Natural Gas Drives Canadian Effort

Mackenzie Delta, Beaufort Sea

The Beaufort Mackenzie Basin's current exploration renaissance is being driven by a North American continental energy strategy focusing on natural gas.

American and Canadian E&P firms are banking on the fact that the $C 7.7 billion, Mackenzie Valley pipeline — extending 1,200-kilometers from the Beaufort Sea to northern Alberta — will be onstream by 2009. The pipeline will enable operators to monetize 12 Tcf of stranded gas and 1.5 to two billion barrels of recoverable oil discovered during the late 1970s to mid 1980s.

During the heyday of northern exploration, some 250 wells were drilled in the BMB, resulting in 53 significant discoveries. Included among these significant discoveries are world class fields like Amauligak (1.35 Tcf marketable gas and 235 million barrels of recoverable oil) and Taglu (2 Tcf of marketable gas).

According to the Geological Survey of Canada, an additional 53 Tcf of natural gas and 5.4 billion barrels of oil are waiting to be discovered in the BMB.

Image Caption

Swamp land of Canada's Mackenzie River delta, site of an exploration renaissance.
Graphics, photo courtesy of Devon Canada Corp.

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The Beaufort Mackenzie Basin's current exploration renaissance is being driven by a North American continental energy strategy focusing on natural gas.

American and Canadian E&P firms are banking on the fact that the $C 7.7 billion, Mackenzie Valley pipeline — extending 1,200-kilometers from the Beaufort Sea to northern Alberta — will be onstream by 2009. The pipeline will enable operators to monetize 12 Tcf of stranded gas and 1.5 to two billion barrels of recoverable oil discovered during the late 1970s to mid 1980s.

During the heyday of northern exploration, some 250 wells were drilled in the BMB, resulting in 53 significant discoveries. Included among these significant discoveries are world class fields like Amauligak (1.35 Tcf marketable gas and 235 million barrels of recoverable oil) and Taglu (2 Tcf of marketable gas).

According to the Geological Survey of Canada, an additional 53 Tcf of natural gas and 5.4 billion barrels of oil are waiting to be discovered in the BMB.

Since 1999, the E&P industry has:

  • Acquired more than 20 new exploration licenses from the federal government, totaling more than three million acres. The bidding process for "Crown" lands is a public one — the biggest work commitment dollars (seismic and drilling) secures the license.
  • Acquired 15 3-D seismic surveys, including a marine 3-D in the shallow Beaufort Sea.
  • Acquired several thousand kilometers of 2-D seismic data.
  • Reprocessed its extensive historical in-house grids of 2-D seismic data, using modern processing methods, including pre-stack time and depth migration.

Seeing the Light

During this newest exploration phase, nine wells have been drilled in the Mackenzie Delta (onshore), resulting in a minimum of two publicized natural gas discoveries.

In 2003, the Devon-operated Tuk M-18 well flowed at a restricted rate of 30 MMcf per day from the Cretaceous age Kamik Formation. Devon and its partner, Petro-Canada, publicly stated that the well is capable of an estimated sustained deliverability of up to 80 MMcf per day. Tuk M-18 encountered an estimated 200 to 300 Bcf of natural gas reserves.

Devon describes the well as the first significant onshore drilling success in the Mackenzie Delta since 1975.

Fueled by success, the company is systematically marching northward with its exploration program. Devon plans to drill its first offshore well in the Beaufort Sea during the winter of 2005-06. While the offshore well is still two years distant, timelines in the North are protracted due to logistics and regulatory approvals (including environmental and aboriginal).

Devon exploration geologist Chris Bergquist describes a huge stratigraphic structure that his company has identified with its newly-acquired, 1,800 square kilometer 3-D marine seismic program — the structure boasts impressive AVO anomalies in Tertiary age sediments that ring a shale diapir structure.

This diaper flank play is located updip from a structure that Berquist describes as "a pimple on the side of a huge feature."

The "pimple" was tested by the Minuk I-53 well, which flowed a combined 27.4 MMcf/d from two zones in the Oligocene age Kugmallit Formation and 26 MMcfd/d from a conglomeratic zone in the Eocene age Taglu Formation. Bergquist's previous interpretation of this structure — based on a 2-D seismic grid — was that of a tightly folded anticline.

According to Peter Graham (also with Devon) and Bergquist, historical success rates of Cretaceous plays onshore are about 5 percent. Onshore and offshore , Tertiary age plays have averaged a whopping 50 percent in historical success rates.

Devon's onshore wells in the Mackenzie Delta average about $C 20 to 25 million to drill. The company's proposed offshore well, however, could cost as much as $C 65 million.

"Without a pipeline, it's difficult to justify putting a lot of money into something that's going to sit there for 30 years, as some discoveries have," Bergquist said. "But we believe that we see the light at the end of the tunnel."

Several hurdles must be cleared, however, before Canada's Arctic gas reaches southern markets. These include:

  • Regulatory approvals.
  • Securing shipping commitments from producers.
  • Resolution of a lawsuit filed by the Deh Cho First Nation, an aboriginal group residing in the southern Northwest Territories.
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