A report released today from the National Energy Board (NEB) and British Columbia Ministry of Energy and Mines puts the marketable shale gas in the basin at 78 trillion cubic feet, including 75 Tcf of undiscovered resources. The new assessment of the shale gas contained in the Horn River basin of north-eastern British Columbia more than doubles the province’s estimated unconventional reserves.
It is the first publicly released probability-based resource assessment of a Canadian shale basin.
The medium case estimate for marketable natural gas is 2198 billion cubic meters (78 Tcf). Once added to the 2006 estimate for conventional ultimate potential, and accounting for cumulative production to year end 2010 of 602 billion cubic meters (21.3 Tcf), the estimate of remaining conventional and unconventional natural gas available for future demands is 3058 billion (109 Tcf). This does not consider other unconventional gas resources which are known to exist in B.C.
The use of the term “marketable” implies a sense of economic recovery. However, for the purposes of this report, “marketable” refers to a technically recoverable volume under foreseeable market conditions. No rigorous economic assessment was performed for this study, though the NEB released an Energy Briefing Note in November 2010 indicating that the average cost of producing Horn River basin shales was $4.68/GJ in 2009, not including pipeline tolls3. The 2010 study used a number of simplifying assumptions and its applicability to specific development is limited. In general, Horn River Basin gas would not appear to be economic at current prices, but could become more attractive if costs continue to decline, which is typical for shale gas as development proceeds.
A grid-based method was used to estimate marketable resources in the Horn River Basin similar to that for GIP. To estimate the amount of marketable free gas, the agencies considered how much of the gas would be successfully recovered through drilling and hydraulic fracturing using current practices. Given the lack of long-term production from the Horn River Basin, free gas recovery factors are highly uncertain. For this project, recovery factors varied for each shale, but most likely values ranged between 15 and 25 per cent. The agencies also considered how much gas would be removed as gas impurities (so that the gas was of pipeline grade) and how much gas would be extracted as fuel gas to transport and process the raw gas. The amount of impurities in Horn River Basin shale gas appears to vary by shale, with some wells as low as eight per cent with others as high as 19 per cent, dominantly consisting of carbon dioxide. The impurities increase with depth
Prior NEB estimate of Conventional Natural gas in Canada
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