Extraheavy oil and oil sands

A large share of the world's remaining oil resources is classified as non-conventional.3 These resources - oil sands, extra-heavy oil and oil shales - are generally more costly to produce, though considerable progress has been made in addressing technical challenges and lowering costs. Oil sands and extra-heavy oil resources in place worldwide amount to around 6 trillion barrels, of which between 1 and 2 trillion barrels may be ultimately recoverable economically. Technically recoverable reserves, defined by the World Energy Council as resources which can be exploited profitably with today's technology, amount to some 1.1 trillion barrels using an average conservative recovery factor of 18% (Table 9.4).

The world's extra-heavy oil and oil sands resources are largely concentrated in Canada (mainly in the province of Alberta) and Venezuela (in the Orinoco Belt). Assuming a potential 20% recovery factor, these two countries would hold more recoverable resources than all the conventional reserves in the Middle East. Alberta alone has proven reserves today of 174 billion barrels (crude bitumen) and an estimated 315 billion barrels of ultimately economically recoverable resources. Nearly 80% of the

3. The IEA defines non-conventional oil as oil sands, extra-heavy oil, oil shales, coal-to-liquids (CTL) and ^ gas-to-liquids (GTL). Only the first four are considered here. The prospects for CTL and GTL are discussed ¡J in Chapter 11. §

c proven reserves in Alberta are in the Athabasca Wabiskaw McMurray deposit, while the remaining 20% are split between the Cold Lake Clearwater and the Peace River deposits. A one percentage-point increase in the recovery factor would boost recoverable resources by 60 billion barrels.

Table 9.4 • Extra-heavy oil and oil sands resources (billion barrels)

Extra-heavy oil

Oil sands

Oil in place

Recovery factor

Technically recoverable

Oil in place

Recovery factor

Technically recoverable

North America




1 659



South America

2 046






Middle East







Other regions




1 135




3 303



2 795



Several technologies exist to extract bitumen from oil sands. If the deposit is near the surface, oil sands are mined, using enormous power shovels and dump trucks. The bitumen is then extracted using hot water and caustic soda. The extracted bitumen needs to be upgraded (or diluted) with lighter hydrocarbons before it can be transported to a refinery. Upgrading consists of increasing the ratio of hydrogen to carbon, either by carbon removal (coking) or by adding hydrogen (hydrocracking), resulting in a synthetic crude oil that is shipped to a refinery.

When the heavy hydrocarbon deposit is deeper, drilling is required. When its viscosity is low enough or can be reduced enough for the oil to flow to the surface, long horizontal or multi-lateral wells are used to maximise well bore contact with the reservoir and reduce the drop in pressure in the well bore. This is the technique used for several of the heavy oil deposits in Venezuela's Orinoco Belt. The main drawback of such conventional production techniques is the low recovery factors, typically less than 15%. As a result, the expected amount of extra-heavy oil that could be recovered from the estimated 1 700 billion barrels in place in the Orinoco Belt is less than 250 billion barrels, using current technology.

Much higher recovery factors (up to twice those of conventional production technologies) can be obtained using in situ viscosity-reduction techniques. In situ technologies are currently used for highly viscous oils: they include cyclic steam stimulation injection (CSS) and steam-assisted gravity drainage (SAGD). Technologies being developed include a vapour extraction process, which uses hydrocarbon solvents instead of steam to increase oil mobility, the use of downhole heaters and hybrid methods. Theoretical recovery factors of 50% to 70% are predicted for SAGD and new in situ processes, significantly higher than with CSS (20% to 35%). The steam-oil ratio is also lower with SAGD (2 to 3) than with CSS (3 to 5), so less water would be required. About 20% of Alberta's bitumen can be mined, while 80% requires in situ recovery methods (ACR, 2004).

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