The recoverable portion of Canada’s crude bitumen resources, a black tarry hydrocarbon that coats the sands and carbonate sedimentary formations in the Athabasca, Cold Lake and Peace River regions of northern Alberta, is large enough to satisfy the country’s total domestic crude oil requirements for the next 200 years.
According to the Canadian National Energy Board, Alberta’s oil sands currently contain 1.63 trillion barrels of crude bitumen resources, based on estimates published by the Alberta Energy and Utilities Board, and may ultimately contain as much as 2.52 trillion barrels. Of that total, 178 billion barrels of bitumen can be recovered and economically upgraded into synthetic crude oil using existing technology. Ultimately, 12%, or 309 billion barrels of the total resource projection, may be recoverable. For comparison purposes, this is roughly equivalent to the proven conventional oil reserves in Saudi Arabia.
A heavy crude oil, bitumen is too thick to flow through rocks, well bores or pipelines. The accepted theory for the formation of the oil sands is that lighter oil sourced in the deeper portions of the Western Canada Sedimentary Basin in Mississippian and Jurassic-age sediments migrated long distances to their present-day locations. The McMurray sandstone formation or equivalent sands were the main conduits for migration. The migration path is speculated to be at least 360 km for the Athabasca deposit and at least 80 km for the Peace River deposits.
Subsequently, biodegradation transformed the lighter oil into a black, tar-like material known as bitumen. The oil sands deposits are composed of quartz sand, silt and clay, water and bitumen, plus trace amounts of other minerals. The oil sands are generally unconsolidated and quite friable, crumbling easily in the hand. The deposits are typically 40-60 metres thick and overlie relatively flat limestone beds.
Bitumen is heavy, viscous and deficient in hydrogen, compared to conventional crude, which is a problem for conventional refineries. It has to be upgraded locally through the addition of hydrogen or the rejection of carbon, and transported to market after blending with a condensate, to meet pipeline specifications for density and viscosity.
First recognized in the 1700s, the Alberta oil sands have a long and colourful history marked by individuals, such as Sidney Ells and Karl Clark, who spurred on research and development through much of the early to mid 1900s. The first large-scale integrated surface mining and upgrading plant was built in 1967 by Great Canadian Oil Sands, now Suncor. The Syncrude project, owned by a consortium of companies, followed in 1978.
Bitumen can also be extracted using various thermal in situ recovery techniques incorporating cyclic stream stimulation (CSS), horizontal well technology and steam-assisted gravity drainage (SAGD). The first large-scale commercial in situ project was developed by Imperial Oil in 1978 at Cold Lake.
Technological innovation and the consequent decline in costs are largely responsible for the resurgence in oil sands investment. The early mining operations of both Suncor and Syncrude suffered from startup problems and high production costs of $35 per barrel. In the last 20 years or so, costs were substantially reduced through a process of continuous improvement in all aspects of operations.
However, the 1990s saw two major technical innovations which resulted in operating costs falling to the $11 to $14 per barrel range.
First, there was a move to replace large-scale draglines and bucket-wheel excavators with large mining trucks and power shovels, which offered increased flexibility, lower maintenance and improved efficiency. The second major innovation was the introduction of the hydrotransport process, which uses less costly and more energy-efficient slurry pipelines, instead of conveyor belts, to transport the oil sands to the extraction plant.
Supply costs for in situ operations have also been reduced through ongoing improvement and innovation, though not to the same extent as in the surface mining operations. Costs for CSS are estimated to be in the $10-to-$16-per-barrel range, whereas those for SAGD are $8 to $4 per barrel. Costs for both methods are highly dependent on the quality of the reservoir.
Both integrated mining projects and thermal in situ projects use substantial amounts of natural gas as a fuel source in their operations. Thus, the price of natural gas can play a role in their level of profitability.
The next wave of oil sands projects coming on-stream includes Shell’s Athabasca project, a joint venture with
After BHP pulled out of the joint venture, Shell brought in Chevron and Western Oil as minority partners and proceeded with the development of the Athabasca oil sands, announcing a go-ahead decision in late 1999. Western Oil was selected as a partner based on its mining expertise. “Western are the dirt movers,” said Neil Camarta, Shell’s senior vice-president of the oil sands division, during a presentation at the Scotia Capital Integrated Oil Conference. “Oil sands is 85% dirt, and you better bring in people who know how to move dirt.”
The Athabasca project consists of two main components: the Muskeg River mine, 75 km north of Fort McMurray, and the Scotford upgrader, in Fort Saskatchewan, beside Shell’s Scotford refinery, north of Edmonton.
The Muskeg River mine will be an open-pit operation producing bitumen at a rate of 155,000 barrels per day from a resource estimated to contain 1.65 billion barrels bitumen. The initial mine life is projected at 30 years. The joint-venture partners have formed Albian Sands Energy as the holding company of the Muskeg River mine.
The oil sands will be mined from a 121-sq.-km area of Lease 13 using a combination of hydraulic and electric shovels, hydraulic excavators and 400-tonne haul trucks. The ore is to be dumped into a crusher and reduced in size to less than 41 cm, and then fed to rotary breakers for further crushing to less than 5-cm size. Heated water (40C) will be added to create a slurry, which is then pumped to the extraction plant.
The extraction process is designed to separate the bitumen from much of the sand, clay and other materials. Air will be added to the slurry and then pumped to large gravity-separation vessels. The bitumen attaches to the air bubbles and rises to the top to form a bitumen-rich froth, which is processed through a stripper, removing the air bubbles and directing the bitumen to two large froth storage tanks. The sand particles settle to the bottom and are pumped to the tailings processing system.
The bitumen froth is then sent to a multi-stage counter-current decantation circuit, a technique new to oil sands processing, but used for many years in mineral extraction. This process provides partial upgrading in the field. The extracted bitumen is blended with a paraffinic solvent, which promotes the precipitation of asphaltenes and thereby removes most of the carbon-laden or coke-producing components in the mixture.
A clean, diluted bitumen, low in contaminants and with the appropriate viscosity is then ready to be transported through a 444-long-km pipeline to the Scotford upgrader, which will use hydrogen-addition technology to process the bitumen into low-sulphur synthetic crude oils. Initial production will total 130,000 barrels per day of light synthetic crude oil plus another 60,000 barrels per day of
heavier grade vacuum gas oil.
These synthetic crude oils will be sold to Shell’s Scotford and Sarnia refineries, and Chevron’s Salt Lake and Burnaby refineries. Shell, Chevron Texaco and Western Oil are sharing the costs of constructing the Muskeg River mine and the Scotford upgrader based on their respective interests. However, initial capital estimates of $3.8 billion have soared 37% to $5.2 billion. Camarta blames some of the increase on a shortage of labour due to the high level of construction activity in the oil and gas industry. The project was also affected by price increases for piping and electrical.
Says Camarta: “The crunch has really been on the labour side, especially when we were going head-to-head with some of the other major oil sands projects last year. We just couldn’t get enough welders.”
In addition to the mine and upgrader operations, a number of new facilities are being constructed by companies outside the joint venture. The 444-km Corridor pipeline, which will carry bitumen slurry from the Muskeg River mine to the Scotford upgrader, is being built for $600 million by Trans Mountain Pipe Line, a subsidiary of BC Gas. “They’re right on track and on schedule, and they are doing a great job,” says Camarta.
ATCO Power Canada is building new cogeneration power plants at both the mine site and the Scotford upgrader. Shell, itself, is solely investing an additional $500 million to modify the Scotford refinery so that it can utilize the new synthetic crude oils.
Cash costs are projected at $10-12 per barrel, based on a natural gas price of $3.85 per thousand cubic feet. Every dollar increase in natural gas adds about 65 to the cost base. Based on the revised capital cost and a crude oil price of US$18 per barrel, the Athabasca project runs a projected 15% rate of return.
“It’s not as good as it used to be, because we’re dragging more of a piano behind us with this capital cost,” says Camarta. “But it does set us up with a pretty good growth platform.”
The Athabasca project is anchored on 1.65 billion recoverable barrels of bitumen on the west side of Lease 13. Another 3.2 billion barrels of bitumen lie on the east side of Lease 13, and two other leases, 88 and 89, contain an additional 3.9 billion barrels of bitumen. Down the road, Shell is looking to expand production at the Muskeg River mine by another 70,000 barrels per day before moving over to the east side and starting up the 200,000-barrel-per-day stand alone Jackpine mine. Shell initiated the regulatory review process for the Jackpine mine last fall. Camarta further envisions the Jackpine mine extending on to leases 88 and 89 and adding a further 100,000 barrels per day.
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