In order to find out the enrichment mechanism and forming type of deep shale gas, taking the Longmaxi Formation shale in the Desheng–Yunjin Syncline area of Sichuan Basin as an example, we determined the mineralogy, organic geochemistry, physical property analysis, gas and water content, and the influence of three factors, namely sedimentation, structural conditions, and hydrogeological conditions, on the enrichment of shale gas. The results show that Longmaxi Formation shale in Desheng–Yunjin Syncline area is a good hydrocarbon source rock that is in the over-mature stage and has the characteristics of high porosity, low permeability, and high-water saturation. The contents of clay and quartz are high, and the brittleness index is quite different. According to the mineral composition, nine types of lithofacies can be found. The development characteristics of Longmaxi Formation shale and the sealing property of the roof have no obvious influence on the enrichment of shale gas, but the tectonic activities and hydrodynamic conditions have obvious influence on the enrichment of shale gas. The main control factors for shale gas enrichment in different regions are different. According to the main control factors, the gas accumulation in the study area can be divided into three types: fault-controlled gas, anticline-controlled gas, and hydrodynamic-controlled gas. The fault-controlled gas type is distributed in the north of the Desheng syncline and the north of the Yunjin syncline, the anticline-controlled gas type is distributed in the south of the Desheng syncline and the south of the Yunjin syncline, and the hydrodynamic-controlled gas type is distributed in the middle of the Baozang syncline. This result is of great significance for deep shale gas exploration.

The migration phenomenon of deep shale gas is a subject that has yet to be fully comprehended, specifically regarding the migration ability of deep shale gas. This study focuses on the Longmaxi Formation in the southern Sichuan Basin, utilizing it as an example. Various experimental techniques, such as temperature-driven nitrogen and carbon dioxide adsorption, high-pressure mercury intrusion, XRD, and TOC analysis, are employed. The goal is to analyze the pore structure and fractal characteristics of the Longmaxi Formation shale. Additionally, the study aims to calculate its Knudsen number based on parameters like temperature gradient and pressure coefficient. The migration ability of the Longmaxi Formation shale in southern Sichuan Basin is also discussed. The results show the following: (1) The pore volume distribution of the Longmaxi Formation shale in the study area ranges from 0.0131 to 0.0364 cm³/g. Mesopores contribute approximately 56% of the pore volume, followed by micropores with a contribution rate of about 26%, and macropores contributing approximately 18%. Additionally, the Longmaxi Formation shale exhibits strong heterogeneity, with the fractal dimension (D1) of mesopores ranging from 2.452 to 2.8548, with an average of 2.6833, and the fractal dimension (D2) of macropores ranging from 2.9626 to 2.9786, averaging 2.9707. (2) The fractal dimensions of shale were significantly influenced by organic matter, inorganic minerals, and pore structure parameters. D1 and D2 were positively correlated with TOC, clay mineral content, and specific surface area, while exhibiting negative correlation with quartz. However, the correlations with calcite content, pore volume, and average pore size were not significant. (3) The proportion of pores satisfying Darcy flow in the Longmaxi Formation shale was approximately 3.7%–11.8%, with an average of 6.6%. Consequently, the migration capability of shale gas can be calculated using Darcy’s law. Furthermore, the migration capability of shale gas is controlled by D2, specifically the surface area, and the connectivity of macropores.

The enrichment of organic matter in high-quality marine shale is generally controlled by factors such as the redox conditions of sedimentary environments, productivity levels, terrigenous input, and ancient productivity. However, the controlling effect of the sedimentary environment on organic matter enrichment in intracratonic sag is still unclear. This study takes samples from the Qiongzhusi formation shale in southern Sichuan Basin as the research object, focusing on trace elements as well as rare earth elements in different stratigraphic intervals. The provenance of the Qiongzhusi formation shale is mainly terrigenous, with sediment sources mainly consisting of sedimentary rocks and granites. The primary sedimentary environment transitions from a continental margin setting, influenced by rift-related tectonic activity and sediment influx from adjacent landmasses, to an open oceanic environment characterized by mid-ocean ridge processes and oceanic plate subduction zones. During sedimentation, saline water was present, with predominant sedimentary environments ranging from shallow water to deep water continental shelves. The shale in the study area is characterized by a higher content of silicates and a lower content of carbonate minerals. Its siliceous sources are mainly influenced by biogenic and terrigenous debris, indicating higher ancient primary productivity and representing a favorable target for shale gas exploration.

Accurately predicting the genesis and distribution of reservoir pressure is essential for comprehending the distribution of oil and gas reservoirs while mitigating drilling risks. In the Qiongzhusi Formation of the Sichuan Basin, overpressure has developed, leading to high production levels in several wells. However, the distribution and causal mechanism of overpressure within the Qiongzhusi Formation remain unclear at present. This study utilizes logging data from representative drilling wells to identify the causes of overpressure in the Qiongzhusi Formation and predict the characteristics of pressure distribution. The results indicate that the pressure coefficient of the Qiongzhusi Formation ranges from 1.01 to 2.05 and increases with burial depth. The overpressure in the Qiongzhusi Formation is attributed to fluid expansion, disequilibrium compaction, and pressure transmission. The contribution of disequilibrium compaction to pressure is 9.44 MPa, while hydrocarbon generation from organic matter contributes 82.66 MPa, and pressure transmission contributes 37.98 MPa. Additionally, the uplift erosion unloading effect and geothermal decline result in pressure reductions of approximately 26.68 MPa and 56.56 MPa, respectively. This study systematically elucidates the causes and distribution of overpressure in the Qiongzhusi Formation, providing valuable insights for subsequent exploration and development of shale gas in this formation.