The Middle and Upper Permian Dalong and Gufeng Formations in South China have recently been considered as potential gas-producing shales. However, their pore structure characteristics remain poorly understood. To investigate the pore structure and fractal characteristics of the pores in these two formations, a suite of shale samples from the Dalong and Gufeng Formations in the western Hubei Province, South China were analyzed by multiple techniques, namely, TOC content, X-ray diffraction (XRD) mineralogy analysis, optical microscopy observations, major elemental analysis, field emission-scanning electron microscopy (FE-SEM), and low-pressure gas adsorption measurements (N₂ and CO₂). The identified major shale lithofacies include siliceous mudstone, carbonaceous mudstone, argillaceous-siliceous mixed mudstone, and calcareous-siliceous mixed mudstone. SEM images show that the dominant pore types include the pores between brittle minerals, slit-shaped pores between clay sheets, and secondary organic matter (OM) pores within solid bitumen. The pore size distribution is dominated by micropores and mesopores (<30 nm), which are the major contributors to total pore volume and surface area for the Dalong and Gufeng Formations. Based on the Frenkel–Halsey–Hill (FHH) method, fractal dimensions (D₁, D₂) calculated from the nitrogen adsorption data have a range of from 2.489 to 2.772 (D₁) and from 2.658 to 2.963 (D₂), and are higher in the Gufeng Formation (average TOC = 8.3 wt.%) due to a higher TOC content comparing to the Dalong Formation (average TOC = 6.2 wt.%). The pore development and fractal characteristics are primarily controlled by organic matter (OM), carbonate minerals, and clay minerals for both the Dalong and Gufeng Formations. Shale samples with high TOC content, low carbonate content, and high clay content tend to develop more heterogeneous micropores and mesopores, which is ascribed to the generation of clay-related and OM-hosted pores, along with the destruction of primary pores by pore-filling carbonate cements.

This study investigates the reservoir properties and source–reservoir system types of the Upper Permian Dalong Formation shale in Western Hubei (Middle Yangtze region) through core observations and systematic experiments, including total organic carbon (TOC) analysis, X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), low-pressure gas adsorption, and methane isothermal adsorption. The Dalong Formation shale is dominated by organic-rich siliceous facies, with average quartz and TOC content of approximately 60% and 6.16%, respectively. Organic matter (OM) pores are the most abundant pore type, and the average porosity is 2.75%. Mesopores account for ~69% of the total pore volume, whereas the specific surface area is mainly controlled by micropores (~60% on average). The mean methane adsorption capacity is 3.53 m³/t, and the TOC content is identified as the primary factor governing both micropore/mesopore development and the adsorption capacity. Based on the lithological assemblages, limestone-to-stratum ratio, and TOC content, four source–reservoir systems are identified: (1) pure shale, (2) laminated shale, (3) source-intercalated reservoir, and (4) reservoir-intercalated source. The pure shale system, developed in deep-water platform basin facies, exhibits the highest reservoir quality (average TOC: 8.29%; pore volume: 32.99 × 10⁻³ cm³/g; specific surface area: 44.16 m²/g; methane adsorption: 4.11 m³/t). In contrast, the reservoir-intercalated source system, occurring in platform margin slope facies, shows the poorest performance (TOC: 3.03%; pore volume: 7.46 × 10⁻³ cm³/g; methane adsorption: 2.72 m³/t), while the laminated shale and source-intercalated reservoir systems yield intermediate values. Accordingly, four distinct shale gas occurrence models are established. The pure shale system is identified as the most favorable exploration target, followed by the laminated shale and source-intercalated reservoir systems. This classification framework offers a practical reference for shale gas evaluation in analogous rift trough marine shale systems.