The ZN Oilfield shale reservoir is characterized by thin sand–shale interbeds, strong lateral and vertical heterogeneity, poor porosity–permeability, low formation pressure coefficient, and low brittleness, which together limit fracture propagation and suppress production after conventional hydraulic fracturing. To overcome these constraints, we propose an intensive-stage, closely spaced volumetric fracturing technology that couples energy-replenishment pressurization with differentiated parameter design. Numerical simulations were used to quantify how injected fluid volume affects the post-fracturing formation pressure coefficient and estimated ultimate recovery (EUR), and to determine economically optimal energy-replenishment scales. Guided by a “dual sweet spot” evaluation (geological + engineering), field designs reduced stage spacing from 80–100 m to 30–50 m and cluster spacing from 10–20 m to 6–10 m, and increased proppant and fluid intensities to ~5.0 t/m and 22.0 m³/m, respectively. Field monitoring and production data show average fracture half-length increased to 193 m, and average initial oil production per well rose from 8.8 t/d to 12.9 t/d (≈46% increase). These results demonstrate that the proposed approach effectively enlarges fracture-controlled reservoir volume, enhances formation energy, and substantially improves single-well performance in low-pressure shale oil systems.

Deep coalbed methane (CBM) resources are abundant and represent a critical component of future energy supply and carbon reduction strategies. However, deep coal seams are characterized by well-developed cleat systems and high Poisson’s ratios, rendering the mechanisms of hydraulic fracture initiation, propagation, and complex fracture network development insufficiently understood. In this study, deep coal rock at a burial depth of 2700 m is investigated. A finite element–based hydraulic fracturing model incorporating complex face-cleat and end-cleat networks is established by explicitly representing cleat geometry, mechanical properties, fluid leak-off behavior, and hydraulic loading conditions. Using this model, the effects of cleat inclination angle, horizontal stress difference, and displacement on fracture evolution are systematically analyzed. The results indicate that when face cleats are orthogonal to the maximum horizontal principal stress, fractures preferentially penetrate cleats and propagate along the maximum stress direction. In contrast, when face cleats form acute angles with the maximum horizontal stress, pronounced branching fractures develop along both face and end cleats, with propagation increasingly dominated by face cleats as the angle decreases. Increasing horizontal stress difference suppresses fracture branching, leading to simpler fracture networks but greater total fracture length and maximum fracture width. Moreover, under identical injection pressures, the equal-pressure fracture length increases, indicating enhanced fracture propagation capacity. With increasing displacement, fracture networks evolve from simple to complex patterns, accompanied by accelerated propagation and enlarged fracture widths; however, excessive displacement intensifies fluid leak-off, ultimately reducing the equal-pressure fracture length.