A theory is presented for calculating the constrained (matrix) compressibility for aquifers from responses to tides and changes in surface pressure when both gas and water are present. With this theory, a new method to determine matrix compressibility without a pump test is developed. The method is then applied to a coalbed methane well in the Piceance basin.

The ability to produce low cost, pipeline quality gas from low permeability deep coal reservoirs depends largely on thorough integration of exploration methods with appropriate drilling, completion and production strategies. In the extreme case, areas that are not economic with current completion technologies should be avoided with adherence to prudent exploration practices. Therefore, reliable predictive geologic methods to specify coal reservoir conditions need to precede drilling and completion decisions. Dominant coal reservoir mechanisms include: permeability, saturation, reservoir pressure and gas-in-place. Production characteristics from low permeability coal reservoirs are most sensitive to the interaction between type of saturation and reservoir pressure. The geologic processes responsible for these reservoir conditions have been examined in the Piceance Basin. This basin, known for low permeability reservoirs, was selected for geologic evaluation due to the large coalbed methane resource and large data base. Also located in the basin is the Deep Coal Seam Project, a multiyear, multi-well, field laboratory joint venture by the Gas Research Institute and Resource Enterprises, Inc., providing fully integrated reservoir and geologic engineering data on deep coal reservoirs. Reservoir diagnostics and modeling suggests that reservoir pressure and type of saturation demonstrate an interaction between catagenesis and permeability. Thick, thermally mature coal deposits actively generate more gas than can be adsorbed by the coal or be diffused through a low permeability system. In these regions over-pressuring occurs. Ultimately, pore pressure will exceed insitu stresses resulting in tensional fractures through the coal bearing sequences. While the coal seams remain in the active gas generation phase, the fractures and pore spaces become gas saturated. Eventual temperature reduction through erosion will under-pressured reservoir. Imbibition of water into these reservoir is unlikely in areas of low permeability. In summary, source rock evaluation techniques have been applied to characterize and predict coal reservoir mechanisms in low permeability basins. Introduction A portion of the extensive gas accumulations found in the San Juan Basin, the Green River Basin, and the Alberta Basin has been sourced largely by coal seams. Despite the amount of data collected on coal reservoir characteristics and coal as a source rock, little work has been done integrating the two sciences. A coupled understanding of coal reservoir mechanisms and coal maturation will assist the explorationist in his pursuit of coalbed gas resources. This work was sponsored by the Gas Research Institute under Contract No. 5083-214-0844 with Resource Enterprises, Inc. A geologic model is presented which incorporates the coal's inability to transfer heat with its ability to generate large volumes of gas over a specific temperature and time sequence. In basins where low reservoir permeability prohibits crossformational fluid flow, gas generation can exceed the quantity of gas that can migrate through the geologic system. This results in high pore pressure within the coal reservoirs. Conversely, where gas migration exceeds the rate of gas generation, low pore pressure will be observed. These stages of reservoir disequilibrium have been observed in various deep coal basins of the western United States. P. 297^

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SPE Members Abstract Methane gas contained in coal represents a potential new gas supply. Transformation of this large gas-in-place resource to reserves will depend on developments of modified and/or new completion methods to achieve long-term economic production. Coal reservoirs typically have very low matrix permeability with gas being desorbed from the matrix to the wellbore through a system of natural fractures or cleats. Due to low permeability, coal reservoirs usually require hydraulic fracture stimulation to achieve economic production. Investigations have shown that hydraulic fractures usually propagate parallel to the maximum stress or face cleat direction, and therefore may not adequately access an anisotropic reservoir. A more effective stimulation technique may be a horizontal borehole placed perpendicular to the maximum permeability direction. This paper discusses the application of drilling horizontal boreholes for coalbed methane recovery in two different situations:in a coal seam associated with an active underground coal mine, andin a deeply buried unmineable coal seam. Introduction Coal seams in the contiguous United States have been estimated to contain s much as 400 trillion cubic feet (TCF) (11-32 TM3) of pipeline quality natural gas. Deeply buried unminable coal seams at depths 3000-7000 feet (914-2134 m) are estimated to contain more than half of the coalbed methane resource. Most of this resource lies within the borders of five western states: Colorado, New Mexico, Utah, Wyoming and Washington. Commercialization of this large potential new gas supply will depend on the developments of modified and/or new completion methods to achieve long-term economic production. Coalbeds are much different than conventional natural gas reservoirs in that the coal reservoir is both source rock and reservoir rock. Methane is the principal by-product of coalification. The amount of methane retained within a coal reservoir is directly related to gas generation during the coalification process, and a function of depth, coal rank and hydrogeologic environment. In most cases considerably more methane gas has been generated than retained. Gas is held in the coal reservoir in three possible ways:as absorbed methane molecules on the surface of micropores,as free gas within fractures or pores, andas dissolved gas in formation water. Of these, the first accounts for the majority of the retained gas volume. The free gas contained in the natural fractures or cleats within the coal constitutes a smaller fraction of the resource, however the cleat system provides the primary flow channel or permeability of the coal. The cleat system usually contains two sets of closely spaced vertical natural fractures. The primary set of natural fractures are face cleats, a less defined set of perpendicular fractures are butt cleats. Gas flow depends on the natural fracture, cleat system and diffusion within the coal matrix. Coal reservoirs typically are tight with porosity less than 8 percent and matrix permeabilities below 10 md. Due to the low permeability of the matrix of the coal seam, stimulation is usually required to achieve economic production. Hydraulic fracturing is the most common stimulation technique used. Investigation of the orientation of hydraulic fractures in anisotropic coal reservoirs have shown that the fracture usually propagates parallel to the face cleat (maximum stress and permeability direction) and, therefore, may not be the most effective access to the reservoir. A more effective stimulation technique may be a horizontal borehole placed perpendicular to the face cleat direction, thereby providing maximum access to primary flow channels. P. 195^