Albian Sands) in 2003. New mines under
construction or undergoing approval include Canadian Natural Resources Ltd
Horizon Project (in the initial stages of development), Shell Canada's Jackpine
mine, Imperial Oil's Kearl Oil Sands Project, Synenco Energy's Northern
Lights mine, and Petro-Canada's Fort Hills mine.
It is estimated that around 80% of the Alberta oil sands and nearly all of Venezuelan sands are too far below the surface to use the open-pit mining technique used by the large producers. A number of in-situ techniques have been developed to extract this deeper oil. http://www.oilsandsdiscovery.com/oil_sands_story/insitu.html
In this technique, the oil is simply pumped out of the
sands, often using specialized pumps called progressive cavity pumps. This
only works well in areas where the oil is fluid enough to pump. It is
commonly used in Venezuela (where the extra-heavy oil is at 50 degrees
Celsius), and also in the Wabasca, Alberta Oil Sands and the southern part of
the Cold Lake, Alberta Oil Sands. It has the advantage of being cheap and the
disadvantage that it recovers only 5-6% of the oil in place.
Some years ago Canadian oil companies discovered that if they removed the sand filters from the wells and produced as much sand as possible with the oil, production rates improved remarkably. This technique became known as Cold Heavy Oil Production with Sand (CHOPS). Further research disclosed that pumping out sand opened "wormholes" in the sand formation which allowed more oil to reach the wellbore. The advantage of this method is better production rates and recovery (around 10%) and the disadvantage that disposing of the produced sand is a problem. A novel way to do this was spreading it on rural roads, which rural governments liked because the oily sand reduced dust and the oil companies did their road maintenance for them. However, governments have become concerned about how thick the roads were becoming, so in recent years disposing of sand in underground salt caverns has become common.
Cyclic Steam Stimulation (CSS)
The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s. The Cyclic Steam Stimulation or "huff-and-puff" method has been in use by Imperial Oil at Cold Lake since 1985 and is also used by Canadian Natural Resources at Primrose and Wolf Lake. In this method, the well is put through cycles of steam injection, soak, and oil production. First steam is injected into a well at a temperature of 300 degrees Celsius for a period of weeks to months, then the well is allowed to sit for days to weeks to allow heat to soak into the formation, and then the hot oil is pumped out of the well for a period of weeks or months. Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes higher than the money made from producing oil. The CSS method has the advantage that recovery factors are around 20 to 25% and the disadvantage that the cost to inject steam is high.
Steam Assisted Gravity Drainage (SAGD)
Steam assisted gravity drainage was developed in the 1980s by an Alberta government research center and fortuitously coincided with improvements in directional drilling technology that made it quick and inexpensive to do by the mid 1990s. In SAGD, two horizontal wells are drilled in the oil sands, one at the bottom of the formation and another about 5 metres above it. These wells are typically drilled in groups off central pads and can extend for miles in all directions. In each well pair, steam is injected into the upper well, the heat melts the bitumen, which allows it to flow into the lower well, where it is pumped to the surface. SAGD has proved to be a major breakthrough in production technology since it is cheaper than CSS, allows very high oil production rates, and recovers up to 60% of the oil in place. Because of its very favorable economics and applicability to a vast area of oil sands, this method alone quadrupled North American oil reserves and allowed Canada to move to second place in world oil reserves after Saudi Arabia. Most major Canadian oil companies now have SAGD projects in production or under construction in Alberta's oil sands areas and in Wyoming. Examples include Suncor’s Firebag project, Nexen's Long Lake project, Petro-Canada's MacKay River project, Husky Energy's Tucker Lake and Sunrise projects, Shell Canada's Peace River project, Encana's Foster Creek development, ConocoPhillips Surmont project, and Devon Canada's Jackfish project,Japan Canada Oil Sands Ltd's (JACOS) Hangingstone project and Derek Oil & Gas`s LAK Ranch projekt. Alberta's OSUM Corp has combined proven underground mining technology with SAGD to enable higher recovery rates by running wells from underground within the oil sands deposit, thus also reducing energy requirements compared to traditional SAGD. This particular technology application is in its testing phase and has stranded oil and other carbonate applications as well.
Vapor Extraction Process (VAPEX)
VAPEX is similar to SAGD but instead of steam, hydrocarbon solvents are injected into the upper well to dilute the bitumen and allow it to flow into the lower well. It has the advantage of much better energy efficiency than steam injection and it does some partial upgrading of bitumen to oil right in the formation. It is very new but has attracted much attention from oil companies, who are beginning to experiment with it.
The above three methods are not mutually exclusive. It is becoming common for wells to be put through one CSS injection-soak-production cycle to condition the formation prior to going to SAGD production, and companies are experimenting with combining VAPEX with SAGD to improve recovery rates and lower energy costs.
Toe to Heel Air Injection (THAI)
This is a very new and experimental method that combines a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the "toe" of the horizontal well toward the "heel", which burns the heavier oil components and drives the lighter components into the production well, where it is pumped out. In addition, the heat from the fire upgrades some of the heavy bitumen into lighter oil right in the formation. Historically fireflood projects have not worked out well because of difficulty in controlling the flame front and a propensity to set the producing wells on fire. However, some oil companies feel the THAI method will be more controllable and practical, and have the advantage of not requiring energy to create steam.
Tar sands development has a direct impact on local and
In Alberta, the strip mining form of oil extraction destroys
the boreal forest, the bogs, the rivers as well as the natural landscape. The
mining industry believes that the boreal forest will eventually colonize the
reclaimed lands, yet 30 years after the opening of the first open pit mine
near Fort McMurray, Alberta, no land is considered by the Alberta Government
as having been reclaimed.
For every barrel of synthetic oil produced in Alberta, 80 kg of greenhouse gases are released into the atmosphere. About 5-10% of the two to four barrels of water used for processing is considered as wastewater.
Greenhouse gas emissions
In ratifying the Kyoto Protocol, Canada agreed to reduce, by 2012, its greenhouse gas emissions by 6% with respect to the reference year (1990). In 2002, Canada's total greenhouse gas emissions had increased by 24% since 1990. The tar sands projects have been blamed for this increase by certain environmentalists, but no direct proof has been given.
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The release of vast amounts of contaminated water into the
environment of the Athabasca River has resulted in reports of more frequent
cancers downstream. These are blamed on the Tar Sands developments, and would
be consistent with the known impacts of petroleum development.
More Web Resources
Oil Tar Sand Concepts
Oil Tar Sand Extraction Cost
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