Canadian oil producers ought to be doing more to exploit the billions of barrels of conventional crude that remain in the ground, rather than solely focusing on developing Alberta's oilsands, an industry expert says.

Enhanced oil recovery (EOR) of conventional resources holds immense potential in the Western Canadian Sedimentary Basin at a fraction of the cost of multi-billion-dollar oilsands projects, adds Eddy Isaacs, managing director of the Alberta Energy Research Institute (AERI).

But because mounting a successful EOR project is a tough technical nut to crack, Issacs adds, it often represents a less-attractive option, especially given that very little in the way of new technology has been developed in recent years.

"It does require a lot of technical smarts to play this game," Isaacs said in an interview following a presentation at an oil conference in Kananaskis last week staged by the Canadian Energy Research Institute (CERI), a non-profit energy research group.

"And it does require that companies spend time and some capital to do it."

In Canada, the primary EOR methods have traditionally included steam and water flooding, hydrocarbon injection - usually injecting natural gas to increase formation pressure to make the oil easier to extract - and carbon dioxide (CO2) miscible flooding, achieved by injecting the gas into the formation.

Isaacs couldn't say how much capital spending has gone into EOR projects over the years or how much is planned for the future, but said he believes that given the existing infrastructure for conventional oil - pipelines, processing facilities, etc. - a mere fraction of capital dollars destined for heavy oil operations could achieve similar production results to that of the oilsands.

"Before people start abandoning these fields, if we can do something with enhanced recovery to produce a lot of this oil, then certainly we're going to be in very good shape, because it won't require a lot of capital," he said.

AERI is a provincially funded agency that promotes energy research, technology evaluation and technology transfer.

There is a lot to be gained by paying more attention to enhanced recovery of conventional crude, Isaacs said. A one-per-cent increase in conventional oil recovery would gross producers around $35 billion in revenue and governments about $4 billion in royalties, adding $60 billion to Canada's gross domestic product.

"But we need to better understand the EOR mechanism ... we need to do field testing and, of course, we need to implement the projects in the field. And all of this means we have to know something about the geology, we need to do a better job of (reservoir) modelling and keep an eye on the economics."

EOR activity was in its heyday in the 1980s, but since then has fallen off the radar screen somewhat. One reason for the decline in activity was several years of slumping oil prices during the 1990s, "but I think these things are going to change quite dramatically" given the strong oil prices in recent times, Isaacs told delegates.

One of the great EOR success stories has been the CO2 miscible flooding program in the Joffre fields in central Alberta. Isaacs noted that the 20-year EOR project has been "incredibly successful" and demonstrates the "tremendous potential CO2 has."

Alberta regulators, in the meantime, recognize that more must be done to expedite viable EOR projects in the province. Jim Dilay, an Alberta Energy and Utilities Board (EUB) board member, acknowledged the need to smooth out the regulatory process.

"What we're doing is making the regulations process simpler," to allow producers to implement EOR programs faster, he said.

The EUB estimates that close to five billion barrels of conventional oil can be retrieved from Alberta using enhanced recovery methods.

Still, the oilsands remain the big ticket to Alberta's energy future, says industry consultant Bob Dunbar, a former CERI research director who recently collaborated on the organization's soon-to-be-released supply study on the oilsands.

Quoting from study results, Dunbar said CERI predicts oilsands output will reach 2.6 million barrels per day (b/d) by 2015 from the current 1.1 million b/d, before hitting 3.7 million b/d by 2020.

To attain those production numbers the industry will have to overcome rising costs - especially high natural gas costs, which CERI expects to average $6 US per thousand cu. ft. (mcf) this year - and widening heavy/light oil-price differentials, which means producers unable to upgrade bitumen are not realizing the full benefits of vigorous crude prices.

While a wide differential should provide incentive for upgraders to build new capacity to upgrade bitumen to lighter synthetic crude oil, it becomes a tough sell due to the historic volatility of crude pricing.

"If (upgraders) knew for sure the differentials would remain wide into the future it would be an easy decision to make, but generally, as soon as new upgrading capacity comes onstream, the fact that new capacity arrives narrows the differential and takes away some of the benefit the upgraders had hoped to achieve," Dunbar said.

With regard to the natural gas market's affect on oilsands, Greg Stringham, vice-president of markets and fiscal policy with the Canadian Association of Petroleum Producers, said oilsands projects are becoming less reliant on gas for their operations, moving toward other options such as burning bitumen and heavy asphalt.

Meanwhile, recent news that the Mackenzie Pipeline Project is halting spending on engineering and design work until access and benefits issues with aboriginal communities and the regulatory process become clearer, should not be interpreted that the project will be cancelled, Stringham said.

"The producer group (lead by Imperial Oil Ltd.) has said they're very committed to this project and I have no reason to believe it won't go ahead," he added. "They got ahead of themselves on the engineering-design side because they were going full out, and they need to resolve the access benefits and need to get the regulatory process moved further along."

When asked about what a cancellation of the Mackenzie project would mean to heavy oil producers, he said the impact would be minimal.

"There has been a rumour out there that the heavy oil projects are relying on gas and will take all the gas coming out of the Mackenzie Delta, and that's just wrong," Stringham said. "They're using about .4 mcf to produce a barrel, so even if they continued using that much gas, and with an increase of about 1.7 million b/d of heavy oil output, you'd still be looking at 700 million cu. ft. per day of gas," which represents only about one-third of the projected maximum output from the Mackenzie Delta, he added.

(John Ludwick can be reached at ludwick@businessedge.ca)