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Cooling the heat of B.C. shale gas plays Experts: Handle B.C. potential resource figures with care, caution; focus instead on technically recoverable, marketable estimates Gary Park For Petroleum News
Voices of moderation are penetrating the hubbub surrounding British Columbia’s sizzling natural gas plays in Montney and Horn River, telling investors not to be swept up in the preliminary resource potential numbers.
Speakers at the Insight Information Pacific Gas Forum in Vancouver Sept. 24-25 started downplaying the flurry of reported Horn River discoveries and concentrating on what might be technically recoverable and actually marketable.
“There is a difference, of course, between a resource and what we’re eventually going to produce,” said James Reimer, executive vice-president with Result Energy.
Robin Mann, chief executive officer of Calgary-based AJM Petroleum Consultants, cautioned investors to focus on the marketable reserve potential of the Horn River and Montney plays.
“We have to be careful in the way we (present) the numbers,” he said.
Gerry Goobie, a principal with Purvin & Gertz, said although the Horn River region, in the remote northeast corner of British Columbia, will eventually boost Canadian gas production, it is “going to take a lot longer and probably grow a lot slower than a lot of people anticipate.”
Based on anecdotal information, Reimer said as many as 100 wells could be drilled in the Horn River Basin this winter, which is largely a winter-only access area, although there has been progress in developing roads.
“Huge logistics” for fracturing As well, there are “huge logistics” sourcing the water needed for fracturing, especially in finding ways of storing the water and preventing it from freezing during harsh winters.
Reimer said a breakdown of 100 wells points to a need for 150,000 metric tons of frac sand for the upcoming winter, alone.
Mann, in presenting an independent analysis of the trends and challenges facing British Columbia’s emerging plays, said there is “no denying” that the resource potential is “very large … however, the nature of the resource and its location means only a small percentage of it will be converted into reserves in the short term.
“We have to be careful in the way we put the numbers,” he said. “This isn’t to throw cold water on what we’re saying; it’s just to say that’s the reality.”
Giving some fresh perspective to the string of discoveries reported by Apache, Devon Energy, EOG Resources and EnCana, he urged investors to “focus on the marketable reserve potential of these plays, which, while still impressive, isn’t as large as the estimated resource potential.”
The AJM study estimates the Horn River shale potential at up to 700 trillion cubic feet, with an estimated resource potential drawn from company information at 308 Tcf, translating into a technically recoverable resource potential of 30-140 Tcf.
That, in turn, generates a total marketable resource in the range of 21-110 Tcf, giving a reserve potential per well, based on early test results, of 4-6 billion cubic feet (Bcf).
For the Montney shale, AJM estimates the resource potential ranges from 50-415 Tcf, with the technically recoverable resource potential at 10-80 Tcf and the marketable resource potential at 7-64 Tcf.
The reserve potential for the average well drilled to date is about 4.3 Bcf, a number AJM notes will decrease with continued drilling.
Based on current Montney wells, the consultant said the average deliverability of gas is 1.3 million cubic feet per day for vertical holes and 3.5 Mmcf/d for horizontal wells, while reserves are rated at 1.6 Bcf for vertical wells and 4.3 Bcf for horizontal wells.
Not enough data is available on the Horn River area to provide such a detailed analysis.
AJM also cautioned that development of British Columbia’s natural gas resources will be influenced by a number of factors, including gas prices, determined by North American supply and demand; the terrain for drilling and infrastructure; and what support the capital markets will give companies to invest in a mega-resource play.
Two plays require 32,000 wells The firm believes that realizing the full extent of the two plays will require more than 14,000 Montney wells and 18,000 Horn River wells.
Mann also warned that if the B.C. plays are developed along with expansion of U.S. shale production and new shale development comes on line in Quebec, North America could face a gas glut, with the U.S. mid-continent output heading towards 7 Bcf/d, with another 5 Bcf/d coming from the Barnett shale.
He said production from Horn River will not automatically go east or south to Canadian and U.S. markets, but could be shipped overseas – the major reason why Kitimat LNG scrapped plans for a re-gasification plant on British Columbia’s northern coast, opting instead to build an export terminal.
Mann said the Kitimat reversal might be a “very positive thing for some of the gas in Horn River.
“All this being said, maybe the U.S. won’t reach its peak. Maybe some of these other plays won’t develop as quickly,” he added.
On the technical side, Reimer said there is a “very extensive” gas column beneath the Horn River shale, meaning the risk of fractures encountering water is “substantially reduced.”
He said the economic question facing companies is how much gas they will get after conducting a $1 million frac … “not how much gas do you get out of a well, but how much do you get out of a frac event.”
Reimer said Result – which has exposure to 53,000 gross acres in Horn River and has partnered with privately-held Seven Generations Energy by committing to pay C$5 million to acquire a 10 percent working interest in a 16,000-acre land block – has heard that individual wells may require 10 or more frac events.
“You need to understand what the recovery is per frac stage. If you can’t make that economic, it doesn’t matter how many fracs you do, you’re not making money,” he said.
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