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Resource-Assessment Perspectives for Unconventional Gas Systems

¹ U.S. Geological Survey, Mail Stop 939, Denver Federal Center, Denver, Colorado 80225; schmoker{at}usgs.gov

James W. Schmoker, Ph.D., is an emeritus scientist at the U.S. Geological Survey, Denver, Colorado, where he has spent the last decade working on issues of petroleum resource assessment. He has contributed to the methodology used by the U.S. Geological Survey in many of their recent oil and gas assessments and is particularly interested in the geologic nature and approaches to resource assessment of continuous (unconventional) oil and gas accumulations.

Concepts are described for assessing those unconventional gas systems that can also be defined as continuous accumulations. Continuous gas accumulations exist more or less independently of the water column and do not owe their existence directly to the buoyancy of gas in water. They cannot be represented in terms of individual, countable fields or pools delineated by downdip water contacts. For these reasons, traditional resource-assessment methods based on estimating the sizes and numbers of undiscovered discrete fields cannot be applied to continuous accumulations. Specialized assessment methods are required.

Unconventional gas systems that are also continuous accumulations include coalbed methane, basin-centered gas, so-called tight gas, fractured shale (and chalk) gas, and gas hydrates. Deep-basin and bacterial gas systems may or may not be continuous accumulations, depending on their geologic setting.

Two basic resource-assessment approaches have been employed for continuous accumulations. The first approach is based on estimates of gas in place. A volumetric estimate of total gas in place is commonly coupled with an overall recovery factor to narrow the assessment scope from a treatment of gas volumes residing in sedimentary strata to a prediction of potential additions to reserves. The second approach is based on the production performance of continuous gas reservoirs, as shown empirically by wells and reservoir-simulation models. In these methods, production characteristics (as opposed to gas in place) are the foundation for forecasts of potential additions to reserves.

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