Characterization of shale reservoir heterogeneity under different pressure coefficients based on NMR and multi-fractal analysis, Sichuan Basin, SW China

This study employs nuclear magnetic resonance (NMR) technology and multifractal theory to quantitatively assess the heterogeneity of pore structures in six groups of deep shale samples from the Sichuan Basin. The samples have depths ranging from 3602 to 5955 m and pressure coefficients from 0.75 to 1.90. The results indicate that mineral composition, fluid type, and formation pressure coefficients are the primary factors controlling pore heterogeneity.Samples with high clay content exhibit the greatest heterogeneity in the dry state (Δα = 0.88–0.99). After water saturation, the contribution of small pores to heterogeneity increases significantly, with Dmin-D0 rising by over 40%. In contrast, carbonate mineral cementation reduces shale heterogeneity, as evidenced by a strong negative correlation between saturated ΔD and carbonate content (r = −0.91).The type of saturating fluid also affects heterogeneity. Saturated water generally enhances pore structure heterogeneity, leading to a significant increase in ΔD. The influence of crude oil is modulated by wettability: hydrophobic shale samples show higher Δα under saturated oil conditions (0.90–0.97), while hydrophilic samples exhibit lower Δα values in the same state.Formation pressure plays a critical role in heterogeneity development. Under overpressure conditions (pressure coefficient = 1.90), the maintenance of microfracture openings significantly enhances heterogeneity in the saturated oil state, with ΔD showing a strong positive correlation with the pressure coefficient (r = 0.75). Beyond this physical preservation of fracture networks, overpressure may also alter the compressibility and adsorption behavior of crude oil within nanopores, further amplifying pore size distribution complexity and contributing to the stronger ΔD-pressure correlation observed under oil saturation. Conversely, low-pressure conditions (0.75–0.98) promote the closure of pores and microfractures, reducing the contribution of large pores (HC1 series shows D 0 -D max values of only 0.25–0.32).This study reveals the synergistic mechanisms of the mineral-fluid-pressure system on shale reservoir heterogeneity, providing a theoretical basis for optimizing development strategies, such as mitigating clay hydration damage and utilizing gas displacement of nanoporosity in high-pressure zones.