Apache Canada takes the lead in shale gas production

May 2008

Not much resulted from Apache’s initial foray into northeast British Columbia’s Ootla area to test Keg River carbonates in 2001. Today, the area has been identified as potentially one of the largest shale gas plays in North America.

DURING THE 2001 WINTER DRILLING SEASON, Apache’s Canadian Region began to drill a series of wells into the Keg River Hydrothermal Dolomite in the Ootla area of the Horn River Basin in northeast British Columbia. Although not remote by Canadian standards, the majority of the basin is currently accessible only in the winter because the muskeg thaws into a swampy, spongy mess that can swallow heavy equipment during the summer.

By the end of the 2004 winter season, it was clear that the Keg River play was not panning out as expected. That July, Steve Farris, Apache’s president and chief executive officer, sent Kent Newsham, petrophysics manager, to Calgary to work with Ross Pitman, team lead for New Ventures, on the Keg River Dolomite to figure out what was wrong with the play, and if irresolvable, to “find something else.”

Over the next couple of weeks, Newsham and Pitman concluded that the Keg River Formation had intractable problems. So, just as Farris had encouraged the team to do, they found something else – something much better.

Pitman and Newsham noticed the gas cross-over effect on the density and neutron logs, a sign of hydrocarbons, across the Klua and Muskwa Shale intervals, above the Keg River Dolomite. During the summer of 2004, Newsham noticed that the Ootla shales calculated gas pay, and the team started to define the regional extent of the gas distribution across the Horn River Basin.

As Apache began to look at Ootla, the company was thrilled with the prospect of a new discovery. What no one realized when Newsham and Pitman started evaluating the Keg River play, however, was that Apache was in the middle of what may become one of the largest shale gas reservoirs in North America.

Shale gas was not an initial target in the basin because gas-charged shale historically had been thought of as a source-and-seal rock, not as a commercially viable reservoir. Only recently have favorable gas prices and advances in hydraulic fracture stimulation as well as other technologies made unconventional resources such as gas shale economically viable.

Apache had no history in shale gas, even as the industry and Wall Street rewarded companies with large holdings in the Barnett Shale in North Texas. “We’re not big believers in following other people’s plays,” Farris told investors recently.

At Ootla, with holdings totaling 90,000 acres, Apache decided to see if the play was actually realistic.

By mid-February 2005, Pitman had defined the regional extent of the Ootla gas shale play. Ultimately, it was concluded that the shale covered an expansive area of approximately 3,600-square miles. Around the same time, it was recognized that Ootla might be geologically comparable to some U.S. formations, particularly the Barnett Shale in the Dallas/Ft. Worth area. This led Apache to bring Ken Pfau, research play specialist, who helped put peer company EOG Resources into the Barnett, on board in late February. The Barnett analog also provided a starting point for the team to correlate the gas effect on the well logs with the amount of gas potentially in the system.

As early as November 2004, the Klua and Muskwa Shales were considered as possible exploratory targets for the recompletion of an existing well in the Keg River formation. In February 2005, after realizing that the play might have serious potential, Apache selected the vertical well A-12-H for recompletion to test the Klua Shale for the presence and recoverability of gas. To test for gas, Apache started conservatively with a 28,000-pound hydraulic fracture stimulation, or “frac.”

Hydraulic fracture stimulation is a process where sand and water are pumped at high pressure into a well in order to crack open reservoir rock to increase production. Fracing is imperative in shale plays like Ootla because shale has very low permeability.

On April 3, the first gas flow confirmed natural gas in the system, and on April 5 a flow-back test show-ed the production of the well to be 95 thousand cubic feet (Mcf) per day.

Once the potential was identified, the game got serious. Mike Bahorich, executive vice president of Exploration and Production Technology, assembled a team of shale gas experts that included Chuck Smith, reservoir engineering manager, and fracture-treatment expert Tom Hellman, manager of completion and production optimization, who came in to run the next series of horizontal, multi-frac wells.

Rob Spitzer, vice president of Exploration in Canada, put together a land deal with EnCana in the summer of 2006 that buoyed the project’s momentum by helping to create an area of mutual interest to jointly develop the two companies’ acreage in the basin. The same June, Newsham and Barbara Johnson, technical coordinator, completed the first maps of the entire Horn River Basin showing over 350 trillion cubic feet (Tcf) of gas resource availability. It was beginning to appear the Horn River Basin might be an enormous unconventional resource play.

Britt Dearman, special projects manager, was brought on in the fall of 2006 to assess the project. Continuous communication between staff in Calgary and Houston led to recommendations for Apache to accelerate acquisition of acreage and drill tests to get the best land position and find the optimal size for fracture treatments. Farris continued to provide corporate support and money to amass a large land position. According to Pfau, “He was our biggest cheerleader.”

Now, four years after discovering the play, Apache has announced that three wells drilled this year at Ootla have test-flowed at rates of 8.8 million cubic feet (MMcf), 6.1 MMcf, and 5.3 MMcf of gas per day. Even with results like these, “going forward, the cool thing is we haven’t optimized this system,” says Smith. Apache estimates the recoverable gas resource potential at Ootla is between 9 Tcf and 16 Tcf.

Apache already has some infrastructure in the area from the Keg River play, but surface and subsurface facilities will need to be expanded. There is already a major Spectra Energy pipeline that connects to an Apache-owned, gas-processing plant and pipeline in the area.

Apache recognized the potential of Ootla about the same time as other companies like EOG and EnCana recognized the potential for shale gas nearby. But, unlike the other companies, Apache went beyond testing to put wells into production. Indeed, until last year, Apache was the only company with shale gas production in northeastern British Columbia.

Ootla is representative of the innovation that takes place at Apache. Unlike other companies such as EnCana, which have teams looking for gas shale plays, Apache had no history with gas shale prior to Ootla. This organic growth is an exciting development for Apache because the company is breaking new ground by leading the way in gas shale production in northeastern British Columbia. As Ross Pitman puts it, “It’s not everyday you get a chance to build a play from scratch that not only has regional impact but also has corporate impact.”

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