Xu Wei, Meng Cai, Cuilong Kong, Dezhao Zhao
Volume fracturing technology critically enhances shale oil recovery by generating complex fracture networks through interactions with shale anisotropy, bedding planes, and natural fractures. However, the spatiotemporal evolution of multiscale fractures under varying in situ stress anisotropy and construction parameters remains poorly understood. This study integrates CT scanning and acoustic emission (AE) monitoring to investigate hydraulic fracture propagation in 300 mm × 300 mm × 300 mm shale samples under controlled geomechanical conditions. Experimental results demonstrate that shale with lower minimum horizontal stress exhibits earlier fracture initiation. Under high stress anisotropy(Δσ ≥ 8MPa), reservoirs with well-developed bedding planes preferentially form vertical fractures due to stress concentration effects. Increasing injection rates from 35 mL/min to 50 mL/min elevated fracture height by 159% (7.1 cm to 18.4 cm), attributed to enhanced fluid pressure and reduced stress concentration at fracture tips. Similarly, high-viscosity fracturing fluids (50 mPa·s) increased fracture height by 52% (7.1 cm to 10.8 cm) compared to low-viscosity fluids (2 mPa·s), effectively mitigating filtration losses. A mixed fluid system (high: low viscosity = 5:5) optimized fracture geometry: high-viscosity fluids extended main fractures to bypass near-wellbore constraints, while low-viscosity fluids activated secondary bedding planes, increasing stimulated reservoir volume by 28%. These findings provide actionable insights for optimizing fracture morphology and construction parameters in bedded shale reservoirs, balancing fracture height, complexity, and stress constraints to maximize recovery efficiency.