Fluid–Solid Coupling Simulation and Field Flow Response of Separate-Layer Fracturing in Vertically Heterogeneous Thick Shale: Insights from the Qiongzhusi Formation

The Qiongzhusi Formation, a thick and vertically heterogeneous marine shale sequence in southern China, presents substantial obstacles to efficient hydraulic stimulation when conventional horizontal-well staged fracturing is applied, owing to marked interlayer contrasts in mineralogy, rock mechanics, and natural fracture intensity. To address this challenge, this study develops an integrated methodological framework that combines a comprehensive fracability index (IFI) with discrete-element-based fluid–solid coupling simulations, aimed at elucidating fluid-driven fracture propagation behaviors and their corresponding flow performance under separate-layer fracturing conditions. Using Well Z202 as a field case, the IFI is first constructed by incorporating mineral composition, mechanical properties, and natural fracture attributes to quantitatively rank the stimulability of individual layers. Subsequently, a discrete element hydraulic fracturing model is established, which explicitly resolves the transient fluid flow within fracture networks, the pressure-dependent initiation and extension of tensile fractures, and the dynamic evolution of fracture aperture and permeability in response to varying injection rates and fluid viscosities. The simulations reveal that fracture network geometry—and hence the effective fluid-flow pathway—is governed by a tripartite interplay: brittle mineral content dictates the locus of initial fracture opening, natural fracture density and orientation control fluid diversion and network interconnectivity, and the in situ stress state modulates fracture complexity and vertical growth potential. Critically, the results demonstrate that high-angle natural fractures substantially enhance vertical fluid connectivity, with a single perforation cluster generating a stimulated fracture height of up to 23.7 m, a finding corroborated by post-fracturing temperature logging. The modeled fracture heights align closely with field-observed production contributions: lower perforation clusters, which develop greater fracture half-heights, account for 4.0–4.6% of gas production, whereas upper clusters contribute only 1.4–2.9%, confirming the dominant influence of downward fluid-driven fracture propagation. Overall, the proposed workflow—integrating quantitative fracability evaluation, fluid–solid coupled numerical simulation, and field flow-data validation—offers a robust theoretical foundation for optimizing separate-layer fracturing design, with direct implications for injection strategy, fracture conductivity maintenance, and long-term productivity forecasting in thick shale reservoirs.