Study on the Evolution of Reservoir Conductivity in Inter-Salt Shale under Fluid-Rock Interactions

Abstract

: The inter-salt shale reservoir in the Qianjiang Depression exhibits strong vertical heterogeneity and high oil content, but unlike conventional shales, it is characterized by complex lithology, poor pore connectivity, high plasticity, and pronounced sensitivity. During reservoir hydraulic fracturing, the interaction between injected fluids and the reservoir matrix not only alters fracture surface strength but also induces matrix softening, leading to damage-induced fractures with limited effective duration and rapid decay of fracture conductivity. However, the reservoir adaptability of different injected fluids remains unclear. In this study, triaxial compression tests and a small-scale core fracture conductivity displacement apparatus were employed to measure mechanical parameters and fracture conductivity. From a coupled mechanical–chemical perspective, the evolution of fracture conductivity under varying fluid soaking durations, fluid types, and lithological matrix conditions was investigated. The results indicate that fluid type has a significant impact on the mechanical properties. After soaking in 15 wt% NaCl solution reduced the elastic modulus of argillaceous dolomite by 47.5%, whereas the ethylene glycol–based gel-breaking fluid caused only a 21.2% decrease. Microscopic observations indicated relatively minor microstructural damage in the latter, characterized by localized surface dissolution without evident salt crystallization. Fracture conductivity tests indicate that soaking duration markedly affects conductivity under low closure pressure; at 9 MPa, extending soaking from 12 to 24 h reduced conductivity by 77.3% (from 8.074 D ⋅ cm). However, as closure pressure increases beyond 27 MPa, the conductivity differences induced by different soaking durations gradually diminish, suggesting a transition from fluid-sensitivity-dominated to stress-dominated conductivity loss. Under identical proppant placement, the ethylene glycol–based gel-breaking fracturing fluid caused less reservoir rock damage than supercritical CO 2 and guar-based fluids, resulting in superior fracture conductivity. This study informs the selection of fracturing fluids and provides a reference for enhancing fracture conductivity in inter-salt shale reservoirs.