Wednesday, 9 June 2010

Alberta sitting on nearly 1.5 trillion barrels, says ERCB

Alberta sitting on nearly 1.5 trillion barrels, says ERCB

Province hikes bitumen estimate

CALGARY - A re-evaluation of emerging oilsands areas and advances in production technology have pushed Alberta’s bitumen resources toward 1.5 trillion barrels in 2009, according to a report by the Energy Resources Conservation Board.

According to the ERCB’s annual reserve report, which will be officially released today, the increase was driven by a re-evaluation of the largely untapped Grosmont deposit, which is now said to contain 406 billion barrels in the ground waiting for the right technology to extract it.

In situ oilsands production grew 14 per cent last year, along with a 14 per cent increase in mining output due in large part to the startup of Canadian Natural Resources’ Horizon mine, the report notes. But in situ is expected to be the strongest driver of future activity, said Carol Crowfoot, the board’s chief economist and report co-author.

“Particularly on the in situ side, we’re forecasting quite a growth rate for the next 10 years, due to the SAGD (steam assisted gravity drainage),” she said.

In situ oilsands production now accounts for about half of the 1.49 million barrels of bitumen produced per day, a figure that is expected to double to 3.2 million barrels per day by the end of the decade, the report said.

The Grosmont is a lesser-known fourth oilsands area — after Athabasca, Peace River and Cold Lake — that is unique because the bitumen is contained in limestone instead of sand. Producers have known about the Grosmont carbonates for decades, but lacked practical ways of getting it out of the ground.

Although the resource potential rose nearly 30 per cent in the first evaluation of the Grosmont reserves since 1990, no commercial reserves were assigned due to the lack of production.

That could change later this year when in situ players such as Laricina Energy begin constructing pilot projects aimed at testing new production technologies, including the application of solvents, to the previously unattainable bitumen.

The company is moving ahead with a commercial pilot at Saleski and hopes to be producing oil by the end of the year, Laricina president Glen Schmidt told the Herald on Friday.

He said he wasn’t aware of the revised resource numbers, but confirmed his company worked with the ERCB to help prepare the estimates.

“It is very exciting to see the ERCB start talking about the Grosmont,” he said.

“It is clearly the second-largest in situ play, by far. We like to give ourselves some credit for leading the charge.”

Companies such as Unocal attempted pilot projects in the 1970s and ’80s to no avail. In 2006, Sure Northern, a subsidiary of Royal Dutch Shell, spent more than

$500 million to buy Grosmont rights adjacent to 75,000 hectares controlled by Husky Energy.

Unlike a conventional in situ development, Schmidt said carbonates require less steam at lower temperature and pressure to drain the oil. Laricina is hoping that will in turn translate into lower operating costs.

“The better Grosmont projects will do every bit as good as the McMurray,” he said.

In other highlights of the report, the more commonly known McMurray-Wabiskaw deposit — characterized by truck and shovel mining — declined 0.4 per cent to 959 million barrels. Cold Lake was also re-evaluated for the first time since 1999, resulting in a 20 per cent drop in available resources to

33.8 billion barrels. The region is host to Alberta’s largest and oldest in situ development, operated by Imperial Oil.

The report notes Alberta has produced about seven billion barrels of raw bitumen since oilsands production first began in 1967, or less than half of one per cent of the available resource, compared with 16 billion barrels of conventional crude oil since 1914.

While oilsands production continues to rise, conventional oil declined almost nine per cent in 2009 to 461,300 barrels per day. About

3.5 billion barrels of conventional oil remain to be developed, although the report notes that new technology is starting to unlock “tight oil” in places such as the Pembina Cardium play.

Other big revisions were made to the province’s inventory of coal bed methane, which increased

90 per cent. Gas from coal accounted for seven per cent of Alberta’s total gas production in 2009, a figure that is expected to rise to

20 per cent by 2019, the report said.

Shale gas was expanded in the 2009 report, but no reserves were assigned to what could be a major new supply source in Alberta. As part of the Alberta government’s royalty holiday on new shale gas wells, the province last week initiated a study by the Alberta Geological Survey to determine the exact size and location of a resource that could top

850 trillion cubic feet.

“At the moment we don’t actually see enough data to do a calculation,” said Kevin Parks, who oversees the AGS. “But you have to start somewhere. We’re ramping up to generate our own reasonable numbers, what’s out there are kind of bold estimates.”

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