High natural gas prices and new technology for unconventional plays are needed to overcome equipment cost challenges and the impact of imported liquefied natural gas, a new study shows.

But per-well performance, not the cost of services, is the key driver of increasing well costs, especially as more wells are drilled in unconventional gas formations.

"Higher market prices, along with advances in technology, can unlock the resource potential of unconventional gas," says Robert Ineson, director of North American gas research at Cambridge Energy Research Associates (CERA), an IHS company. "However, continued strong market prices will be necessary to motivate a sufficient level of drilling to maintain production."

The study, a diminishing-returns analysis, gathered data on 273 individual plays in 50 gas basins in the U.S. and Canada and analyzed the past few years of production and development.

"The study suggests that there is a limit to the unconventional resource potential at market prices within the $4- to $10-per-thousand-cubic-feet range analyzed."

Without supportive prices, domestic gas used for power generation may become uneconomic compared to imported LNG or coal.

"Our study examines the interplay among the future cost of gas production, the geological potential of gas in North America, and how supply would build at higher market prices. This relationship of price versus cost versus geologic potential defines the trajectory of gas production in the years ahead," he says.

CERA identified some of the best opportunities emerging in the rapidly growing East Texas and Rocky Mountain regions. The emerging shale plays in the Appalachian and Black Warrior basins also show growth potential, especially at sustained prices above $6 per thousand cubic feet.

CERA analyzed historical production and costs for the more than 48,000 wells completed in 2005 in more than 273 natural gas plays. By projecting production performance across each play's remaining resources, the diminishing-returns analysis generated overall productive capacity under price scenarios ranging from $4 to $10 per thousand cubic feet. Price and production scenarios were forecast to 2015.



Key findings

The analysis revealed three key operational and strategic findings.

First, the most significant driver in the rise in costs to produce gas has been, and will continue to be, declining production on a per-well basis. The shift to drilling unconventional resources has buoyed U.S. gas production, but has also raised unit costs because gas production in these types of plays, per well, has fallen.

"Well performance, not services, is the top cost driver. Overall systematic cost pressure will continue."





CERA's study also suggests that costs for equipment are no longer the main cost factor, although high equipment costs could push a region into an unprofitable position, says Ineson.

Second, the study broke out 30 basins projected to have the largest and the smallest potential capacity increases from 2005 to 2010. Of the 15 basins with the largest projected capacity increases, 12 are primarily unconventional resources. Of the 15 basins projected to have either the smallest increases or largest declines, only two are unconventional.

Finally, the study shows that each play's economic position depends on the performance of its top-quartile wells in initial production rates and estimated ultimate recovery.

Typically, a play's top-quartile wells often produce between one-half and two-thirds of a basin's total estimated ultimate recovery. However, production performances of the top-quartile wells for unconventional plays vary much more than the production performance of conventional resources.

CERA said the variance is due to the uneven level of industry experience of managers and the differing technologies used to develop and maintain wells.

Unconventional gas, as a percentage of total U.S. gas production, grew from 23% in 1996 to 42% in 2006 and is expected to rise to 62% in 2016, says Ineson.

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