Oil Magazine.
Dec 2008
A float on fir rafts and light royalties, a production line forms across a northern B.C. muskeg seaMike Graham, EnCana Corp.’schief for the Canadian foothills of the Rocky Mountains, has noillusions.
The breakthrough he’s mandated to lead in northeasternBritish Columbia takes labor and cash – big time.“You walk offthose mats and you’ll be up to your waist in muck,” he says. Hiswarning describes a hazard of tapping natural gas beneath muskeg swampsin the Horn River Basin near B.C.’s boundary with the NorthwestTerritories.
The insects are beyond description.Portable firdecks are built by the tens of thousands at Prince George timber millsfor truck deliveries north, to lay down end-to-end and side-by-side ina growing network of floating roads and work platforms for B.C.drilling rigs.“It’s by no means cheap,” Graham adds. Each well into the new geological jackpot, where EnCana leads the industry pack with nearly 900 square kilometers of Horn River mineral rights, can cost $10 million.
The target only yields its riches to horizontal bores drilled up to 1.5kilometers across formations buried as deep as three kilometers belowthe swamps. Every well requires up to 10 “fracs” or rock-fracturinginjections of sandy fluid, with each shot using about 4.5 millionlitres of salt water obtained by drilling nearly a kilometer down intoanother geological layer. Multiple wells radiate outwards from eachfloating rig location.
This is the gritty and expensive Canadian version of the hottest drilling play in the United States: shale gas. EnCanaranks among the top participants in the new specialty’s cornerstoneBarnett Shale, a 13,000-square-kilometre Texas field in the Dallas-FortWorth region that produces about three billion cubic feet per day or asmuch as all of B.C. The Barnett total has the potential to triple,Graham says.EnCana also has 1,320 square kilometers of mineral rights in an emerging U.S. field – the Haynesville Shale on safe, dry land in northern Louisiana – that Graham describes as potentially twice as productive as the Barnett.
Therewere easier places to start transplanting the Texas technology toCanada. Earth scientists are poring over geological maps of shaleformations and starting to drill in Alberta, Nova Scotia, New Brunswickand Quebec.Talisman Energy and Questerre Energy are poised to launch a commercial pilot project in the St. Lawrence Lowlands west of Quebec City. Stealth Ventures Ltd. describes its pioneer Albertashale gas program as advancing from “a conceptual technology play to acommercial producing asset” with a 70-well drilling program atWildmere, southeast of Edmonton.
Triangle Petroleum Corp. and Corridor Resources Inc. are probing geological formations beneath New Brunswick, Nova Scotia and Prince Edward Island.B.C. lured large-scale development by industry who’s who – from Apache Canada to Nexen Inc. – with a gas counterpart to Alberta’s pro-development oil sands royalties. Mineral rights sales in the Horn River region and similar Montney area topped $2 billion in the first nine months of 2008 or more than double B.C.’s previous annual record.Thenew B.C. regime, enacted with Alberta industry guidance and no publicfanfare last spring as the “net profit royalty regulation,” chargesonly two per cent of gross production revenues.
The rate stays at thatnominal level until all gas-field drilling and development costs arepaid over up to 10 years.After “payout” or full cost recovery,three higher “tiers” set B.C. gas royalty rates at the greater ofseveral potential levels: five per cent of gross revenues or 15, 20 or35 per cent of net revenues after operating expenses.
The rules ensureincreases will be gradual. The rising tiers only kick in as revenuesreach levels double and then triple project costs. The policy continuesto evolve and potentially widen beyond shale gas, with B.C. authoritiesinviting further industry submissions on types of operations thatshould qualify for the incentive scheme.As in Alberta’s oilsands, the key to commercial success in B.C. shale gas is economies ofscale. Developments work when high initial costs are spread thin overthe greatest possible production. In industry language coined by EnCanathese are “resource plays,” where jumbo projects harvest large mineralrights spreads by doing multiple standardized, repetitive drilling andproduction installations over long periods of time. “We talk about amanufacturing approach,” Graham says. “We talk about a natural gasfactory.”EnCana alone expects to produce one billion cubic feet of Horn River gasper day eventually, single-handedly increasing B.C.’s current totaloutput by 33 per cent. The company plans to operate up to 10 drillingrigs around the clock, 365 days a year in the remote region.
“Everytime we drill a well, we get more proficient. We get better at it,”Graham says.At a technical level, the new specialty deserves tobe called revolutionary. The approach replaces eons of fossil fuelevolution. Shale is a geological “source rock,” where organic materialfrom ancient sea beds and swamps biodegrades into methane or oil, thenslowly leaks out and migrates to underground “trap” formations.
These much rarer natural storage sites have been the industry’s drillingtargets for its entire history to date, with their scarcity, size andstructure setting limits on reserves and production.Theresource potential of source rocks is measured in hundreds or eventhousands of trillions of cubic feet, in a gas version of theastronomical ratings for the oil sands. B.C. alone has enoughpotentially gas-charged shale to harbor up to 1,000 trillion cubicfeet, the province’s energy ministry calculates – a fossil fuel motherlode that is the energy equivalent to 166 billion barrels of oil. Theswampy Horn River Basin sprawls across 12,800 square kilometers ofnortheastern B.C.Shale gas also has the potential torevolutionize the energy outlook for all of North America, Graham says.Conventional forecasts, saying U.S. and Canadian gas supplies havepeaked and begun to turn down, are starting to look obsolete.“We’re still just scratching the surface.
The big supply is yet to come.”Instead of building a long lineup of import terminals currently proposed for tanker cargoes of liquefied natural gas from overseas, the industry may need LNG export ports, the EnCana executive suggests.
The first project catering to a possible about-face in gas suppliessurfaced as summer ended. Calgary-based Kitimat LNG Inc. converted its$750-million proposal for a north Pacific import terminal on the B.C.coast at Kitimat into an export scheme about four times bigger.Alberta Oil Magazine.Dec 2008
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