Abstract Scanning electron microscopy (SEM) of shales from three unconventional gas/liquid plays (Nordegg, Montney, Duvernay) of the Western Canadian Sedimentary Basin were combined with routine analytical investigations to characterize mineral composition, mineral assemblage, morphology, organic content, and porosity. The investigations demonstrated that despite marked diagenetic differences between these shales, some common textural and pore characteristics occurred in all samples. The study showed that SEM morphological investigations of unconventional shale reservoirs provided important information about mineral aggregates, cementation, and clay mineral distribution, which allows interpretations about diagenetic history.

Abstract Mature coalbed methane reservoirs are prospective as major sinks for anthropogenic CO 2 , and injection of CO 2 shows promise for increasing coalbed methane reserves through enhanced recovery. Assessment of the carbon sequestration and enhanced recovery potential of coal in the Black Warrior basin indicates that numerous geological variables, including stratigraphy, structure, hydrology, geothermics, and coal quality, have a strong impact on the quantity of carbon that can be sequestered. Key variables affecting the feasibility of sequestration and enhanced recovery in the Black Warrior basin include (1) the distribution of mineable coal, (2) the distribution of formation water saline enough for underground injection, and (3) the distribution of structural compartments with sufficient reservoir continuity to host multiple five-spot well patterns. Within the developed coalbed methane fields, the feasible CO 2 sequestration potential is estimated to be 166 Bscm (5.9 Tscf), or 341 MMt, which can facilitate long-term sequestration of CO 2 emissions from coal-fired power plants. The potential for enhanced coalbed methane recovery in this area is estimated to be between 16 and 30 Bscm (0.6 and 1.1 Tscf), and realization of this potential would expand proven coalbed methane reserves by more than 30%.

Abstract In gas shales, natural gas occurs both as free gas in intergranular and fracture porosity and as an adsorbed phase onto the surfaces of clays and organic matter, analogous to natural gas storage in coalbeds. The adsorption capacity of shales from Kentucky, Indiana, and West Virginia was estimated using drill cuttings and sidewall cores to determine both CO 2 and CH 4 adsorption isotherms. Elemental capture spectroscopy logs were analyzed to investigate possible correlations between adsorption capacity and mineralogy. The maturity of the shale was characterized using average random vitrinite reflectance data yielding values ranging from 0.78 to 1.59 (upper oil to wet gas and condensate hydrocarbon maturity values). Total organic carbon (TOC) content ranges from 0.69 to 14%. Calculated CO 2 adsorption capacities at 2.75 MPa range from a low of 0.4 m 3 /t (14.1 ft 3 /t) to more than 4.2 m 3 /t (148.3 ft 3 /t). A direct linear correlation between measured TOC and the adsorption capacity of the shale has been determined; CO 2 adsorption capacity increases with increasing TOC. Data also suggest that CO 2 is preferentially adsorbed (5.3:1) and would displace CH 4 , leading to a potential method for enhancing natural gas recovery in gas shales. Initial estimates of the volume of CO 2 sequesterable in the shale based on these data indicate a capacity of as much as 25 billion t in the deeper and thicker parts of the Devonian shales across Kentucky. Discounting the uncertainties in reservoir volume and injection efficiency, these results indicate that gas shales could provide a potentially large geologic sink for CO 2 . Moreover, the extensive occurrence of gas shales in Paleozoic and Mesozoic basins across North America makes them an attractive regional target for economic CO 2 storage and enhanced natural gas production.