To solve engineering problems in the production process after fracturing and flooding of low-permeability sandstone reservoirs, such as rapid water-cut rise and low water flooding efficiency, a method for optimizing the fracture parameters of low-permeability sandstone reservoirs under fracturing flooding conditions was proposed. A rock property test experiment was first carried out, the fracturing coefficient was defined, and an evaluation method for the brittleness index of low-permeability sandstone was established to optimize the perforation location of the fracturing reservoir. A productivity numerical model for the two-phase flow of oil–water in matrix–fracture media was established to optimize the fracture morphology under fracturing flooding conditions. The results showed that the quartz content, Young’s modulus, and peak stress mainly affected the fracturing coefficient of rock and are the key indicators for evaluating the brittleness of low-permeability sandstone reservoirs. For production wells in the direction of minimum horizontal principal stress, the swept area of water flooding should be expanded, fracture length should be optimized to 90 m, and fracture conductivity should be 20 D·cm. For fracturing production wells in the direction of maximum horizontal principal stress, the advancing speed of the water injection front should be slowed down to reduce the risk of water channeling in injection-production wells. The optimized fracture length was 80 m, and the fracture conductivity was 25 D·cm. The application of these findings can markedly improve oil production and provide a reference for optimizing the fracture parameters of low-permeability sandstone reservoirs under fracturing flooding conditions.

Due to factors such as low porosity and permeability, thin sand body thickness, and strong interlayer heterogeneity, the fluid flow in the tight reservoir (beach-bar sandstone reservoir) exhibits obvious nonlinear seepage characteristics. Considering the time-varying physical parameters of different types of sand bodies, a nonlinear seepage coefficient is derived based on permeability and capillary force, and a low-velocity nonlinear seepage model for beach bar sand reservoirs is established. Based on core displacement experiments of different types of sand bodies, the low-velocity nonlinear seepage coefficient was fitted and numerical simulation of low-velocity nonlinear seepage in beach-bar sandstone reservoirs was carried out. The research results show that the displacement pressure and flow rate of low-permeability tight reservoirs exhibit a significant nonlinear relationship. The lower the permeability and the smaller the displacement pressure, the more significant the nonlinear seepage characteristics. Compared to the bar sand reservoir, the water injection pressure in the tight reservoir of the beach sand is higher. In the nonlinear seepage model, the bottom hole pressure of the water injection well increases by 10.56% compared to the linear model, indicating that water injection is more difficult in the beach sand reservoir. Compared to matrix type beach sand reservoirs, natural fractures can effectively reduce the impact of fluid nonlinear seepage characteristics on the injection and production process of beach sand reservoirs. Based on the nonlinear seepage characteristics, the beach-bar sandstone reservoir can be divided into four flow zones during the injection production process, including linear seepage zone, nonlinear seepage zone, non-flow zone affected by pressure, and non-flow zone not affected by pressure. The research results can effectively guide the development of beach-bar sandstone reservoirs, reduce the impact of low-speed nonlinear seepage, and enhance oil recovery.

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.

The Cambrian Qiongzhusi Formation shale of the Sichuan Basin, buried below 4000 m, is a key deep-shale-gas target whose hydraulic fracturing is jointly controlled by bedding weak planes and high in situ stress. This study separates the two controls quantitatively and establishes a reproducible criterion for selecting favourable bedding attitudes and scaling treatment energy. A fluid–solid coupled discrete-element model was built on PFC2D, combining parallel-bond matrix contacts, smooth-joint bedding planes installed on a discrete fracture network, servo-controlled stress boundaries and a cubic-law fluid network, with micromechanical parameters calibrated against a triaxial test on a core from a 4601.76 m depth. Seven bedding inclinations (0–90°) were simulated under a unified stress state, and nine stress combinations were arranged in a 3 × 3 orthogonal design of basal horizontal stress (88.1–125 MPa) and vertical–horizontal stress difference (0.1–6 MPa) at a fixed 60° bedding, then analysed by quadratic response surface and two-way ANOVA. The peak fracturing pressure follows a U-shaped relation with bedding inclination spanning 110–160 MPa. Low-angle bedding (0–30°) favours lateral extension (ratios: 0.63–0.68) but limits vertical connectivity, whereas high-angle bedding (75–90°) promotes vertical breakthrough with lateral reach falling to 0.08–0.09. Ranked by a composite stimulation score built from four normalised sub-scores—initiation efficiency, lateral reach, vertical reach and an SRV proxy—60° is the optimum (S = 0.76), ahead of 15° (0.72) and 45° (0.67), combining the lowest fracturing pressure of 110 MPa with progressive branching rather than sudden breakthrough. Raising basal σh from 88.1 to 125 MPa lengthens propagation approximately fourfold and shifts the failure mode from tensile splitting to shear–tensile ductile rupture, with the tensile-fracture proportion falling from 1.0 to 0.25–0.35. The two-way ANOVA attributes 82–99% of the variance of every response to σh (p ≤ 0.031), whereas the stress difference contributes at most 8.2% and reaches significance for none (p > 0.17) The bedding optimum is placed on a stated objective function rather than qualitative judgement, and the two stress controls are shown to combine additively rather than multiplicatively within the Qiongzhusi stress envelope. Practically, treatment energy should be scaled with basal σ_h rather than with the stress difference, and target intervals selected at 45–60° bedding.