Plans for a jumbo, expandable processing plant confirm that Canadian producers are gearing up for sustained development of shale gas in northern British Columbia on a large scale.
The program for the Cabin Gas Plant, for production from the Horn River Basin near BC's boundary with the Northwest Territories, calls for building up capacity of 2.4 Bcf/d in six equal stages. The operation will make pipeline-grade gas by stripping out byproducts and disposing of impurities including traces of hazardous hydrogen-sulphide and anticipated high volumes of carbon-dioxide.
EnCana Corp., Canada's top gas producer, started the regulatory approval process by filing a project description with the BC Environmental Assessment Office on behalf of the eight-member Horn River Basin Shale Gas Producers Group. The consortium includes Apache Canada, Devon Canada, EOG Resources Canada, Nexen Inc., Quicksilver, Stone Mountain Resources and a partnership of Imperial Oil with its majority owner ExxonMobil.
The project schedule calls for completion of the first, 400 MMcf/d Cabin stage in late 2011 for about C$400 million (US$335 million). The construction target is the time when EnCana, as the largest owner of Horn River drilling rights, expects new shale gas production to overtake about 400 MMcf of excess capacity currently available in BC processing plants. The Cabin program also marches in step with plans by TransCanada Corp. to build extensions of its Nova Alberta pipeline grid and trading hub into northern BC.
"Each subsequent phase is expected to be installed as production from the Horn River natural gas basin comes on-line and demand for processing increases," EnCana told the BC environmental authorities.
Members of the Horn River consortium were driving forces behind an annual record C$2.7 billion (US$2.3 billion) in sales of BC government-owned gas rights during 2008. The shale gas formation is a Devonian-era reef about 180 meters (590 feet) thick, underlying 6,200 square kilometers (2,400 square miles) of northern bush and muskeg swamps at a depth of 2,700 meters (8,830 feet), EnCana said.
In its disclosures to BC's environment watchdog, the Horn River consortium calculated its namesake geological structure's endowment of gas in place at an astronomical 600 Tcf. With current technology, the group estimated 10-30% of the natural deposit can be economically produced.
Initial wells, employing horizontal bores and multiple fracs are yielding an average 4.9 MMcf/d or more in months-long extended production tests, BC authorities were told.
The technique is a Canadian adaptation of methods devised in Texas for the prolific Barnett Shale formation near Dallas-Fort Worth, where four of the Horn River group members -- EnCana, EOG, Devon and Quicksilver -- are among the top 10 well operators. The northern BC version of shale gas development costs about C$10 million (US$8.4 million) per well, EnCana has disclosed. But longer experience in BC's similar Montney tight gas formation has shown costs can cut by about 70% as the new technology is mastered, EnCana has reported in investor presentations.
Even at the forecast minimum of 60 Tcf, projected Horn River production exceeds Alberta's 39 Tcf of government-estimated remaining conventional gas reserves by 54%. The Alberta Geological Survey, an arm of the province's Energy Resources Conservation Board, is putting finishing touches on a guide book to Alberta shale gas resources. But the province that has been the mainstay of Canadian supplies so far has no counterpart to cut-rate royalties enacted by BC to stimulate unconventional gas development. The scheme closely resembles an incentive regime invented by Alberta to lure industry to its northern oil sands.
As BC environmental authorities review the Cabin gas plant project, the BC energy ministry this week issued its first call for formal applications to obtain benefits of its net profit royalty regulation. Only requests involving Horn River development will be considered, the invitation said.
The scheme sets royalties at a nominal rate of 2% of production revenues until project costs are recovered over periods of up to 10 years. Then the rates rise in tiers to 15%, 20% and ultimately 35% as revenues attain specified multiples of development costs. But the rates apply only to net revenues after production expenses, rather than to gross gas sales proceeds which are the customary targets of Canadian provincial royalties.
Crucial details, including what costs to let companies claim against the royalties, are open to negotiation under the BC scheme, which was devised in consultation with the industry. The co-operation continues, with the BC energy ministry sending representatives to Alberta for a technical information meeting with industry on the royalty policy Jan. 21 in the Canadian gas capital of Calgary.
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