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Nova plan backed by 6.8 tcf marketable gas
The potential for British Columbia’s Montney shale formation has been further strengthened in a regulatory application by Nova Gas Transmission, which told Canada’s National Energy Board it is supported by 6.8 trillion cubic feet of marketable gas.
In submitting plans for its proposed C$251 million Groundbirch system, Nova (wholly owned by TransCanada) said the 36-inch pipeline can also draw another 700 billion cubic feet from other sources.
It said Groundbirch will be designed to carry about 1.66 billion cubic feet per day, with five potential customers having committed to transportation agreements for an initial 115 million cubic feet per day in 2010, increasing to 1.13 bcf per day by 2014.
Nova estimated the drainage area contains 28.5 tcf of original Montney gas in place, yielding 6.8 tcf of marketable gas based on a 25 percent recovery factor and 4 percent shrinkage.
It said the forecast is based on discussions with area producers who participated in its binding open season and data from public sources.
40 tcf marketable estimate The British Columbia government’s Ministry of Energy, Mines and Petroleum Resources estimates the entire Montney formation has 318 tcf of original gas in place and marketable volumes of up to 40 tcf.
Nova’s application said the formation varies in quality from conventional gas straddling the Alberta-British Columbia border to unconventional gas farther west.
The company said current industry activity has been concentrated on unconventional tight and shale gas resources, which has generated the demand for additional pipeline capacity out of the region.
“The magnitude of these resources supports the conclusion that (Groundbirch) will provide needed transportation capacity for many years,” the regulatory filing said.
The pipeline is planned to cover about 49 miles across the border into Alberta, where it would feed into TransCanada’s pipeline network.
Nova’s 15-year forecast of productive capacity covers both Montney and other conventional resource volumes and estimates capacity will climb to 1.44 bcf per day by 2024 from 255 million cubic feet per day in 2010.
The application said producers expect an average 12 wells per section will be drilled, ranging from eight to 15 wells, but Nova is basing its forecast on an average drilling density of 7.5 wells per section.
Imperial not so bullish
Nova’s bullish predictions are tempered by Imperial Oil, which shares almost 200,000 acres with ExxonMobil in British Columbia’s Horn River shale play.
Imperial Senior Vice President Randy Broiles said the partnership might eventually have a pilot project that can produce 20 million to 30 million cubic feet per day within a couple of years.
“The production pilot … is critically important to understand what we’re going to be able to achieve from a cost standpoint,” he said. “The early engineering has been under way for several months.
“We’ve got some tough technical nuts that we’re trying to crack that relate to the tightness of the shale and how do we go through massive fracs in a very cost-effective way to ensure that gas is profitable,” Broiles said.
He said that although results from a winter drilling program were “encouraging” there are “many unknowns” in the play.
ExxonMobil Chief Executive Officer Rex Tillerson offered another insight into the company’s thinking on shale gas May 27, telling reporters the “technology has come a long way. … In terms of shale gas, there is a pretty bright future.”
He said the company is now facing a decision on “whether large-scale development” of its worldwide shale positions “will be attractive.”
Alberta has shale potential Whatever the outlook, the windfall success to the British Columbia government of its shale deposits has grabbed Alberta’s attention, with the government-owned Alberta Research Council making a case to advance commercial production in the province.
A council engineer, Kirby Nicholson, said estimates of Alberta’s shale resources are about 300 tcf, prompting the ARC to propose a joint industry project, involving ARC funding along with federal and Alberta tax and royalty credits, with the goal of achieving high initial production revenue.
Mike Dawson, president of the Canadian Society for Unconventional Gas, told a conference that as technology moves ahead in the United States and British Columbia, Alberta’s significant shale potential will become more economically attractive.
“It truly is a technology play,” he said. “We’ve gone through a major paradigm shift in how we look at reservoirs. Traditionally, we didn’t consider the rocks from which we’re now producing gas as reservoirs because the porosity or permeability of these reservoirs was so low we couldn’t get the natural gas out of the ground.
“With the application of horizontal drilling and multistage fracture stimulations … we’re actually able to access these very tight reservoirs.”
—Gary Park
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