Methane adsorption experiments were conducted on a series of organic-rich shales, isolated kerogens, and pure clay minerals at 60 ˚C and up to 20 MPa pressure. The maximum adsorption capacities of the two isolated kerogens (type I) (17.45 cm 3 /g and 12.41 cm 3 /g) were much higher than those of the clay minerals and shale samples. In the high-over mature stage, the affinity of methane for type I kerogens gradually increased, while the amounts of methane adsorbed decreased with increasing thermal maturity. Among the pure clay minerals, the methane adsorption capacity decreased in the following order: montmorillonite (4.02 cm 3 /g) > kaolinite (3.48 cm 3 /g) > illite (3.46 cm 3 /g) > illite/smectite mixed layer (3.1 cm 3 /g) > chlorite (0.88 cm 3 /g); the methane adsorption capacities were controlled by the effective surface areas available for adsorption. These clay minerals with higher Langmuir pressures exhibited weaker affinities for methane than the isolated kerogens. Moreover, the adsorption results of kerogen, shale, and illite at different temperatures (30 ˚C, 60 ˚C, and 90 ˚C) show that the V L values of kerogen decreased linearly with increasing temperature, while the amount of adsorbed water on clay minerals decreased with increasing temperature, which may have affected the methane adsorption capacity. The results show that the contributions of kerogens to the adsorption capacities of the two bulk shale samples were ~ 43.08% and 56.58%, and the methane adsorption of clay minerals accounted for ~ 44.12% and 16.74%.

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This study presents both experimental and theoretical investigations about gas transport in shales. Gas apparent permeability coefficients and Klinkenberg slippage factors were determined on Longmaxi shales using He, Ar, N2, CH4, and CO2. Then, a model was developed to interpret the experimentally determined gas slippage factor, considering the effects of intrinsic permeability, porosity, tortuosity, and gas physical properties. The proposed model is verified by correlating Klinkenberg-corrected permeabilities and gas slippage factors of shales probed by He, Ar, N2, CH4, and CO2 at different confining pressures. The model can quantitatively describe the gas dependence of slippage factors (He > Ar > N2 > CH4 > CO2). According to the model presented, the slippage factor increases proportionally to the ratio of the characteristic gas parameter (C ) to tortuosity. The model also leads to a practicable approach to determine the effective tortuosity of tight rocks at in situ reservoir stress state. Effective tortuosity of shales determined using helium slippage measurements are far larger than the generally assumed values. Another advantage of the model is its ability to quantitatively account for the variation in permeability values at similar gas slippage and the counterintuitive reduction in gas slippage during compaction observed in previous experiments. The proposed model correctly matches a set of gas slippage measurements and provides insight into gas transport in tight porous medium.