The Athabasca oil sands story

For centuries, the sticky bitumen of northern Alberta was good for little more than caulking Chipewyan Indian canoes -- and leading entrepreneurs astray.
The first attempt to exploit the oil sands came nearly a century ago, when oilmen tried drilling conventional wells in the area, convinced that the bitumen on the surface must be welling up from gigantic pools of crude deep in the Earth. Two dozen wells were drilled over 11 years, with zero success Small-scale operations producing asphalt popped up in the ensuing decades, but cheaper sources of the product elsewhere in the world eventually bankrupted every one of those efforts.

It was not until 1967 that the oil industry began to make a business out of bitumen, when the Great Canadian Oil Sands Project, which eventually became Suncor Energy, began production.
Swings in oil prices, particularly the collapse of the mid-1980s, left the sector's viability in continual question. In part because of shrinking opportunities for conventional exploration, interest in the oil sands grew, with tens of billions of dollar invested in the 1990s.

Despite a record of multibillion-dollar cost overruns, that investment has pushed production of bitumen and synthetic crude past 1 mm bpd -- with capital spending predicted to double that to 2 mm bpd over the next five years, and perhaps to 3 mm by the middle of the next decade.
Even with that soaring growth, there are decades, and likely centuries, of production in the oil sands. The best official estimate of oil that can be profitably extracted is 175 bn barrels -- second only to the reserves of Saudi Arabia.

Oil sands projects

Shell Canada,
Western Oil Sands,
ChevronTexaco.
Athabasca Oil Sands Project -- mining
Capacity: 155,000 bpd
Cost: $ 5.7-bn
Start of production: January, 2003

Canadian Natural Resources.
Horizon -- Mining
Capacity: 232,000 bpd
Projected cost: $ 10.8-bn
Start of production: 2008

Syncrude Canada.
Stage 3 expansion -- Mining
Capacity: 360,000 bpd, total
Projected cost: $ 7.8-bn
Start of production: 1978 for original operations

Nexen,
OPTI Canada.
Long Lake -- in situ
Capacity: 60,000 bpd
Projected cost: $ 3.5-bn
Start of production: 2006

Suncor Energy.
Millennium, Firebag (latest expansions) -- Mining and in situ
Capacity: 225,000 bpd, total
Cost or projected cost: $ 3.4-bn for Millennium expansion
Start of production: 1967 for original operations

Imperial Oil.
Kearl Lake -- in situ
Capacity: Up to 300,000 bpd
Projected cost: $ 5-bn to $ 8-bn
Start of production: 2009

Husky Energy.
Sunrise Thermal Project -- in situ
Capacity: 200,000 bpd
Projected cost: Undisclosed
Start of production: 2008

Petro-Canada
MacKay River SAGD project -- in situ
Capacity: 30,000 bpd
Cost: $ 300-mm
Start of production: Fall 2002

Athabasca area
At 40,000 sq km. It is Alberta's largest and most accessible reserve of bitumen. Some ofthe oil sands near Fort McMurray are close to the surface and can be mined, but less than 20 % of the total area can be developed this way. In-situ techniques, which melt the bitumen and pump it from underground, are needed for deeper deposits.

Peace River area
The smallest of Alberta's oil sands areas at 8,000 sq km, its deep deposits are also being recovered with in-situ methods.

Cold Lake area
At 22,000 sq km, it is the province's second-largest reserve of bitumen. Its deep deposits are being recovered using in-situ technology.

Extraction and refining
Mining
The mining process begins with the removal of vegetation, muskeg and a thick layer of clay, silt and gravel. (The soil is saved to build the tailing ponds that will hold the sands once bitumen has been extracted.)
Oil sands are mined using shovels with buckets that hold 100 tons of soil, loading huge 240- to 360-ton trucks. The mine delivers about 450,000 tons of oil sand a day to the ore preparation plants, with twotons needed to produce one barrel of synthetic oil.

Crushers and sizers in the preparation plants prepare the ore for delivery to primary extraction through pipelines after the ore has been mixed with water. Primary extraction plants on both sides of the Athabasca River separate raw bitumen from the sand.
In secondary extraction, the bitumen is cleaned by removing fine clay particles and water. The thick bitumen is diluted with naphtha and treated to remove remaining minerals and water. It is then stored in holding tanks and delivered to the upgrader for processing. The water, clay, sand and tailing (residual bitumen) are pumped to holding ponds where they are treated to speed up the reclamation process that will restore the landscape.

In situ
Unlike mining, in-situ production does not disturb the top soil. Instead, steam-assisted gravity drainage (SAGD) technology uses underground wells to inject steam into the oil sands deposits, melting the bitumen and allowing it to be pumped above ground. The recovered bitumen is sent by pipeline to be upgraded.

Upgrading
In upgrading, naphtha is removed and recycled back to extraction. The bitumen is heated in furnaces and sent to drums where petroleum coke is removed. Coke, which is similar to coal, is used as a fuel source for the utilities plant. Depending on customer requirements, sulphur can be removed by hydrotreating the products. Sulphur is recovered and sold to fertilizer manufacturers.

The utilities plant provides steam, water and power for the rest of the operation. Additional steam and power is supplied through TransAlta's natural gas-fired cogeneration plant and two steam turbine generators.
Refinery-ready feedstock and diesel fuel is shipped by pipeline to customers and commercial and industrial markets throughout North America.