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Coal reservoirs especially deep unminable coal reservoirs, are viable geological target formations for CO2 storage to mitigate greenhouse gas emissions. An advantage of this process is that a large amount of CO2 can be stored at relatively low pressure, thereby reducing the cost of pumping and injection. Other advantages include the use of existing well infrastructure for CO2 injection and to undertake enhanced recovery of coalbed methane (ECBM), both of which partially offset storage costs. However, ECBM faces difficulties such as low initial injectivity and further permeability loss during injection. Although expensive to perform, ECBM field experiments are essential to bridge laboratory study and large-scale implementation. China is one of the few countries that have performed ECBM field experiments, testing a variety of different geological conditions and injection technologies. These projects began more than a decade ago and have provided valuable experience and knowledge. In this article, we review past and current CO2 ECBM field trials in China and compare with others performed around the world to benefit ECBM research and inform future projects. Key aspects of the ECBM field projects reviewed include the main properties of target coal seams, well technologies, injection programmes, monitoring techniques and key findings. [ABSTRACT FROM AUTHOR]

Shale gas has become a key natural gas resource and has been a great success in the USA and a few other countries. The gas production behaviour from shale is different to that from conventional gas reservoirs or coal seam reservoirs, primarily because of the different gas storage and flow behaviours in shale. Gas is stored in shale mainly as adsorbed gas in the pores of organic matter and clay minerals and as free gas compressed in other pores. Thus to understand how free and adsorbed gas contribute to the total gas production is a key question for shale gas reservoir engineering. One method to answer this question is by using reservoir simulation; however, this will require a reservoir simulator representing the shale gas storage and flow behaviours. In this work, a triple porosity model was applied in the reservoir simulator SIMED II, which was designed for dual porosity coal seam reservoirs, to account for both gas storage mechanisms of adsorption and free gas. A unique aspect of this new development is that the adsorbed gas, matrix free gas and fracture free gas are identified as different gas types but having the same gas properties. Thus the flow and production of gases with different storage mechanisms are directly identified in the simulation and output. The developed simulator was validated through history matching production data of a vertical well from the Barnett Shale. Then a series of parameter sensitivity analyses was carried out to investigate the impact of reservoir properties on adsorbed and free gas production. The results show that the contribution of adsorbed gas on the total gas production is generally low and is dependent on many factors such as the reservoir permeability, porosity and adsorption behaviour, and hydraulic fracturing effect. [ABSTRACT FROM AUTHOR]

Abstract: Permeability is one of the most important parameters for CO2 injection in coal to enhance coalbed methane recovery. Laboratory characterization of coal permeability provides useful information for in situ permeability behavior of coal seams when adsorbing gases such as CO2 are injected. In this study, a series of experiments have been conducted for coal samples using both non-adsorbing and adsorbing gases at various confining stresses and pore pressures. Our observations have showed that even under controlled stress conditions, coal permeability decreases with respect to pore pressure during the injection of adsorbing gases. In order to find out the causes of permeability decrease for adsorbing gases, a non-adsorbing gas (helium) is used to determine the effective stress coefficient. In these experiments using helium, the impact of gas sorption can be neglected and any permeability reduction is considered as due to the variation in the effective stress, which is controlled by the effective stress coefficient. The results show that the effective stress coefficient is pore pressure dependent and less than unity for the coal samples studied. The permeability reduction from helium experiments is then used to calibrate the subsequent flow-through experiments using adsorbing gases, CH4 and CO2. Through this calibration, the sole effect of sorption-induced strain on permeability change is obtained for these adsorbing gas flow-through experiments. In this paper, experimental results and analyses are reported including how the impact of effective stress coefficient is separated from that of the sorption-induced strain on the evolution of coal permeability. [Copyright &y& Elsevier]

Abstract: Coal permeability is highly sensitive to the stress. Meanwhile, coal swells with gas adsorption, and shrinks with gas desorption. Under reservoir conditions these strain changes affect the cleat porosity and thus permeability. Coal permeability models, such as the Palmer and Mansoori and Shi and Durucan models, relate the stress and swelling/shrinkage effect to permeability using an approximate geomechanical approach. Thus in order to apply these models, stress–permeability behaviour, swelling/shrinkage behaviour and the geomechanical properties of the coal must be estimated. This paper presents a methodology for the laboratory characterization of the Palmer and Mansoori and Shi and Durucan permeability models for reservoir simulation of ECBM and CO2 sequestration in coal. In this work a triaxial cell was used to measure gas permeability, adsorption, swelling and geomechanical properties of coal cores at a series of pore pressures and for CH4, CO2 and helium with pore pressures up to 13MPa and confining pressures up to 20MPa. Properties for the permeability models such as cleat compressibility, Young''s modulus, Poisson''s ratio and adsorption-induced swelling are calculated from the experimental measurements. Measurements on an Australian coal are presented. The results show that permeability decreases significantly with confining pressure and pore pressure. The permeability decline with pore pressure is a direct result of adsorption-induced coal swelling. Coal geomechanical properties show some variation with gas pressure and gas species, but there is no direct evidence of coal softening at high CO2 pressures for the coal sample studied. The experimental results also show that cleat compressibility changes with gas species and pressure. Then the measured properties were applied in the Shi and Durucan model to investigate the permeability behaviour during CO2 sequestration in coal. [Copyright &y& Elsevier]

The sample size or particle size of shale plays a significant role in the characterization of pores by various techniques. To systematically investigate the influence of particle size on pore characteristics and the optimum sample size for different methods, we conducted complementary tests on two overmature marine shale samples with different sample sizes. The tests included small-angle neutron scattering (SANS), gas (N2, CO2, and H2O) adsorption, mercury injection capillary pressure (MICP), and field emission-scanning electron microscopy (FE-SEM) imaging. The results indicate that artificial pores and fractures may occur on the surface or interior of the particles during the pulverization process, and some isolated pores may be exposed to the particle surface or connected by new fractures, thus improving the pore connectivity of the shale. By comparing the results of different approaches, we established a hypothetical model to analyze how the crushing process affects the pore structure of overmature shales. Our results imply that intact wafers with a thickness of 0.15–0.5 mm and cubic samples (~1 cm3) are optimal for performing SANS and MICP analyses. Meanwhile, the 35–80 mesh particle size fraction provides reliable data for various gas physisorption tests in overmature shale. Due to the intrinsic heterogeneity of shale, future research on pore characteristics in shales needs a multidisciplinary approach to obtain a more comprehensive, larger scale, and more reliable understanding. [ABSTRACT FROM AUTHOR]

Commercial gas production has been achieved in China's marine shale of the Silurian Longmaxi formation in the eastern Sichuan area, and experience for developing shale gas in complex structural areas has been gathered. A set of Longmaxi Formation shales deposited in the northwestern Hunan area has close relationship with the eastern Sichuan Longmaxi shale on both depositional environment and tectonic evolution. Therefore, it is important to undertake an integrated evaluation of the Longmaxi formation shale in the northwestern Hunan area. This work combined field investigations and the laboratory measurements using outcrop samples to study the petrology, geochemistry, reservoir and adsorption characteristics of the Longmaxi shale in the northwestern Hunan area. The geological settings and reservoir properties were compared with those of the eastern Sichuan Longmaxi shale using publically available data. The results show that the hydrocarbon generation ability, organic matter maturity, sealing capacity and reservoir stimulation effectiveness of the Longmaxi Formation shale in the northwestern Hunan area are comparable to those in the eastern Sichuan area. The Longmaxi shale in the northwestern Hunan area therefore shows early signs of development potential, and the drilling of exploration wells is thus warranted to further evaluate its gas content and other in-situ reservoir properties for possible shale gas development in the near future. [ABSTRACT FROM AUTHOR]

Gas is stored in shale mainly in free and adsorbed phases. Since a significant amount of gas in the shale is adsorbed to the organic matter and/or clay minerals, it is possible that gas adsorption will induce shale swelling, which may then has an impact on the gas flow behavior in the shale thus its gas production. In this work, strain behavior was studied in two gases, helium and methane, at different pore pressures under constant hydrostatic pressure at 20 MPa on two shale samples. The results show that porosity and volumetric strain are functions of gas pressure and the strain is larger in methane than helium demonstrating gas adsorption induced swelling for the shale samples. The calculated methane adsorption induced swelling strain is at a magnitude of 0.1% volumetrically with pressure at 10 MPa for the shale samples studied. The adsorption induced shale swelling strain shows a Langmuir-like relationship with pressure and is proportional to the amount of methane adsorbed. The results also show slight anisotropic strain behavior between the two directions of parallel and perpendicular to the bedding and strain hysteresis with methane in and out of the shale. The gas adsorption induced swelling may influence gas flow in gas shale, thus more research in this topic is warranted. [ABSTRACT FROM AUTHOR]

Abstract: Adsorption-pore (pore size less than 100nm) and seepage-pore (pore size greater than 100nm) structures have great effects on gas adsorption/diffusion and gas flow in coal seam, respectively. Pore properties, including porosity, size/volume distribution, volumes, surface fractals, specific surface area, and connectivity, for four coals from Northeast China were acquired through mercury porosimetry, N2 adsorption at 77K, small angle X-ray scattering (SAXS) and their relationships with CH4 adsorption capacity and permeability are investigated. The roughness of pore surface was analyzed with surface fractal dimensions. Obtained values of fractal dimensions from mercury porosimetry and N2 adsorption at 77K were comparable with values determined by SAXS measurement. The surface fractals results show that the more irregular surface, the more inhomogeneous pore structures is, meaning more surface area and then stronger adsorption capability, especially for the micropores with sizes in the range of 2–10nm and the mesopores. Moreover, with the data of petrographic, proximate and ultimate analyses, the ratio of C/H, moisture content, ash yield also have great effects on CH4 adsorption capacity of coals. For bituminous and subbituminous coals, macropores have significant impacts on gas flow. The coals with high contents of macroporosity generally have good gas flow capability. Therefore, they may have significant implications for coalbed methane (CBM) exploitation. [Copyright &y& Elsevier]