Reservoir Heterogeneity and Vertical Differentiation of the Marine Shales in the Permian Gufeng Formation, Western Hubei, China: Insights from NMR and Micro-CT Analyses

Reservoir effectiveness in marine shales is controlled not only by pore volume but also by pore-fluid occurrence, pore–throat connectivity, and mineral–organic matter coupling. In this study, the Permian Gufeng Formation shales from the Enshi area, western Hubei, South China, were investigated through an integrated analysis of total organic carbon (TOC), X-ray diffraction (XRD)-based mineral composition and lithofacies, low-field nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), micro-computed tomography (Micro-CT), and entropy-weighted technique for order preference by similarity to an ideal solution (TOPSIS) evaluation. The TOC content ranges from 1.60% to 21.38% and shows clear vertical differentiation, with moderate but variable enrichment in the lower interval, reduced organic matter abundance in the middle interval, and pronounced organic enrichment in the upper interval. Mineral compositions demonstrate an upward transition from a mixed siliceous–carbonate system to a dominantly siliceous shale system. NMR results reveal strong heterogeneity in porosity, NMR-derived permeability, T2cutoff, bound-fluid saturation, and free-fluid saturation. Based on saturated and centrifuged T2 spectra, four descriptive reservoir response types were identified: short-T2-dominated micropore-bound response, intermediate-T2-dominated movable-fluid response, long-T2-enriched but low-efficiency response, and NMR-inferred enhanced mobility composite response. SEM observations show diverse pore types, including organic-matter-related pores, dissolution pores, interparticle pores, mineral-edge pores, pyrite intercrystalline pores, and local microfracture-like pores. Micro-CT results indicate that micrometer-scale pore bodies are commonly isolated, demonstrating that pore abundance or pore size alone cannot determine reservoir effectiveness. TOC mainly controls pore generation potential, whereas siliceous minerals, pore–throat connectivity, movable fluid proportion, and local fractures exert stronger controls on effective reservoir development. The most favorable reservoir responses are concentrated in the upper high-organic siliceous shale interval from A33 to A42, with local enhanced responses in A16 and A21. These results provide an integrated framework for evaluating reservoir heterogeneity and favorable intervals in complex marine shale systems.