Marine–continental transitional shale is one of the most promising targets for shale gas exploration in the Lower Yangtze region. To investigate the sedimentary environments and the regularity of the enrichment of the Longtan shale, multiple techniques including core and thin-section observations, geochemical and elemental analyses, X-ray diffraction, scanning electron microscopy (SEM), and low-pressure nitrogen adsorption (LPNA) were used to analyze the sedimentology, mineralogy, and pore structure of the Longtan shale. The core descriptions and thin-section observations showed that the Longtan shale was deposited in marine–delta transitional environments including delta-front, shore swamp, mixed tidal flat and shallow shelf environments. The Sr/Cu, V/Cr, CIA, EF (Mo), EF (U), and other major and trace element results indicated warm and moist climates and water-reducing conditions in the Longtan period. Both the climate and water conditions were favorable for organic matter production and preservation. The geochemical results showed that the Longtan shale was in the overmature stage (Ro values ranging from 2.4% to 3.57%) and that the average total organic carbon (TOC) content was 5.76%. The pore system of the Longtan shale consisted of inorganic pores with a small number of organic pores and microfractures. The porosity and specific surface area were mainly affected by the TOC and clay mineral contents. An effective combination of brittle mineral particles, organic matter, and clay minerals provided the necessary conditions for pore preservation. The organic pores, intergranular pores in clay minerals, and brittle mineral pores formed the main network system for the Longtan shale. In summary, the lithological combinations, organic geochemistry, and pore structure system were all affected by the sedimentary environments.

The pore evolution characteristics of organic-rich shale under semiclosed and open-system conditions were investigated through a pyrolysis simulation experiment conducted on marine low-maturity shale. The results show that the experimental samples of the two systems mainly developed organic pores, clay mineral intergranular pores, and brittle mineral dissolution pores during the evolution process. The shale porosity showed a non-linear growth trend with the thermal maturity increase. However, the porosity increase rate of the semiclosed system was higher than that of the open system. The pore structure characterization parameters of the experimental samples under the two systems were quite different. The samples of the semiclosed system developed wedge- or V-shaped pores with a diameter of several tens of nanometers, while those of the open system developed more small throats with a diameter of several nanometers to ink bottle-type and closed pores of tens of nanometers. For the marine organic-rich shale, the organic matter (OM) evolution was mainly affected by the formation pressure. In summary, a semiclosed system with a higher formation pressure is more conducive to the development of organic pores and the pore structure than an open system with a lower formation pressure. The best stage of pore evolution and development is the overmature stage.

The physics of how organic pores change under high thermal evolution conditions in overmature marine shale gas formations remains unclear. In this study, systematic analyses at the macro- to micro-scales were performed to reveal the effects of the sealing capacity on organic pore development. Pyrolysis experiments were conducted in semi-closed and open systems which provided solid evidence demonstrating the importance of the sealing capacity. Low-maturity marine shale samples from the Dalong Formation were used in the pyrolysis experiments, which were conducted at 350 °C, 400 °C, 450 °C, 500 °C, 550 °C, and 600 °C. The pore characteristics and geochemical parameters of the samples were examined after each thermal simulation stage. The results showed that the TOC of the semi-closed system decreased gradually, while the TOC of the open system decreased sharply at 350 °C and exhibited almost no change thereafter. The maximum porosity, specific surface area, and pore volume of the semi-closed system (10.35%, 2.99 m²/g, and 0.0153 cm³/g) were larger than those of the open system (3.87%, 1.97 m²/g, and 0.0059 cm³/g). In addition, when the temperature was 600 °C, the pore diameter distribution in the open system was 0.001–0.1 μm, while the pore diameter distribution in the semi-closed system was 0.001–10 μm. The pore volumes of the macropores and mesopores in the semi-closed system remained larger than those in the open system. The pore volumes of the micropores in the semi-closed and open systems were similar. The pyrolysis results indicated that (1) the pressure difference caused by the sealing capacity controls organic pore development; (2) organic pores developed in the semi-closed system, and the differences between the two systems mainly occurred in the overmature stage; and (3) the differences were caused by changes in the macropore and mesopore volumes, not the micropore volume. It was concluded that the sealing capacity is the key factor for gas pore generation in the overmature stage of marine shale gas reservoirs when the organic matter (OM) type, volume, and thermal evolution degree are all similar. The macropores and mesopores are easily affected by the sealing conditions, but the micropores are not. Finally, the pyrolysis simulation results were validated with the Longmaxi shale and Qiongzhusi shale properties. The Longmaxi shale is similar to semi-closed system, and the Qiongzhusi shale is similar to open system. Two thermal evolution patterns of organic pore development were proposed based on the pyrolysis results. This study provides new insights into the evolution patterns of organic pores in marine shale gas reservoirs.

The deep formations (burial depth: 3500–4000 m) in the northern Luzhou Block boast favorable geological conditions for shale gas accumulation. However, field development is hindered by the frequent casing deformation of shale gas wells and significant variations in single-well productivity. These issues severely restrict the efficient development of shale gas resources. Existing studies mainly focus on the identification and optimization of geo-engineering dual sweet spots, but few have established a systematic and comprehensive evaluation system from the perspective of engineering risk prevention and control. Based on traditional research on geo-engineering dual sweet spots, this study integrates engineering risk factors. It innovatively establishes a geo-engineering dual sweet spot evaluation system that incorporates engineering risks. Four key evaluation indicators for shale matrix geo-engineering sweet spots are selected: the continuous thickness of a Class I reservoir, the structural location, the fault scale, and natural fracture characteristics. Accordingly, shale matrix geo-engineering sweet spots are classified into three categories: Class I-A Area, Class I-B Area, and Class II Area. Meanwhile, three key indicators affecting fault slip—the angle between fractures and the maximum horizontal in situ stress direction, fracture dip angle, and friction coefficient—are optimized to establish the fault slip risk evaluation criteria. Combined with the distribution characteristics of slip faults, the engineering risks are divided into three levels: high, medium, and low. Finally, by coupling the geo-engineering sweet spots of a shale matrix with engineering risk zones, the geo-engineering sweet spots of shale reservoirs in the study area are classified into four categories (I, II, III, IV).

The geological conditions of shale gas in the deep layers (burial depth of 3500-4000m) of the northern area of Luzhou block are superior, but the shale gas wells in the work area have frequent casing deformation and poor gas well performance. How to scientifically divide the geological-engineering sweet spots of shale gas reservoirs in the work area determines the effective development of the gas field. Starting from the geological-engineering conditions of shale reservoir, this article conducts an analysis of the factors affecting the geological-engineering sweet spots in shale matrix. The research shows that the geological-engineering conditions in the work area are complex, with fault develop showing characteristics of multiple stages, levels, and types. The lower layer of Type I reservoirs has a large continuous thickness (7-18m), excellent reservoir quality, and developed unidirectional and network fractures; The reservoir has high brittleness content, high Young's modulus (3.685~5.004 × 104MPa), low Poisson's ratio (0.195~0.315), and good compressibility of shale; However, the reservoir stress demonstrates complex characteristics such as large differences in horizontal stress, rapid changes in direction, and a strike-slip stress state, which makes faults prone to slippage. Based on a comprehensive analysis of geological conditions, “continuous thickness of type I reservoirs, fault scale, and natural fracture type characteristics” are selected as evaluation indicators, and the work area is divided into three types of geological-engineering sweet spots of the shale matrix: “Zone A of Type I, Zone B of Type I, and Type II”; Based on a comprehensive analysis of fault slip distribution are chosen as the main indicators for evaluating engineering risks, which are divided into high, medium, and low categories; Coupling geological sweet spots of shale matrix geological-engineering sweet spots with engineering risk areas, the geological-engineering sweet spots of shale gas reservoirs in the work area are divided into four categories: I, II, III, and IV.

Deep shale reservoirs in the tectonically complex margin of the southern Sichuan Basin have experienced multistage deformation, resulting in strong spatial heterogeneity of the present-day geostress field. However, the influence of stress heterogeneity on multiscale pore structure evolution and reservoir quality remains poorly constrained. Here, we integrate in-situ stress measurements, overburden porosity and permeability experiments, CO₂/N₂ adsorption, high-pressure mercury intrusion, SEM-MAPS (Scanning Electron Microscopy-MAPS) pore imaging, stress well profile interpretation, and multifractal analysis to quantify the controls of present-day geostress heterogeneity on pore structure evolution in deep Longmaxi Formation shale. The results show that the present-day stress regime is characterized by a strike-slip pattern (σ_H > σ_v > σ_h), with significant variations among different structural deformation zones. Increasing structural deformation results in enhanced differential stress, increasing by 30–80% from gentle structures to tight folds and fault-affected zones, accompanied by a 60–70° rotation of the maximum principal stress orientation. Differential stress, effective stress, differential stress coefficient, and stress structure index exhibit strong negative correlations with porosity, whereas permeability decreases nonlinearly with increasing stress, indicating progressive pore-throat compression and connectivity degradation under heterogeneous stress conditions. Multifractal analysis reveals that pore-size domains exhibit different sensitivities to stress heterogeneity. The macropore fractal dimension (DN3) shows the strongest response, followed by mesopores (DN2), whereas micropores (DN1) exhibit relatively limited variations. Fault-affected zones and strongly deformed regions display higher DN3 values (>2.8), reflecting enhanced complexity of macropore and fracture networks. In contrast, gentle structural zones characterized by curvature values 500 m from faults exhibit relatively low and stable fractal dimensions (<2.73), indicating more homogeneous pore structures. Increasing stress heterogeneity induces the transformation of organic matter pores from regular subcircular shapes to flattened and slit-like morphologies, accompanied by pore-size migration toward smaller scales ( 1.35). These findings reveal that present-day geostress heterogeneity governs shale pore fractal evolution and promotes the transition from micropore-dominated to heterogeneous macropore–fracture systems. This study provides quantitative insights into stress-controlled pore evolution and reservoir quality evaluation in deep shale reservoirs under complex tectonic settings.