The Canadian natural gas community shows signs of curing itsexcess-capacity headache the easy way — by finding enoughsupplies with a few major wells to fill up the expanded pipelinegrid.
Another demonstration is under way to show that Canada’s nearnorth can deliver supplies on a large scale when prices reachlevels that justify exploration on the deeper, costlier side of thedrilling spectrum. Alberta Energy Co. stepped forward with thesecond major drilling success in northeastern British Columbia inless than a year. AEC predicted its discovery well alone – a9,300-foot-deep one in the Ladyfern area 60 miles northeast of FortSt. John – will produce 60 MMcf/d. A second successful well intothe formation, described as a Slave Point dolomitic reef, was beingprepared for production testing.
AEC Oil and Gas President Randy Eresman described the region as”home to world-class wells and high-impact reserve additions. Thisfind looks a lot like the nearby Hamburg-Slave Point A gas pool,which has produced 330 Bcf since its discovery in 1983.”
While the B.C. exploration play is more expensive than shallowdrilling in southern Alberta and Saskatchewan, the costs remain afraction of multibillion-dollar price tags on megaprojects forAlaska and the Northwest Territories which engineering firms arecurrently being recruited to design in the United States andCanada. Near-north production is also achieved in a matter ofweeks, or months at most, because the B.C. finds are withincomparatively easy reach.
In the Ladyfern region for C$60 million (US$41 million) thiswinter, AEC expects to drill nine wells, lay six miles of gatheringpipeline, build a treatment facility and install an additional12-kilometer line to send sales-ready gas into the TransCanada-Novatransportation grid.
Production and reserves estimates will be released aftercompletion of the drilling program. But in hearings before theNational Energy Board on a pipeline for the first Ladyferndiscovery, Murphy Oil Co. President Harvey Doerr said it representsmore than 200 Bcf of new reserves. With numerous additional wellsremaining to be drilled by Murphy and partner Apache Canada Ltd.,estimated productive capacity already exceeds 130 MMcf/d. The NEBapproved the Murphy pipeline, with the construction schedulecalling for completion by March 15.
Testimony before the NEB also indicated that AEC will achieveits quick production schedule by taking over a pipeline that theNEB approved for other participants in the Ladyfern play, RicksNova Scotia Co. and Predator Corp. The line came available afterRicks sold its interests to Murphy, cutting minority interest ownerPredator out of the action and leaving it to demand compensationwith a lawsuit in Alberta Court of Queen’s Bench.
Evidence before the NEB indicated that Murphy and AEC combinedare installing enough new pipeline capacity to achieve productionincreases of 350-400 MMcf/d from the Ladyfern area. Cooperation maybe in the works. Doerr told the NEB “we have had some discussionswith AEC about jointly hooking up those pipelines. And we have hadsome discussions with AEC with respect to combining facilities.”
The Ladyfern play is only the most spectacular Canadian winterdrilling campaign to disclose results so far. Industry associationsand financial analysts are projecting a record 17,000-19,400 wellsin western Canada this year. So far in 2001, about 63% ofsuccessful completions have been for gas production, althoughCanadian oil activity hs also accelerated as a result of strongprices.
When the NEB approved Alliance Pipeline, gas regulators andproducers alike predicted there would be excess capacity in theCanadian grid of up to 2 Bcf/d. But all concerned kept theiroptions open by saying the excess could take as long as five yearsor as little as 24 months for supplies to catch up depending ondrilling results. The Ladyfern discoveries alone show signs ofgoing one-third or more of the way towards making up for the 1.3Bcf/d that Alliance added to western Canada’s long-distancecapacity.
Gordon Jaremko, Calgary
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