According to comprehensive research on forming conditions including sedimentary facies, reservoirs, source rocks, and palaeo-uplift evolution of Sinian-Cambrian in Sichuan Basin, it is concluded that: (1) large-scale inherited palaeo-uplifts, large-scale intracratonic rifts, three widely-distributed high-quality source rocks, four widely-distributed karst reservoirs, and oil pyrolysis gas were all favorable conditions for large-scale and high-abundance accumulation; (2) diverse accumulation models were developed in different areas of the palaeo-uplift. In the core area of the inherited palaeo-uplift, "in-situ" pyrolysis accumulation model of paleo-reservoir was developed. On the other hand, in the slope area, pyrolysis accumulation model of dispersed liquid hydrocarbon was developed in the late stage structural trap; (3) there were different exploration directions in various areas of the palaeo-uplift. Within the core area of the palaeo-uplift, we mainly searched for the inherited paleo-structural trap which was also the foundation of lithological-strigraphic gas reservoirs. In the slope areas, we mainly searched for the giant structural trap formed in the Himalayan Period.

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The pore structure directly controls the tight reservoir’s physical properties and plays a crucial role in gas charging and accumulation. To characterize the pore structure accurately, it is critical for the exploration and development of tight gas. In this paper, the pore structure of a tight sandstone reservoir in the Carboniferous Benxi Formation coal-bearing strata in the Ordos Basin was characterized by X-ray diffraction, thin sections, scanning electron microscopy, high-pressure mercury intrusion, and X-ray–computed tomography techniques. The porosity and permeability of the Benxi Formation reservoir are 0.12–12.53% and 0.0003–33.59 mD, respectively. The type of pores is dominated by secondary pores, followed by primary pores and microcracks. The reservoirs are divided into three types based on the high-pressure mercury injection curve pattern and the displacement pressure. The average pore radii of Type I and Type II reservoirs are similar, and the pore volume, average radius of throats, and pore–throat connectivity ratio of Type II reservoirs are all higher than those of Type I from the results displayed by micron CT. The pores of the reservoir are divided into small pores (<1 μm), mesopores (0.1–1 μm), and macropores (>1 μm) according to their diameters. In type I reservoirs, three types of pores are found, and the type II reservoirs have mainly mesopores and macropores. There are almost no large pores in Type III reservoirs. Type I has the best porosity and the smallest heterogeneity, while Type II has stronger heterogeneity than Type I, according to the findings when combining the high-pressure mercury intrusion experiment with fractal theory. Total fractal dimension has a weak negative correlation with porosity and a positive correlation with permeability. The contribution rate of mesopores and macropores to porosity is more affected by heterogeneity. The seepage of a reservoir is mainly affected by the throat radius and throat connectivity ratio under the same porosity condition. With a larger throat radius and a higher throat connection ratio, the seepage capacity will be stronger. As the content of clay minerals increases, the heterogeneity of the reservoir increases and permeability decreases.

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