The pore structure of shale plays key role in oil and gas storage capacity and accumulation. Twelve representative samples were selected from Triassic Yanchang Formation in the Ordos Basin and Silurian Longmaxi Formation in the Sichuan Basin with different ages, depositional settings, and maturities to analyze shale pore structure using focused ion beam-scanning electron microscopy and high-pressure mercury intrusion capillary porosimetry. The results show that the pores of lacustrine shale with maturity Ro < 1.3% from the Triassic Yanchang Formation were predominantly composed of pores with pore throat diameter of larger than 30 µm. The pores of marine shale with maturity Ro > 1.3% from the Silurian Longmaxi Formation were predominantly composed of pores with pore throat diameter of smaller than 100 nm. For the porosity, the average porosity of low-mature lacustrine shale is 2.4%, while the average porosity of high-mature marine shale is 1.5%. For the pore type, intergranular inorganic pores predominantly occurred between mineral particles in the lacustrine shale, while the marine shale mainly developed organic pores with pore throat diameters ranging from 5 to 200 nm. Compared to the low-mature lacustrine shale, macropores of high-mature marine shale are less developed and micropores dominant. Importantly, brittle minerals (quartz, feldspar, and carbonate minerals) mainly affect the pore structure of lacustrine shale, while organic matter mainly affects the pore structure of marine shale.

Shale gas desorption and loss is a serious and common phenomenon in the Sichuan Basin. The characteristics, capability, and origin of shale gas desorption are significant for understanding the shale gas reservoir accumulation mechanism and guiding shale gas exploration. The shale gas of the Longmaxi Formation in the southeastern Sichuan Basin was studied based on a shale gas desorption simulation experiment, combined with mineral composition, total organic carbon, specific surface area, isothermal adsorption, and scanning electron microscope (SEM) data. Here, the shale gas desorption capability was quantitatively evaluated, and its controlling factors are discussed. The results show that the shale gas desorption process within the Longmaxi Formation varies significantly. The total time of the desorption process varies from 600 min to 4400 min, and it mainly occurs by the 98 °C desorption stage. The desorption capability of the lower Formation is markedly weaker than that of the upper Formation, and it is mainly determined by the shale properties. Organic matter (OM) is the most important controlling factor. As the OM content increases, the specific surface area, methane adsorption capacity, and OM pores increase, leading to a rapid decrease in shale gas desorption capability. In addition, feldspar exhibits a positive correlation with shale gas desorption capability due to its large pores but low specific surface area.

To understand the characteristics of variation in porosity and permeability, the physical properties of the shale reservoir under different stress conditions play an important role in guiding shale gas production. With the shale of the Wufeng-Longmaxi Formation in the south of the Sichuan Basin as the research object, stress-dependent porosity and permeability test, high-pressure mercury injection, and scanning electron microscope test were performed in this study to thoroughly analyze the variation in physical properties of different shale lithofacies with effective stress. Besides, the stress sensitivity of different lithofacies reservoirs was evaluated by using parameters such as pore compressibility coefficient (PCC) and porosity sensitivity exponent (PSE), while the optimized support vector machine (SVM) algorithm was adopted to predict the coefficient of reservoir porosity sensitivity. According to the research results, the porosity and permeability of shale reservoirs decline as a negative exponential function. When the effective stress falls below 15 MPa, the damage rate of permeability/porosity increases rapidly with the rise of effective stress. By contrast, the permeability curvature of the shale reservoirs plunges with the rise of effective stress. It was discovered that a higher siliceous content results in a higher permeability curvature of shale, indicating the greater stress sensitivity of the reservoir. The ratio of matrix porosity to microfracture porosity determines the PSE, which is relatively low, and low aspect ratio pores contribute to high porosity compressibility and stress sensitivity. Young's modulus shows a negative correlation with pore compressibility and a positive correlation with Poisson's ratio. High clay minerals have a large number of low aspect ratio pores and a low elastic modulus, which leads to both high PCC and low PSE. Based on the principal component analysis, a multiclassification SVM model was established to predict the PSE, revealing that the accuracy of the sigmoid, radial basis function (RBF), and linear kernel function is consistently above 70%. According to error analysis, the accuracy can exceed 80% with the RBF kernel function and appropriate penalty factor. The research results serve to advance the research on the parameters related to overburden pressure, porosity, and permeability. Moreover, the optimized SVM algorithm is applied to make a classification prediction, which provides a reference for shale reservoir exploration and development both in theory and practice.

The degree of organic matter (OM) enrichment in shale determines its oil and gas potential. To understand the factors controlling this OM enrichment, we have used petrological and geochemical analyses to study the Lower Cambrian Niutitang Formation Shale in the eastern shelf margin of the Yangtze Block. Our results reveal that the total organic carbon (TOC) content of the Niutitang Formation Shale varies significantly throughout the vertical section. The lower part of the Niutitang Formation has a high TOC content, likely due to its formation in a dysoxic/anoxic environment with intense upwelling that favored OM enrichment. The middle part of the Niutitang Formation has the highest TOC content, which can be attributed to its formation in an environment with more hydrothermal activity, moderately upwelling, high paleosalinity, dysoxic/anoxic conditions, and moderately restricted water contents. Finally, the upper part of the Niutitang Formation records the lowest TOC contents because it likely formed in an oxic to dysoxic environment with weakly restricted hydrographic conditions that did not favor the preservation of OM. Therefore, these data demonstrate that the factors controlling OM enrichment in the Niutitang Formation Shale on the shelf margin include intense upwelling, greater amounts of hydrothermal activity, high paleosalinity, dysoxic/anoxic conditions, and moderately restricted water contents.