The commercial success of natural gas shale plays in the United States has producers large and small eyeing the potential of gas shale that covers the northeastern corner of British Columbia, which may hold 250-1,000 Tcf of gas in place.
British Columbia is in the early stages of evaluating its shale gas, but as the announcements of new discoveries in the region become more frequent, producers appear ready to take on the challenges. EOG Resources Inc. in February unveiled its gas discovery in BC’s Horn River Basin, which may hold 6 Tcf of reserves (see Daily GPI, Feb. 29). Tuesday Apache Corp. CEO G. Steven Farris trumpeted his company’s BC three-well drilling program in the Ootla shale of the basin during the 2007-2008 winter drilling season.
“Although we are still in the early stages of understanding the full scope of this play, these three wells help validate our view that Ootla has the potential to be one of the larger shale gas accumulations in North America,” said Farris.
The three horizontal wells test-flowed at rates of 8.8 MMcf/d, 6.1 MMcf/d and 5.3 MMcf/d, Farris told participants at the Howard Weil Energy Conference in New Orleans. Apache has 323 sections in the play, and average gas in place per section is 180-320 Bcf, said the CEO. Total gas in place is estimated at 58-103 Tcf. At a 20% recovery rate, Apache estimates it has 9-16 Tcf of reserves in place. At a 30% recovery rate, the reserves could total 13-23 Tcf, said Farris.
“Infrastructure is in place, and 18 MMcf/d is flowing to Apache’s Missile gas plant” in British Columbia, said Farris. The Missile plant has 23 MMcf/d of capacity, which is expandable to 45 MMcf/d. The Fort Nelson gas plant, located 90 miles away, could provide 450 MMcf/d of spare capacity, he added.
Apache was one of the first movers in the Ootla play, building its initial position in 2000. Its first producing well from the Muskwa shale was completed in the 2005 winter season, and in November 2006 subsidiary Apache Canada Ltd. was approved to begin testing the commercial viability of the Horn River Basin’s shale gas. Over the winter Apache performed 18 fracture stimulations in the three horizontal wells, pumping a total of 7.8 million pounds of sand and 280,000 barrels of water into the formation.
EnCana Corp., which has been the busiest operator in the Horn River Basin since 2001, and Apache formed an area of mutual interest, and together they control more than 400,000 acres at the center of the play; Apache’s net stake is 207,000 acres (see Daily GPI, Feb. 8). In total the two producers have drilled about half of all the wells to date in the play, Farris noted. EnCana also has drilled, but not yet completed, two horizontal wells in the Ootla area, he added.
About 300 wells have been drilled into the Horn River Basin since the 1950s, but that number is expected to quickly grow as unconventional gas drilling increases, said the BC Oil and Gas Commission (OGC) in a recent report. Most of the province’s lease parcels last year were sold to land brokers — acting for producers that may not have wanted the publicity. At the province’s December 2007 sale, land broker Meridian Land Services (90) Ltd. paid a bonus of C$30.7 million for a 5,572-hectare license, representing an average price per hectare of C$5,502. It was the highest bonus paid for a parcel in the Horn River Basin at any of the 12 provincial land auctions in 2007, the commission noted.
Besides EnCana and Apache, unconventional gas pioneers Devon Energy Corp. and EOG Resources Inc., as well as Calgary-based Nexen Inc., and Quicksilver Resources Inc. are testing the commercial viability of the basin’s shale gas (see Daily GPI, April 8). Other producers are extending their tests across a wider swath, drilling into sections of the Liard Plateau and Basin, western extensions of the Peace River Arch, as well as the Triassic Doig and Montney formations.
The Cordova Embayment, which is geologically similar to the Horn River Basin, covers an area of about 379,000 hectares in BC’s Fort Nelson/Northern Plains region. More than 325 wells have been drilled in the basin in the past 50 years, but only a handful have targeted shale gas, according to the OGC. Cumulative gas production so far is about 500 Bcf.
The Upper Montney Play in the Fort St. John/Deep Basin region and Cutbank Ridge also is attracting explorers. Land sale bonuses within this play increased 500% in just the past three years, with annual bonus totals jumping to C$526 million in 2007 from C$85 million in 2005.
ARC Energy Trust was the primary operator in the Upper Montney last year, but drilling records indicate that EnCana and ConocoPhillips Canada Ltd. also are key operators. Newcomers include Murphy Oil Corp., the OGC noted.
BC’s shale gas land sales are expected to be high again this year. To encourage exploration, the province has initiated a net profit royalty program to develop technically complex, high-risk projects. The program will focus on unconventional reservoirs, such as coalbed gas, shale gas, tight gas, enhanced gas recovery and gas hydrates.
The province’s next lease sale is scheduled for April 23, when it will offer 41 parcels covering 26,939 hectares. To learn more about BC’s shale gas activity and the royalty program, visit www.ogc.gov.bc.ca.
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