Nick Snow
Washington Correspondent
WASHINGTON, DC, Sept. 14 -- Shale gas plays in four US Midcontinent basins provided most of the impetus as estimated US natural gas resources grew dramatically from the end of 2004 to the end of 2006, the Potential Gas Committee said in its latest biennial report.
Total domestic gas resources, including proved reserves, were an estimated 1,525 tcf as of Dec. 31, 2006, about 16.6% more than the 1,308 tcf PGC estimated 2 years earlier. It was the largest volumetric and percentage growth in the group's biennial estimate since 1968.
"The industry is looking at gas shales nationwide. It's the hottest kind of new play," observed John B. Curtis, director of the Colorado School of Mines' Potential Gas Agency, which assists PGC's efforts. Although US shale-gas production dates back to the 19th century, "it's coming of age today as a result of higher prices, improved technology, and greater understanding of the formations and what's required to tap them," Curtis told reporters during a briefing at the American Gas Association, one of PGC's sponsors.
Excluding proved reserves, as estimated by the US Department of Energy (204.4 tcf in 2006 and 189 tcf in 2004), yearend potential US gas resources climbed 18% to 1,321 tcf from 1,119 tcf over 2 years, PGC said. Traditional resources, which include carbonates and tight sands, climbed 21.6% to an estimated 1,155 tcf at yearend 2006 from 950 tcf 2 years earlier.
Coalbed methane resources declined 1.9% to an estimated 166 tcf from 169 tcf during that same period, according to PGC. Curtis said this reflected heavy production as operators aggressively developed the resource. Other committee officials agreed. "I think it's maturing. Operators have been chasing CBM for 5-10 years," said PGC Chairman Michael K. Decker, who also is executive vice-president and chief operating officer of Gasco Energy Inc., Englewood, Colo.
Midcontinent shales
The excitement over CBM's potential during the 1990s has shifted to shales, due largely to successes in the Midcontinent's Arkoma, Anadarko, Fort Worth, and Permian basins, PGC said. But the formations, while prolific, can be hard to produce. "Shale wells typically produce small volumes. A field can require a lot of wells and a lot of infrastructure," Curtis said.
But the potential extends to other regions. "The Rockies are just getting started. There could be a major increase there from shale gas in another 2 years," said Decker. Drilling a well to a shale formation there can cost $8 million, compared to $2-3 million for a shallower conventional well, he said.
Gasco recently completed its first shale gas well in Utah's Uinta basin with satisfactory results and one of its competitors, Questar Resources, has drilled four and may drill another, Decker said.
The committee, which draws its members from the gas industry, academia, and government agencies, does not consider access, politics, or price in its estimates. It does try to avoid deposits which are unlikely to be produced for technical reasons.
"Because so many of our members work the basins for a living, the estimates use a realistic cost-to-production ratio. The gas is technically recoverable, but economies vary by company," said Curtis.
As technology improves, however, resources can move from being speculative to being possible or probable, he continued. "The Powder River basin is an excellent example. When the first wells were drilled there, it was thought they'd never produce. Now, after the application of new technology, two new wells are drilled weekly there," he said.
Others warned that federal policy actions could increase domestic demand for gas. "If Congress looks at carbon constraints, it should look very carefully at natural gas supplies. In our view, it hasn't," said Chris McGill, AGA's managing director of policy.
"The treatment of access has been very uneven. It is a problem," he added.
Contact Nick Snow at [email protected].
