Well results quadrupled as Canadians adapted horizontal drilling and hydraulic fracturing to the Montney Shale formation that straddles 130,000 square kilometers (52,000 square miles) of British Columbia (BC) and Alberta, the National Energy Board (NEB) reported.
Average initial production (IP) rates for natural gas per Montney well jumped to 4 MMcf/d last year, up from 0.9 MMcf/d during the first foray into northern unconventional drilling in 2005, NEB records indicate.
The average volume of reserves added to the Canadian gas industry gas reserves by each Montney well likewise multiplied four-fold, to 7.2 Bcf from 1.8 Bcf, said a board review of performance in the shale formation.
Experience with the geological structure and fracture technology improvements are also increasing flows from Montney wells as they age by controlling the natural decline rates of production.
“A well drilled in 2005 typically flowed 0.2 MMcf/d after five years, while a well drilled in 2012 flowed 0.7 MMcf/d,” said the NEB. “Wells drilled after 2012, which do not yet have five years of available production data, could have higher five-year production rates as well.”
Well performance is rated as liable to continue improving on all fronts. The industry is still in early stages of exploiting core sweet spots, rich in liquid byproducts, that occupy an estimated 25,000 square kilometers (10,000 square miles) of the Montney.
“Because of the large size of the Montney’s core area, companies will likely take many years to fully drill areas with the best reservoirs before they start drilling areas with lower reservoir quality,” said the NEB. “Therefore, it is likely that Montney well performance will continue rising as technology continues to evolve.”
High and rising productivity also puts the Montney formation in the top class of North American unconventional deposits as ranked by their economics, said the Calgary branch of Dallas-based international energy consulting house Solomon Associates.
The cradle-to-grave full-cycle cost of Montney wells that flow gas combined with oily byproduct condensate is less than US$2.50/MMBtu, Solomon’s Calgary gas services director, Cameron Gingrich, said at a briefing in the Canadian industry capital.
The negative side of the Montney shale deposit’s natural wealth — currently rated at 449 Tcf in federal and provincial earth sciences appraisals — is a gas price slump. The market is glutted with a regional surplus because of surging production and limited pipeline capacity.
While liquid byproducts prices have risen with oil to support Montney drilling, the value of gas alone has become a drag on activity.
On the AECO shipping, storage and trading hub for Western Canadian output, gas only averaged US$1.32/MMBtu in 1Q2018, down year/year by 35% from $2.02/MMBtu, according to records kept by GLJ Petroleum Consultants in Calgary.
But better times are ahead for producers that can outlast the current lows on the energy cycle, suggested Gingrich.
Gas use by Alberta thermal oilsands plants is expected to grow by about 1 Bcf/d as of the early 2020s if current pipeline projects win their slow struggles to make it into construction over environmental, aboriginal and political resistance.
Prospects remain live for even bigger jumps in outlets for BC and Alberta production by liquefied natural gas (LNG) export projects, said Gingrich. Solomon analysts are optimistic that the mammoth Royal Dutch Shell plc-led LNG Canada project will start the delayed overseas sale ball rolling by achieving a final investment decision before the November expiry of a BC government tax incentives offer.
Shell issued its first quarter results on Thursday, confirming that work continues on controlling costs and finding markets for LNG Canada, amid “challenging” conditions of international competition and soft international prices.
Oilsands and LNG development combined could accelerate the current anemic, 1.6% annual growth rate in demand for western Canadian gas to a stellar 7.6% in the 2020s, Solomon calculated.
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