Posted on 04/14/2012 4:13:34 AM PDT by thackney
In a straight line, they’re 4,200 miles apart. And they’re years apart in commercializing their resources.
But, even if they’re not in the same geographical and time zone, the Canol shale in the Central Mackenzie Valley of the Northwest Territories and the heart of the Bakken in North Dakota have a common bloodline.
The Bakken is already living proof of the success new technology has in spawning a new generation hydrocarbon basin. The Canol shale shares that ambition to become a game changer, turning Canada’s North into a major unconventional oil and natural gas producer.
While the Bakken pushes boldly towards the magic 1 million barrels per day target, the Canol is only just advancing from decades of conventional oil production, fueled by a staggering federal land sale last summer which fetched C$536 million, led by Husky Energy at C$376 million, with Imperial Oil, Shell Canada and ConocoPhillips Canada, joined by junior explorer MGM Energy, playing key roles.
By mid-2016 at the latest — when license holders are required to drill their first exploratory well — there should be a clear indication whether the Canol will enter the big time.
Speculation and competition
For now, the basin is generating intense speculation and competition. John Hogg, MGM Energy’s vice president of exploration, said that when last year’s bidding results were released it “created quite a buzz. … I recognized it was about the new potential of the shales.”
But he told CI Energy Group’s Arctic oil and gas symposium in Calgary in March that one of the biggest initial challenges is to overcome the region’s regulatory challenges.
Hogg said those who have worked in the north over many years “find that it is probably one of the most difficult and unpredictable regulatory regimes (in Canada). The time for reviewing and improving the regulatory process is now, not during the development of the Canol shale resource.”
He described the Devonian-era Canol shale as a 375 million year old formation, deposited below the water in what was then a warm sea.
Norman Wells source rock
The life forms that died created the organic content that made the shale a source rock for the Norman Wells oil field, which has been producing for about 65 years, he said. The Canol shale has a high total organic content of 3 percent to 27 percent and an average of 9 percent to 12 percent, which Hogg rated as two to three times the average shale that is exploited in North America.
He said the resource is liquids-prone and has geochemical characteristics pointing to the production of some oil, with more left to be produced.
Hogg said all of the features are “very good when it comes to looking at this source rock from the point of view of exploration.”
C$5 million work commitment
And MGM has turned its attention to the Canol play, where it and 6362 NWT Ltd. made a work commitment of C$5 million for three exploration licenses covering about 628,000 acres. MGM President Henry Sykes said in a statement in late March the play “continues to show great potential.”
“We are currently focused on advancing the regulatory process and operational planning with the intention of drilling a well in the winter of 2012-2013.
“We are also looking for a partner as one option to assist in the development of this exciting shale oil play,” he said.
Sykes also said MGM is considering a “a number of alternative means of commercializing” its Mackenzie Delta gas assets, without offering any further hints, although it mirrors the mood among larger operators in Canada’s North who have set aside their hopes of participating in a gas pipeline from the Mackenzie Delta to concentrate on the scramble to enter the oilier Central Mackenzie Valley.
“The unconventional that we are going after will be more from a liquids perspective than from a gas perspective,” said Clayton Reasor, vice president of corporate and investor relations at ConocoPhillips, whose work commitments involve C$66.7 million for about 216,000 acres.
Norman Wells line underutilized
The Norman Wells oil field was discovered in the 1920s and has produced about 300 million barrels, although current output has dropped by 50 percent to 20,000 barrels per day. As a result, a 40,000 bpd Enbridge-operated crude pipeline covering 540 miles from Norman Wells to Zama in northwestern Alberta, and from there to the Edmonton refining hub, is underutilized, helping to spur a shift from conventional dolomite reefs which have failed to yield any new finds to the original source rocks.
The Canol shales, like their near relatives in the Bakken region, enjoy high porosity and are saturated with liquids, but must be hydraulically fractured because of their low permeability.
MGM plans involve moving heavy equipment by barge down the Mackenzie River, starting in September.
Once the land is frozen, MGM has about 100 days to drill, fracture and test a well before the spring thaw.
MGM has estimated that the cost of drilling, testing and completing its first vertical exploration well could run to C$25 million.
Other challenges involve the absence of a winter ice road to the drill sites, a shortage of skilled labor and high standby charges because there is no year-round drilling, along with a minimum regulatory cost of C$250,000.
Regulatory phase of 17 months
Hogg said it is important that holders of exploration rights also need assurances that once they acquire land that they can conform to the regulatory framework and not face constant changes. He said the regulatory phase involves six federal, four territorial and two regional regulators or agencies, representing a process stretching over about 17 months.
Any concerns that are raised could stop any portion of the process and could easily cost a full year.
Despite only preliminary data, Hogg is hopeful the Canol could be twice as productive as other North American shale plays.
He told the Arctic symposium that the industry needs a made-in-the-NWT solution to dispose of drilling mud and reclaimed water, drill cuttings and frac fluids and produced water.
“If we are to bring this project forward, we can’t be transporting all that fluid to Alberta or British Columbia,” Hogg said.
It could take up to five years to determine the scope of the play and whether the Canol can overcome its distance from market and northern challenges.
NWT Industry Minister David Ramsay told the symposium his government is working with the Canadian government to obtaining funding for an all-weather road down the Mackenzie Valley.
Northwest Territories? And folks think North Dakota is cold in the winter...
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