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AAPG Bulletin, V.
Fractured shale-gas systems
John B. Curtis1
1Department of Geology and Geological Engineering, Colorado School of Mines, Golden, Colorado 80401; email: [email protected]
John B. Curtis is associate professor and director, Petroleum Exploration and Production Center/Potential Gas Agency at the Colorado School of Mines. He is an associate editor for the AAPG Bulletin and The Mountain Geologist. As director of the Potential Gas Agency, he works with a team of 145 geologists, geophysicists, and petroleum engineers in their biennial assessment of remaining United States natural gas resources.
It has been my pleasure and a continuing education for the last 25 years to work with many excellent scientists and engineers on the challenges presented by shale-gas systems. United States shale-gas production and future world opportunities certainly would be limited without the insights gained from the Eastern Gas Shales Project of the U.S. Department of Energy and from research sponsored by the Gas Research Institute/Gas Technology Institute. I particularly acknowledge the enthusiasm and vision of the late Charles Brandenburg and of Charles Komar. Thoughtful reviews by Kent Bowker, Robert Cluff, and David Hill significantly improved this manuscript. I also thank Daniel Jarvie for his review of my Barnett Shale discussion. Ira Pasternack provided helpful discussions concerning the Antrim Shale. The technical editing and graphic skills of Steve Schwochow are greatly appreciated. Finally, I thank Ben Law for his energy and patience in completion of this project.
The first commercial United States natural gas production (1821) came from an organic-rich Devonian shale in the Appalachian basin. Understanding the geological and geochemical nature of organic shale formations and improving their gas producibility have sub sequently been the challenge of millions of dollars worth of research since the 1970s. Shale-gas systems essentially are continuous-type biogenic (predominant), thermogenic, or combined biogenic-thermogenic gas accumulations characterized by widespread gas satu ration, subtle trapping mechanisms, seals of variable lithology, and relatively short hydrocarbon migration distances. Shale gas may be stored as free gas in natural fractures and intergranular porosity, as gas sorbed onto kerogen and clay-particle surfaces, or as gas dis solved in kerogen and bitumen.
Five United States shale formations that presently produce gas commercially exhibit an unexpectedly wide variation in the values of five key parameters: thermal maturity (expressed as vitrinite reflectance), sorbed-gas fraction, reservoir thickness, total organic car bon content, and volume of gas in place. The degree of natural fracture development in an otherwise low-matrix-permeability shale reservoir is a controlling factor in gas producibility. To date, unstimulated commercial production has been achievable in only a small proportion of shale wells, those that intercept natural fracture networks. In most other cases, a successful shale-gas well requires hydraulic stimulation. Together, the Devonian Antrim Shale of the Michigan basin and Devonian Ohio Shale of the Appalachian basin accounted for about 84% of the total 380 bcf of shale gas produced in 1999. However, annual gas production is steadily increasing from three other major organic shale formations that subsequently have been explored and developed: the Devonian New Albany Shale in the Illinois basin, the Mississippian Barnett Shale in the Fort Worth basin, and the Cretaceous Lewis Shale in the San Juan basin.
In the basins for which estimates have been made, shale-gas resources are substantial, with in-place volumes of 497-783 tcf. The estimated technically recoverable resource (exclusive of the Lewis Shale) ranges from 31 to 76 tcf. In both cases, the Ohio Shale ac counts for the largest share.
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