Alberta has long been the alpha dog of Canada's natural gas exploration, but British Columbia is quickly proving it can run with the pack. Nexen Inc. last week became the latest of several pedigreed gas producers to track down success in the emerging shale prospects in the Horn River Basin.
Calgary-based Nexen completed a winter shale drilling program on a basin leasehold at Dilly Creek, and based on an assessment of three vertical wells -- and assuming a 20% recovery factor -- the Dilly Creek lands are estimated to contain 3-6 Tcf of recoverable contingent resources. Before the estimates are finalized and commercially established, Nexen plans to conduct additional appraisals.
"There has been a lot of excitement over this play," said Nexen CEO Charlie Fischer. "We are well positioned with significant acreage that is surrounded by wells drilled by other major players in the area who have experienced strong production test results. Based on our winter program results, we believe our reservoir is comparable to those offsetting our lands."
Nexen, which has accumulated about 123,000 net acres in the basin over the past 18 months, has a leasehold that runs parallel to a joint venture between EnCana Corp. and Apache Corp. EOG Resources Inc. has a sizeable leasehold nearby. In addition, Devon Energy Corp. and Quicksilver Resources hold acreage in the basin.
David Slater, a marketing director for Nexen Marketing, will be presenting a wrap-up of resource and infrastructure development in Canada at GasMart 2008 coming up May 20-22 in Chicago. (See www.gasmart.com for more information).
Nexen's Horn River Basin news also runs parallel to the recently announced success by its neighbors.
EOG in February unveiled its gas discovery in the basin, estimating that its acreage could hold 6 Tcf of reserves (see NGI, March 3). EnCana, which has been the busiest operator in the basin since 2001, formed an area of mutual interest with Apache and in total they control more than 400,000 acres in the play (see NGI, Feb. 11). Together the two producers have drilled about half of all the wells to date in the play. Apache earlier this month trumpeted its success in the basin and said three horizontal wells drilled in the Ootla Shale of the basin over the winter test-flowed at rates of 8.8 MMcf/d, 6.1 MMcf/d and 5.3 MMcf/d (see NGI, April 14).
Nexen controls 100% of its acreage, and it said the basin "has the potential to become one of the most significant shale gas plays in North America." The play "has been compared to the Barnett Shale in Texas by other operators in the area as it displays similar rock properties and play characteristics. The average gross shale thickness on our Dilly Creek lands is approximately 175 meters, which is almost 50% thicker than the Barnett."
During the 2006-2007 winter drilling season Nexen drilled two vertical wells at Dilly Creek and then analyzed the data last summer. Nexen drilled another vertical well and two horizontal wells this past winter.
"We fraced approximately 300 meters of the horizontal well, and the well tested over 2 MMcf/d from its two frac segments," said Fischer. "These test rates are consistent with rates reported by competitor wells in the area, which average approximately 1 MMcf/d per frac segment. We expect typical future development wells on our acreage to consist of six to 12 frac segments over longer horizontal lengths."
One horizontal well and one vertical well are now producing at rates of about 2.5 MMcf/d, Nexen stated.
To further assess the potential of the play, Nexen wants to conduct a summer drilling program to test two horizontal wells. An all-season road has been constructed, which would provide access to the well locations and half of Nexen's leasehold year-round.
Is there a downside?
Motley Fool's Toby Shute said earlier this month that there were a "few reasons why I think energy investors shouldn't fall totally head over heels for the Horn River play. For one, this shale is deep, making drilling more expensive. Second, year-round drilling in northern Canada is precluded by weather conditions, so the pace of development can never be as furious as that seen in the Barnett. These are just two reasons to help explain why EOG is only modeling a 20% after-tax rate of return in the play. That'll pay the bills, but this isn't the Holy Grail of natural gas."
However, the Horn River Basin is not the only area in the province that has attracted a bevy of top gas producers. The Montney tight gas sands formation, bordering Alberta, is estimated to hold between 50 Tcf and 700 Tcf (see NGI, March 31). BP plc, EnCana and ARC Energy Trust are exploring parts of this play (see NGI, Jan. 28).
The province's lands could contain even more bounty, officials said. With producers touting gas finds not previously known, British Columbia officials this week announced plans to invest C$5.7 million to "enhance the development of exploration and development" of oil and gas resources.
"By getting comprehensive resource data to the industry, we are stimulating oil and gas exploration, investment and production," said Minister of Energy, Mines and Petroleum Resources Richard Neufeld. "British Columbia is one of the most attractive oil and gas jurisdictions in North America. This means more jobs, more revenue and more benefits for everyone in the province."
The Ministry of Advanced Education, through the Ministry of Energy, will fund several projects "with a particular focus on shale gas in the Horn River Basin in northeast BC." British Columbia reached a record high of more than C$1.2 billion for the 2007-2008 oil and gas rights sales.
"The exceptional sales reflect industry's strong interest in the Horn River Basin, the largest shale gas play in Canada," Neufeld said.
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