Growth will be built into the Canadian Arctic natural gas project, with the sponsors expecting it to lay the foundations for a new branch of the industry spanning the 800-mile length of the proposed Mackenzie Valley pipeline.

In the “preliminary information package” or PIP that started the regulatory process rolling this month after completion of a joint-venture agreement, the Mackenzie gas consortium reported encouraging results from an early canvass of Canadian producers for additional support.

An “open-season” offering of rights to book space on the proposed Mackenzie Valley pipeline generated expressions of interest from 20 companies, the project sponsors reported. The lineup is understood to range from United States-based producers with extensive Canadian interests like Devon Energy and Chevron Canada Resources to home-grown, expansion-minded explorers such as Petro-Canada.

The first test of demand for gas transportation service supported planning for an initial capacity of 1.2 Bcf/d at the time when deliveries are scheduled to start in fourth-quarter 2008. The total so far stands at 50% more than the “anchor” traffic of 800 MMcf/d committed by producers in the project sponsor group from their own Mackenzie Delta gas fields: senior partner Imperial Oil Resources Ventures Ltd. with a 34.4% interest, ConocoPhillips Canada 15.7%, Shell Canada Ltd. 11.4% and ExxonMobil Canada Properties 5.2%.

The open season results suggest the Aboriginal Pipeline Group will be able to drum up gas to fill its intended 33.3% share in the line from the Mackenzie Delta to a connection with the northern end of TransCanada PipeLine Ltd.’s Nova grid in Alberta. The information package also says the industry canvass justifies laying the pipe with built-in capacity for large increases in traffic over time.

The consortium’s engineers will work on a blueprint for a system capable of increasing deliveries to 1.9 Bcf/d by making low-cost additions of compressor power, say the documents. Backup designs will also be developed for a lower capacity system in case gas supplies turn out to be smaller than anticipated by companies still in early stages of exploring for reserves.

But the planning will also contemplate a potentially larger pipeline. The Mackenzie consortium says it will “maintain flexibility in line-pipe sizing and expansion capability as long as practical in the project schedule, thereby providing increased opportunity to accommodate additional volumes from the development of existing and new field discoveries.”

The open-season canvass encountered signs that a northern pipeline will have a ripple effect across the Northwest Territories. Making delivery service available is expected to accelerate gas exploration beyond the Inuvik region on the Mackenzie Delta, where the producer-sponsors have been sitting on the discoveries that will provide the anchor traffic since the 1970s.

The PIP says that in the capacity offering, “the responses identified the potential need for receipt points (links with other potential gas fields) in addition to Inuvik.” It will take time, further drilling and negotiations with prospective shippers to nail down exactly how much capacity has to be built and where the connections need to be. The open season responses “also identified a range in potential future capacity needs, reflecting uncertainties associated with forecasting the result of future exploration in the Mackenzie Delta and Mackenzie Valley regions.”

The consortium also expects the pipeline to sire new markets along its route. The design will include “valve access points on the transmission pipeline system to enable regional communities to purchase natural gas,” the documents say.

A decision remains to be made on whether to build a separate line for liquid byproducts or build a single “two-phase” line capable of carrying them as well as the natural gas. Liquids production from the anchor fields on the Delta is expected to be 12,000-15,600 barrels per day. The current version of the plan calls for capacity for up to 20,000 barrels eventually.

The production proposals combine economic and environmental efficiency. The plan calls for multiple production wells to be drilled from single work sites, minimizing equipment, movement and damage to the tundra. The consortium has had decades to work on production programs for the three Delta discoveries to be tapped initially: Taglu, Parsons Lake and Niglintgak. Imperial found Taglu in 1971 at a site 75 miles northwest of Inuvik. The Parsons Lake discovery dates back to a 1972 drilling success about 30 miles northeast of Inuvik by the former Gulf Canada, now part of ConocoPhillips. Shell drilled the Niglintgak find in 1973, near Taglu.

The anchor fields harbor reserves estimated at 5.8 Tcf. Counting offshore discoveries in shallow waters of the Beaufort Sea, the Mackenzie producer group has about 12 Tcf, according to evidence submitted to the NEB in other cases. Potential reserves in the still lightly explored Delta-Beaufort region are projected at 57-73 Tcf. Although the targets of current exploration programs are chiefly onshore locations, Devon has a proposal pending before the NEB for a revival of shallow-water offshore drilling.

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