Bitumen

Bitumen is the heaviest, thickest form of PETROLEUM. The 2 largest-known sources of bitumen (in Alberta and Venezuela) each contain more petroleum than the entire proven conventional oil reserves of the Persian Gulf. Synthetic crude oil produced from bitumen accounts for about 28% of Canada's total oil production. Compared to conventional oil (obtained from traditional, easily accessible sources), however, synthetic crude from bitumen is expensive and complicated to produce.

Description
Unlike conventional crude oil, bitumen does not flow freely: it is heavier than water and more viscous than molasses. Most of the hydrocarbons in bitumen are heavier than pentane, and about half are very heavy molecules with a boiling point over 525° C. The light fractions are high in naphthenes (used in making gasoline and PETROCHEMICALS); the heavy fractions are high in asphaltenes (used in making asphalt). Bitumen also contains up to 5% sulphur by weight, and small amounts of oxygen, heavy metals and other contaminants.

Most deposits contain mixtures of bitumen, sand, water, small amounts of heavy metals and other contaminants. In its natural state, bitumen is suitable only for paving roads. Compared to conventional crude oil, bitumen contains too much carbon and too little hydrogen. In making synthetic crude oil, special refining processes are used to remove impurities and correct the carbon-hydrogen imbalance. Most Canadian refineries require this type of feedstock. To deliver bitumen to those refineries equipped to handle heavy crude oil, it must first be diluted with natural gas condensate or similar material to make it pumpable.

Reserves
The bitumen reserves occur in 3 major Alberta areas, Athabasca, Cold Lake and Peace River, and are found in oil sand and carbonate sedimentary formations. The 41 000 km³ Wabiskaw-McMurray deposit (historically referred to as the Athabasca deposit) surrounding Fort McMurray is largest and nearest the surface. The ATHABASCA RIVER cuts a channel through the oil sands in places, and natives used the tarry bitumen to caulk canoes before the first Europeans arrived in the late 18th century.

Since the late 19th century, people have schemed to tap the petroleum wealth of the oil sands. Some Edmonton streets were paved with bitumen early in the twentieth century. The International Bitumen Company and Abasand Oils Ltd produced asphalt from the Athabasca sands in the 1930s. Until recently, Alberta's bitumen deposits were commonly known as "tar sands," but industry and government now prefer the more descriptive term, oil sands.

In the northwest corner of the Athabasca deposit, several ore bodies lie within 80 m of the surface. About 10% of the deposit's approximately 144 billion m³ of bitumen occurs here. About 5.3 billion m³ of bitumen, corresponding to 4.5 billion m³ of synthetic crude and equivalent to more than 50 years of Canadian oil consumption at the 1987 rate, were considered recoverable under economic conditions prevailing in 1985. This area contains the world's only 2 commercial surface mining oil-sands operations; both use the hot-water process, developed by Karl CLARK of the ALBERTA RESEARCH COUNCIL, Sidney Ellis and R.C. Fitzsimmons and patented in 1929 for separating bitumen from oil sands.

In 1967 Great Canadian Oil Sands Ltd, now part of Suncor Energy Ltd, opened the first modern upgrading plant, and now produces more than 12 000 m³/day of high-quality synthetic crude oil. Syncrude Ltd, which opened in 1978, saw its production level of 20 500 m³/day increase to 41 000 m³/day in 1998 with the completion of an $8 billion expansion project.

A sizeable market for heavy oil opened in the northern US in the 1980s and, in response, several commercial in situ recovery operations started producing bitumen. Amoco's Wolf Lake, originally owned by British Petroleum and Petro-Canada, and Primrose projects were producing an average 5000 m³/day in the first quarter of 1999. Elan produces an average 1100 m³/day at their Lindbergh and Elk Point operations. Suncor started the Burnt Lake project at the end of 1997, and was producing about 300 m³/day by 1999.

Esso Resources brought 6 phases on-stream at Cold Lake through 1987, achieving bitumen production of 12 000 m³/day. Work then started on Phases VII-X which should increase production to 22 000 m³/d by the end of the decade at an additional cost of $375 million; another 6-8 phases will likely be added in the 1990s. Murphy Oil mothballed its Lindbergh operation in 1986 because of the collapse in oil prices but brought it back on-line in late 1987, achieving 400 m³/d. Koch produces 375 m³/d at Fort Kent. These first 4 commercial in situ projects are located on the Cold Lake deposit, whereas the 5th, belonging to Shell Oil, produces 1000 m³/d from the Peace River deposit.

Esso had originally proposed a large in situ project at Cold Lake in the 1970s, but shelved it in 1981 because of uncertainty about inflation, interest rates and world oil prices (see ENERGY POLICY). In 1982, for similar reasons, the Alsands consortium dropped its plans for a large surface-mining project near FORT MCMURRAY. Both Esso and Alsands planned 22 000 m³/day operations, with capital costs estimated at $12 billion each.

Their proposals, which included upgraders, indicated that the economics of surface and in situ extraction are very similar. However, implementation of new technology and operating practices has made new mining ventures attractive in a $12 per barrel world. For example, Syncrude finds it feasible now to develop their Aurora mine, which is 50 km NE of their current facilities. Consequently, Syncrude and Suncor have implemented much of this new technology and are expanding their operations significantly. Shell, Mobil and Koch are planning or designing new ventures across the Athabasca River from Syncrude and Suncor.

Mining of Oil Sands
Because of the contaminants and the high viscosity, the first problem in exploiting bitumen is bringing it to the surface. Both Suncor and Syncrude use open-pit MINING techniques to extract oil sands. However, only about 150 billion m³ or 8% of Alberta's bitumen can be reached by surface mining; the remainder requires in situ recovery techniques.

At Suncor and Syncrude the ore bodies are 30-70 m thick and buried at depths of 15-35 m. The overburden consists of varying proportions of Cretaceous silts, clays and shales (Clearwater formations, 65-140 million years old) overlying the Fort McMurray oil sands, and Pleistocene (1.6-0.01 million years old) sands and gravels deposited unconformably on the Clearwater formations. MUSKEG, up to 5 m in thickness, covers about 40% of the terrain. Muskeg-free areas are generally covered by bush.

Areas to be mined are cleared of trees, then drained. The muskeg is removed during winter and stockpiled for reclamation use. At Suncor, overburden is removed by a large hydraulic shovel which strips the material and loads it into 70 t trucks. About 80% is used to construct haulage roads and tailings dikes. At Syncrude, part of the overburden is cast directly into the mined-out area by draglines, but most is removed by two 15 m³ hydraulic shovels, a fleet of seventy 170 t diesel-electric trucks and other earth-moving equipment. Suncor mines the oil sand with huge hydraulic shovels operating on benches 20 m high.

In winter, with temperatures of -30°C to -40°C, the frozen oil sand may be dynamited before excavation to facilitate digging, but for the most part the oil sand remains unfrozen and is simply excavated using large hydraulic shovels and transported by 170 t or 350 t diesel-electric trucks to an extraction plant. In general, oil sands containing less than 6% (Syncrude) or 8% (Suncor) bitumen are discarded as unprofitable. The direct operating costs of mining (excluding utilities) account for 25-35% of the total direct costs (excluding interest, royalties and taxes).

In Situ Recovery
The Athabasca deposit contains an estimated 212 billion m³ of bitumen lying under 0-750 m of overburden; Cold Lake contains 32 billion m³ and Peace River contains 25 billion m³, for a total of 269 billion m³. Surface mining, currently limited to overburden depths of less than 46 m, might ultimately be feasible up to about 80 m. Successful in situ experimentation, notably by Esso at Cold Lake, has demonstrated that a significant 15-25% of the bitumen lying below 300 m can also be recovered.

Esso Resources has been experimenting continuously with in situ techniques at Cold Lake since 1964. Pilot plant production, which reached commercial volumes in the early 1980s, had increased to 3100 m³/day by late 1987. Esso's method, called "huff and puff," involves injection of high-pressure steam for 1-2 months to heat the formation. Injection is then discontinued briefly for 4 or more months. The bitumen seeps back to the injection wells, which now become production wells operated by pumping. Cold Lake bitumen is 11° API (American Petroleum Institute specific gravity scale) lighter than Athabasca bitumen and this relative lightness facilitates recovery. Initial recovery is about 20% of the in-place reserves, but it is expected that communication between wells will be established eventually, and will increase recovery efficiency.

Shell Canada Resources Ltd's Peace River lease is unique in that it contains a 24 m layer of uniform oil sand over a 1 to 3 m layer containing mostly water. Shell's pilot-plant technique in the 1980s was to inject steam into the water layer and allow the heat and pressure to spread into the oil sands. Unfortunately this process proved to be uneconomic. Current tests used a modified process described later.

There has been much experimentation to develop more efficient processes for recovery of bitumen. Of these novel processes, ones using in situ combustion proved to be uneconomic. With development of technology for drilling and completing horizontal wells, gravity drainage became feasible. A consortium of companies led by the Alberta Oil Sands Technology and Research Authority (AOSTRA) completed a facility to test in situ processes. This $130 million effort placed the researcher in a relatively impermeable dolomite formation below the reservoir. Wells were drilled upwards then horizontally from this formation into the oil sands. Of the many processes tested, the Steam Assisted Gravity Drainage (SAGD) process proved feasible, providing clean bitumen at a cost of $6 per barrel. Recovery for isolated wells exceeded 60%. Since then, methods to pump the oil to the surface in a controlled manner have been developed. Current SAGD production exceeds 4000m³/day.

Bitumen Extraction
Oil sand, as mined commercially, contains an average of 10-12% bitumen, 83-85% mineral matter and 4-6% water. A film of water coats most of the mineral matter, and this property permits extraction by the hot-water process. The oil sand is put into massive rotating drums and slurried with warm water and some steam. Droplets of bitumen separate from the grains of sand and attach themselves to tiny air bubbles. Conditioned slurry is passed through a screen to remove rocks and large pebbles and pumped into large, conical separation vessels where a froth of bitumen is skimmed from the top containing about 65% oil, 25% water and 10% solids. The coarse sand settles and is pumped to disposal sites. Some of the smaller bitumen and mineral particles remain in an intermediate water layer, called middlings and are pumped onto a separation vessel similar to the one mentioned above.

Generally, 88-95% of the bitumen in the mined ore is recovered. Coarse sand from the primary separators is used to build dikes, forming the large tailings ponds needed to contain the effluent. In these ponds the fine particles settle slowly, producing clarified water that is reused in the extraction process. The fine particles do not consolidate to their original density, so every cubic metre of oil sand mined creates 1.4 m³ of material for disposal. Removal of the contaminants from the froth stream is achieved through dilution with naphtha followed by 2 stages of centrifugation. Syncrude has recently installed inclined-plate gravity settlers in series with the centrifuges. About 98% of the bitumen in the froth is recovered. The water needs of a large project like Syncrude are substantial, amounting to about 0.4% of the average flow of the Athabasca River (see WATER POLLUTION).

Economic and environmental incentives still exist to improve recovery, reduce heat and water requirements, and shrink or eliminate tailings ponds. Consequently, many alternatives have been investigated over the years, including retorting, solvent extraction, addition of chemicals, spherical agglomeration and the use of oleophilic sieves and hydrotransport. Of these, hydrotransport features largely in Syncrude's expansion; the slurry is pumped from the mine face up to about 10 km to the extraction plant. Such means are a good substitute for the large rotating drums mentioned earlier.

Bitumen Upgrading
Suncor and Syncrude both use coking processes to remove carbon from the heavy fractions of bitumen. Coking involves thermally cracking the heavy fractions (at 468-498° C) to produce lighter fractions (eg, gasoline, fuel gas) and petroleum coke (some of which may be used as fuel). At Syncrude, fluid coking, a high temperature process (about 530°C) produces slightly less coke and more liquid hydrocarbons than the delayed coking used by Suncor. As new extraction technology is implemented, the cost of producing bitumen decreases, thus favouring use of delayed cokers. Suncor continues to burn coke in its boilers but is increasingly concerned by the intense emissions of sulphur dioxide.

Hydrocracking processes, which add HYDROGEN, offer higher liquid yields, better distillate qualities and lower emission levels of sulphur dioxide, but at much greater expense. The catalysts used in the hydrocracking process rapidly lose their needed properties as they become fouled by the vanadium in the bitumen. Consequently, alternative processes that provide continuous replacement of catalyst have been demonstrated. But they are losing favour as the supply cost of bitumen decreases. Much hydrogen is used in the hydrocracking process and it is most economically derived from steam cracking of methane. Yet methane is becoming more and more expensive as it becomes the preferred fuel of North America.

The distillates obtained from the hydrocracker, the delayed coker and the fluid coker are good feedstock for a conventional refinery. However, such distillates are "live," tending to polymerize and foul surfaces, and must be mildly hydrotreated before being pumped through pipelines to distant refineries. This mildly hydrotreated feedstock is called synthetic crude.

Conclusion
The future of oil sands production appears to be extremely positive as gradual implementation of new technology makes the industry more competitive with international suppliers. In June 1996, Prime Minister Jean Chrétien and the presidents of 18 of Canada's largest oil companies signed a "Declaration of Opportunity" for further oil sands development. The expansion's goal is to increase production from the 400 000 barrels a day to 1.2 million barrels a day. It seems likely that production will exceed this goal. Much of this success is owed to implementation of new technology and the successful collaboration of the governments of Canada and Alberta and industry.

Author G.R. GRAY AND R. LUHNING

Links to Other Sites
Alberta's Oil Sands
An extensive information source about recent technological advances in the exploration and development of Alberta's oil sands, the second largest proven concentration of oil in the world. Also covers related environmental issues. A Government of Alberta website.

Pipeline: Inside the Oil Patch
This blog offers the latest news about Canada's petrochemical industry. From the Calgary Herald.

Canadian Petroleum Products Institute
The website for the Canadian Petroleum Products Institute, an association of major Canadian companies involved in the refining, distribution, and marketing of petroleum products. See basic descriptions of petroleum products, the latest industry news, and related statistics.

The Canadian Society of Petroleum Geologists
Information of interest to petroleum geologists in Canada. Check out the link to SIFT (Student Industry Field Trip) for post-secondary students in geology and related fields.

Oil Sands Discovery Centre
Dig into the history, science and technology of Alberta's oil sands at the website from the The Oil Sands Discovery Centre in Fort McMurray, Alberta.

oilweek
See the latest news and feature articles about Canada's dynamic oil and gas industry.

Oilsands considered crucial to future oil supplies
This 2008 news story highlights environmental effects, high costs and other issues concerning development of Canada's oilsands. From the canada.com website.

Glossary: Oil Sands
A bilingual glossary of terms related to the oil sands industry. From the website "Canada's oil sands."

Canadian Energy Research Institute
This organization focuses on economic research in energy and environmental issues related to the petroleum industry. See "Publications" to view online copies of detailed research reports.

Enbridge
The website for Enbridge, a Canadian company that transports and distributes energy across North America. Click on "About Enbridge" to access their interactive map which displays current pipeline routes and statistics.

Local Push - Global Pull
The website for "Local Push - Global Pull", Joyce Hunt's book that provides a comprehensive history of Canada's oil sands from 1890 to 1930.

Canadian Association of Petroleum Producers
The website for the Canadian Association of Petroleum Producers, a great information source about all aspects of Canada's upstream oil, oil sands, and natural gas industry.