The new surge in drilling for coalbed methane gas brought on by the attractive tax credits has increased the need for quantitative evaluation of coal formations. The potential resource base in the U.S. alone is on the order of 422 Tcf. Currently available petrophysical and fluid flow mechanistic models for gas reservoir analysis in traditional clastic or carbonate environments are notably inadequate for coal formation evaluation and well productivity assessment. Existing coal formation evaluation techniques rely on core measurements and certain basic log measurements such as "bulk" density, The evaluation program as such, is typically site specific and devoid of critical answers like recoverable reserves and well productivity assessment. Additions and improvements to the existing technology are needed to efficiently exploit the production of methane gas from coalbeds.
In this paper we present a methodology that integrates the existing technology with new measurements and techniques. Such a procedure can allow one to evaluate the coal formation specifically for identification, resource definition (thickness), gas content (reserves), recoverable reserves (permeability, porosity and reservoir pressure) and to plan for the de-watering process (reservoir performance). The methodology provides evaluation alternatives depending on the coal seam thickness and the type and concentration of the fracture system. The thin laminated coal seams found in basins like the Black Warrior and the Appalachian require a different evaluation suite of logs compared to those required for the relatively thick (greater than 2 ft) coal seams found in the San Juan and Piceance Basin. Also, the type and concentration of fractures within the cleat system dictate the capillary pressure pattern and thus may require specific transient pressure tests. The majority of coal basins found in the U.S., Canada, U.K., Central Europe and Australia can be broadly categorized within the above aspects of seam thickness and fracture system distribution.