Fracture Propagation Characteristics and Influencing Factors in Cross-Layer Fracturing of Interlayered Shale Reservoirs

Abstract

Hydraulic-fracture transmission across lithologic interfaces governs fracture-height growth and reservoir connectivity in shale–sandstone interbedded reservoirs, yet the coupled effects of mechanical contrast, interface properties, layer geometry, and operational parameters remain insufficiently quantified. A two-dimensional plane-strain hydraulic-fracturing model was developed in ABAQUS by coupling Biot poroelasticity, cohesive-zone damage, and fracture-fluid flow. The model explicitly represents thin, alternating continental shale–sandstone layers, lithology-dependent in situ stress and stiffness, and cohesive interfaces; its implementation was assessed against the KGD solution and published layered-rock fracture morphologies. Under the simulated conditions, increasing the shale-to-sandstone elastic-modulus ratio from 0.4–0.5 to 0.6–0.8 reduced the number of penetrated layers from eight to six. Increasing tensile strength from 4 to 16 MPa reduced the number of penetrated layers from ten to six and the final fracture length from 32 to 21 m, while increasing the maximum aperture from 6.75 to 9.02 mm. A sandstone interlayer thickness of approximately 3 m marked a transition in the present parameter set rather than a universal threshold. Sandstone-centered perforation and higher injection rates promoted vertical connectivity, whereas very high fluid viscosity increased near-wellbore aperture but restricted long-distance fracture-height growth. These results provide a mechanics-based framework for optimizing perforation placement and stage-specific fluid design in continental interbedded shale reservoirs.