Antrim Shale multicomponent gas storage mechanisms of adsorption, porosity and solution in bitumen preclude the use of conventional gas-in-place volumetric calculations. Total in-situ gas content has been measured using canister degassing techniques adapted from coalbed methane technologies. Gas measurements ranged from approximately 5 scflt to 166 scflt. Gas contents exceed apparent gas-filled porosity by 6 to 8 times where organic content is high. Cross plots of gas content to companion TOC and density measurement resulted in a direct correlation between increasing gas content corresponding to progressive increases in organic matter and an inverse relationship between increasing gas content and decreasing density. The linear function relating density and gas content can be used in conjunction with open-hole log bulk density measurements to calculate gas-in-place.A side-by-side comparison of gas content measurements from rotary sidewall core and whole core demonstrated that the measurements from both core sampling types are of equal accuracy. From the standpoint of cost, sample homogeniety and sampling selection, rotary sidewall cores are preferred over whole core. The total gas contained in the shale can be completely released as a single measurement by crushing the core upon retrieval. Utilizing the on-site gas content measurements, density/gas content relationship and density log it is possible for the first time to locate and quantify gas bearing Antrim shale intervals from well logs.References and illustrations at end of paper. LOG-BASED GAS CONTENT AND RESOURCE ESTIMATES FOR THE ANTRIM SHALE, MICHIGAN BASIN SPE 25910Using digital log-derived bulk density data and simple spread sheet calculations, interval gas-in-place calculations can be performed. A plot of gas-in-place by Antrim shale interval for the Mercury Exploration Dey AI-15 well is shown in Figure 13. This analysis shows that the currently producing Norwood and Lachine members are the most important gas reservoirs, with combined resources of 7.3 Bcf/mf. The Upper Black member is an attractive secondary target, estimated to contain 8.6 Bcf/mf of gas-in-place. CONCLUSIONS services.John-Mark Coates and Tracy Lombardi were responsible for data collection and compilation. Word processing was by Iris Drayton and Kathy Horst with editing by Scott Stevens.

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^

Coalbed methane exploration must evolve to adequately reflect a growing geologic and reservoir understanding in domestic and international coal basins. Currently accepted exploration strategies in the San Juan Basin of New Mexico and the Warrior Basin of Alabama are basin specific and remain unproven outside these traditional methane plays. Future development will require modified exploration strategies to locate commercial prospects in the more complex geologic settings of other less favorable domestic and overseas basins. Coalbed methane operators presently focus exploration efforts on locating areas of improved permeability, over-pressured hydrologie conditions, high methane storage capacity coals and a maximum ratio of gas desorption pressure to initial reservoir pressure. The effects of each of these reservoir properties and more importantly their interaction has not been thoroughly examined. A reservoir simulation study was undertaken to investigate the effects of stress setting as it relates to permeability, pore pressure gradient and coal rank in terms of isotherm characteristics and gas content. A series of 162 well performance simulations were conducted evaluating the interaction of depth, coal permeability in high, normal and relaxed stress settings, gas contents for high, medium and low rank coals and finally, normal and abnormal hydrologie conditions. The results indicate that 1) there is an optimum target depth for a coal of a given rank under a specific stress setting, 2) the optimum producing depth increases with decreasing stress setting, 3) low rank coals exhibit superior production than higher rank coals under similar reservoir conditions and 4) the ratio of desorption pressure to initial reservoir pressure is of less significance than the absolute value of the desorption pressure. Based on these findings, fundamental inadequacies of existing exploration criteria require modification, particularly to the interaction of specific coal reservoir properties.

Commercial exploitation of gas occluded in coal reservoirs has been hampered by appropriate exploration, drilling, completion and production methods.The Deep Coal Seam Proj ect located at the Red Mountain Site, Mesa County, Colorado is a field laboratory exper iment directed to develop, improve, evaluate and communicate the technology required to produce gas from a deeply buried coal reservoir.Regional geologic studies have established the Red Mountain Si te as represent at i ve of the majority of the coalbed methane resource within the Piceance Basin. The project is focused on the D coal seam, belonging to the Cameo Coal group of the Williams Fork Formation, Upper Cretaceous Mesaverde Group.Thickness of the D coal seam ranges from 16 to 20 feet (5 to 6.5 m) throughout the site with an average drilling depth of 5500 feet (1800 m).This coal seam is medium-volatile bituminous in rank with an average gas content of 250 scf/ton (8 scc/gm).

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