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The Ediacaran Dengying Formation fourth member in Central Sichuan Basin is the deep dolomite gas reservoir with the largest natural gas reserves in China, providing an excellent example for understanding the effect of hydrothermal silicification on deep dolomite reservoir quality. By integrating petrology, geochemistry and physical property measurement, this study aims to reveal the genesis of different quartz phase and their corresponding diagenetic events, and to discuss the temporal relationship of diagenetic events and their effects on the quality of deep dolomite reservoir in Dengying fourth member. Three phases of quartz cement are identified in Ediacaran Dengying Formation deep dolomite reservoirs of Central Sichuan Basin as follows: (1) first‐stage quartz filled in primary reservoir spaces, (2) second‐stage quartz mainly filled in secondary reservoir spaces, and (3) third‐stage quartz filled in secondary reservoir spaces with Mississippi Valley‐Type minerals. By analysing petrographic and temporal relationships between these fabrics, it is suggested that the first‐stage quartz precipitated during the syndiagenetic stage, the second‐stage quartz precipitated during middle diagenetic stage, and the third‐stage quartz precipitated during middle diagenetic stage as well. Silicification during syndiagenetic stage is characterized by replacement of cryptocrystalline quartz and cementation of first‐stage quartz within matrix dolomite (MD). After syndiagenetic silicification, the mineral composition of the MD changed from magnesium calcium carbonate to silica, and the later constructive diagenetic alterations were almost ineffective. The distribution of syndiagenetic silicification during syndiagenetic stage gradually decreases from the platform‐interior to the platform‐margin. The second‐stage and third‐stage quartz cements, derived from two‐stage hydrothermal silicification in the middle stage, are both destructive for reservoir preservation. This study, combined with coeval vapour–liquid inclusions Th data and thermal‐burial models, constrains the time of the second‐stage quartz to ca. 403–408 Ma, suggesting an hydrothermal silicification related to the Caledonian movement. The time of the third‐stage quartz cement is constrained to ca. 259.4 Ma, associated with Late Permian eruption of Emeishan flood basalts. [ABSTRACT FROM AUTHOR]

The pore‐throat structure and fluid mobility are the key factors of tight sandstone reservoir classification and evaluation. Taking the Jurassic Shaximiao Formation tight sandstone reservoir in Central Sichuan Basin as an example, 19 samples were analysed by casting thin sections, scanning electron microscopy, high‐pressure mercury injection and nuclear magnetic resonance to clarify the pore‐throat structure, the fluid motility and its controlling factors. The results show that the pore type of Shaximiao Formation tight sandstone reservoir consist of intergranular pores, dissolved pores and a few microfractures. Based on the feature of capillary pressure curve, the pore‐throat structure was classified into three types, corresponding to different movable fluid characteristics. The Type I has large pore and throat radius, good pore‐throat connectivity, small fractal dimension, weak reservoir heterogeneity and strong fluid motility. The distribution range of pore‐throat radius is mainly from 0.3 to 1.1 μm and the average movable fluid porosity (MFP) and movable fluid saturation (MFS) are 6.04% and 49.93%. The Type II has poor pore‐throat sorting, weak fluid motility and the distribution range of pore‐throat radius is 0.01–0.03 μm and 0.2–0.8 μm. The average MFP and MFS of Type II are 1.13% and 14.3%. The Type III has the smallest pore‐throat radius and the largest fractal dimension, corresponding to the most complex pore‐throat structure, which lead to the worst fluid mobility. The average MFP and MFS are 0.49% and 12.76%. The fluid mobility of the tight sandstone reservoir is affected by physical properties and pore‐throat structure. The reservoirs with large pore‐throat size, good connectivity between pore and throat, and low heterogeneity have higher MFP and saturation. Moreover, the mineral compositions have different effects on fluid mobility of the tight sandstone. The feldspar positively affects fluid mobility, while the clay minerals negatively affect fluid mobility. [ABSTRACT FROM AUTHOR]

On the basis of the core description, thin sections, and geochemistry data, we characterized the Lower Silurian Longmaxi marine shale in the Changning area in the south Sichuan Basin. Ten lithofacies were identified in the Lower Silurian Longmaxi marine shale: (a) massive silty shale (Lithofacies A); (b) laminated siliceous calcareous shale (Lithofacies B); (c) calcareous shale (Lithofacies C); (d) silty dolomitic shale (Lithofacies D); (e) argillaceous siltstone (Lithofacies E); (f) siltstone (Lithofacies F); (g) laminated silty shale (Lithofacies G); (h) silty calcareous shale (Lithofacies H); (i) argillaceous lime shale (marl) (Lithofacies I); and (j) bentonite (Lithofacies J). Obvious heterogeneity occurred in different lithofacies in terms of mineralogy, total organic carbon (TOC) content, porosity, permeability, pore surface area, total pore volume, and total gas content. Among these lithofacies, Lithofacies B has the highest porosity (5.4%), pore surface area (12.79 m2/g), total pore volume (0.015 cc/g), TOC content (4.37%), total gas content (3.4 m3/ton), and relatively high brittle minerals, suggesting great shale gas potential. Lithofacies A, C, and D have a relatively high brittle minerals, porosity, pore surface area, total pore volume, TOC content, and total gas content, which means that these 3 lithofacies show relatively good potential for shale gas. The rest of the lithofacies have low brittle minerals content, porosity, pore surface area, total pore volume, TOC content, and total gas content, representing poor shale gas potential. [ABSTRACT FROM AUTHOR]