Nanoscale pores have an important role in the accumulation of gas in shale gas reservoirs. Indeed, the formation of nanopores is critical for the characterization and evaluation of a shale reservoir. Moreover, the effect of pyrolysis on the modification of nanopores is not clear. Therefore, this paper focuses on pyrolysis and nitrogen adsorption experiments to examine the nanoscale pore structure and evolution in marine shale strata with low total organic carbon content. All of the examined samples contain micro-, meso-, and macropores. The results show that the number of micropores increased as a result of artificial maturation (i.e., pyrolysis), which resulted in a significant increase in the surface area and the total pore volume. The openness of the pores significantly increased when the maturity was higher than 2.5% R o (vitrinite reflectance). The 1.5–7.5 and 60–70 nm pores are the most pronounced to change after pyrolysis. Furthermore, liquid hydrocarbons produced during heating were shown to influence pores of approximately 41 nm width. In the overmature stage (R o = 2.77%), the number of pores and pore volume significantly increased during pyrolysis. The pore structure of the overmature shale was different from that of the shale during the mature and high-maturity stages. Pores less than 20 nm wide nearly provided 90% of the surface area and at least 50% of the pore volume. The transformation of organic matter from the solid state to the liquid and gas states is most closely related to the number of mesopores. The pores with sizes less than 10 nm in width have the greatest change in the proportion of the surface area to pore volume with increasing maturation.

Micro-heterogeneity is an integral parameter of the pore structure of shale gas reservoir and it forms an essential basis for setting and adjusting development parameters. In this study, scanning electron microscopy, high-pressure mercury intrusion and low-temperature nitrogen adsorption experiments were used to qualitatively and quantitatively characterize the pore structure of black shale from the third member of the Xiamaling Formation in the Yanshan area. The pore heterogeneity was studied using fractal theory, and the controlling factors of pore development and heterogeneity were evaluated in combination with geochemical parameters, mineral composition, and geological evolution history. The results show that the pore structure of the reservoir was intricate and complicated. Moreover, various types of micro-nano scale pores such as dissolution pores, intergranular pores, interlayer pores, and micro-cracks are well developed in member 3 of the Xiamaling Formation. The average porosity was found to be 6.30%, and the mean value of the average pore size was 4.78 nm. Micropores and transition pores provided most of the storage space. Pore development was significantly affected by the region and was mainly related to the total organic carbon content, vitrinite reflectance and mineral composition. The fractal dimension, which characterizes the heterogeneity, is 2.66 on average, indicating that the pore structure is highly heterogeneous. Fractal dimension is positively correlated with maturity and clay mineral content, while it is negatively correlated with brittle mineral content and average pore size. These results indicate that pore heterogeneity is closely related to thermal history and material composition. Combined with the geological background of this area, it was found that the pore heterogeneity was mainly controlled by the Jurassic magmatism. The more intense the magma intrusion, the stronger the pore heterogeneity. The pore structure and its heterogeneity characteristics present today are a general reflection of the superimposed geological processes of sedimentary-diagenetic-late transformation. The influence of magmatic intrusion on the reservoir is the main geological factor that should be considered for detailed evaluation of the Xiamaling Formation shale gas reservoir in the Yanshan area.

Diffusion ability is an important indicator of shale gas reservoir quality. In this paper, the diffusion coefficient of the Longmaxi Formation is measured via the free hydrocarbon concentration method, and the diffusion ability, influencing factors, and seepage flow are discussed. Results show that the diffusion coefficient of the Longmaxi Formation is between 1.23 Â 10 À5 and 2.98 Â 10 À5 cm 2 s À1 with an average value of 2.19 Â 10 À5 cm 2 s À1 (confining pressure 3.0 MPa). The diffusion coefficient is calculated for various pressures using an empirical formula (D ¼ 0.339K 0.67 /M 0.5) and experimentally measured data. The estimated, temperaturecorrected diffusion coefficient of the Longmaxi Formation is 3.94 Â 10 À6-7.24 Â 10 À6 cm 2 s À1 with an average value of 5.28 Â 10 À6 cm 2 s À1 for depths from 1000 to 3000 m (confining pressure 16.7-39.7 MPa). The diffusion coefficient increases with increasing depth of the reservoir due to the changes in pressure and temperature. Fitting parameters show that the porosity of the reservoir and clay minerals is positively correlated with the diffusion coefficient, and the diffusion coefficient is also related to factors such as total organic carbon and the maximum reflectance of vitrinite (Ro). The diffusion flow rate is 0.177-0.204 m 3 d À1 with an average of 0.182 m 3 d À1. Linear seepage flow is 4.95 Â 10 À4-14.29 Â 10 À4 m 3 d À1 with an average of 8.87 Â 10 À4 m 3 d À1 , calculated from the diffusion coefficient and permeability per unit flow. These results indicate that the migration of shale gas in the deep region of the reservoir is mainly by diffusion. Therefore, diffusion is an important shale gas flow mechanism.