Steam-assisted gravity drainage makes debut

The use of steam and gravity to dislodge oil from the tar sands underlying Alberta and Saskatchewan is gradually becoming an accepted recovery technique as pilot projects mature into commercial operations.

The first commercial-scale project to use steam-assisted gravity drainage (SAGD) is EnCana‘s (ECA-T) Foster Creek, near Cold Lake, Alta. Foster Creek is currently producing about 20,000 barrels per day from 24 pairs of wells. Daily production is expected to rise to 30,000 barrels by next year and to 100,000 barrels by 2007.

In the first phase of the operation, EnCana expects to recover about 70% of an estimated 340 million barrels of oil, compared with an average recovery rate of 28% for Alberta’s conventional oil wells.

To date, most operations in the oil sands have been open pit mines, but about 93% of the remaining bitumen is too deep for surface access. If EnCana and other companies experimenting with SAGD meet their goals, the technology may soon become standard industry practice.

“In recent months, we’ve heard a lot about the importance of reducing North America’s dependence on energy imports,” says Brant Sangster, vice-president of oil sands for Petro Canada (PCA-T), which is spending $5.8 billion on new oil sands development. “For decades, we’ve known of the immense potential of the Alberta oil sands, but the challenge has always been that the lion’s share of the deposits is trapped too deep to be mined from the surface. This is why SAGD is exciting technology — it lets us gain access to these deeper deposits economically and with minimal surface impact on the environment.”

SAGD is a simple process consisting of two horizontal wells, one above the other. Steam injected into the upper well heats the surrounding sand, reducing the viscosity of the oil-bearing bitumen. The oil then drains by gravity into the lower well where it is collected and lifted to surface. A typical well pair is spaced 5-6 metres apart at the base of the reservoir and drilled to a length of 1,000 metres.

The simplicity of the concept, the relatively minor environmental disruption, and the resulting recovery rates have encouraged companies to launch at least 30 different pilot projects to test the technology. Now, billions are being spent to turn these projects into commercial operations.

Foster Creek

But SAGD does not make sense for all oil sands reservoirs. For the process to be viable, the reservoirs need to be thick, relatively shallow, highly permeable and porous and well-saturated with oil. For example, the Foster Creek reservoir ranges in thickness from 45 to 55 metres at a depth of 500 metres within the relatively permeable McMurray formation. The average oil saturation there is 85%, increasing to 90-95% in some zones.

Another obstacle is the layer of natural gas that sometimes overlies the bitumen reserves. If the gas is extracted, the reservoir pressure falls. As a result, some of the steam injected to loosen the bitumen can migrate into the empty gas reservoir, or “thief zone,” increasing operating costs. The drop in pressure can also affect SAGD recovery rates.

The conflict between gas and oils sands producers reached a climax in the mid-nineties, when Gulf Canada (now Conoco Canada Resources [CNK.PR.A-T]), demanded that gas producers suspend production on the company’s Surmont lease near Fort McMurray. Naturally, the gas producers, who were granted their leases in good faith, fought back.

In 2000, the Alberta Energy & Utilities Board ordered the shut-in of the 146 gas wells on or next to Conoco’s bitumen leases, which have recoverable reserves of 5-10 billion barrels. Just last month, Conoco announced it had finally resolved the disputes arising from that decision and was seeking regulatory approval to extract 100,000 barrels per day from the site. It would do so through Conoco Oil Sands Partnership. Later this year, the company will decide if it will proceed with commercial development.

SAGD projects are also sensitive to natural gas prices because gas is used to heat the huge quantities of steam and to power the operation. “Higher natural gas prices are having a negative impact on the economics of in situ technologies,” the Energy Council of Canada said in a report released last summer, when gas prices were peaking.

Some companies are reducing their exposure to this uncertain market by reducing the amount of steam they use and investigating alternative fuels.

“We’ve been developing techniques where we try to minimize the energy and steam requirements for SAGD,” says Dr. Tawfik Nasr, team leader of thermal oil recovery at the Alberta Research Council.

One such technique involves combining the steam with different additives. Others entail building co-generation plants that provide a steady, long-term source of power and steam while producing excess electricity that can be sold on the open market.

Mackay River

For example, Petro Canada’s Mackay River project, scheduled to reach commercial production in late 2002 at the daily rate of 30,000 barrels, will be fueled by a 165-megawatt (MW) natural-gas-fired co-generation power plant near Fort McMurray. The plant will be owned and operated by TransCanada Pipelines, which will provide 10 MW of power to the Mackay River project and sell another 60 MW under long-term contracts.

Other commercial SAGD projects that have received regulatory approval include Christina Lake, where EnCana expects to produce more than 70,000 barrels of bitumen per day for 30 years, and Suncor‘s Firebag, which will begin producing at 35,000 barrels a day in 2005, expanding to 140,000 barrels per day by the end of the decade. Several more projects are in the pipeline.

— The author is a Toronto-based freelance writer on mining and environmental issues.