During the hydraulic-fracturing process, stress interference occurs among multiple wells and fractures, potentially affecting the trajectory of hydraulic fracture propagation. Previous studies have largely overlooked the influence of proppant support stresses on the trajectories of fracture propagation. This paper establishes a mathematical model, grounded in the boundary element method, designed to compute the propagation of multiple fractures, considering both proppant support on the fracture surface and dynamic perturbations within the local stress field. The findings of this research reveal that the stress field induced by hydraulic fracturing exhibits dynamic evolution characteristics, necessitating a comprehensive study of the fracture initiation and extension across the entire fracturing time domain. The effect of the residual fracture width under proppant action on the in situ stress field cannot be ignored. During simultaneous fracturing, hydraulic fractures are inclined to propagate in the direction of the maximum horizontal principal stress, particularly as the in situ differential stress escalates. Staggered fracturing between wells has been proven to be more effective than head-to-head fracturing. Simply increasing the well spacing cannot solve the problem of inter-well fracture interference. In zipper fracturing, adjusting the fracturing sequence can inhibit the fracture intersections between wells, thereby controlling the trajectory of fracture propagation. The aforementioned research has considerable significance in guiding the control of fracture morphology during hydraulic-fracturing processes.

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.

Hydrogels used for fracture sealing during heavy-oil thermal recovery are repeatedly exposed to high-temperature steam, dehydration, pressure disturbance, and cooling, conditions that often lead to progressive network deterioration and loss of sealing efficiency. To address this limitation, a thermally triggered self-reinforcing covalent–physical double-network nanocomposite hydrogel was developed by combining a sparse MBAA-crosslinked P(NaAMPS-co-NVP-co-AM) covalent scaffold with a reversible Laponite-mediated physical network. The material response was systematically evaluated through cyclic hydrothermal treatment at 180 °C, while fracture-sealing and resealing performance was examined separately under steam-exposure conditions. Artifact-controlled experiments were further introduced to distinguish genuine cycle-induced reinforcement from dehydration, continued post-curing, and conventional thermal aging. The results show that the NaAMPS/NVP/AM molar ratio of 40/20/40 with 1.00 wt% Laponite provided a suitable balance between precursor processability, hydrothermal stability, and mature network stiffness. After five thermal cycles at 180 °C, the storage modulus of the Lap-DN hydrogel increased from 74.4 to 89.1 kPa, while the compressive stress at 50% strain increased from 0.641 to 0.842 MPa, corresponding to reinforcement ratios of 1.198 and 1.314, respectively. Meanwhile, the mean equivalent pore diameter decreased from 6.2 to 4.8 μm, indicating progressive refinement of the load-bearing network. The hydrogel retained 76.3% of its initial water and 81.6% of its initial volume after five cycles in the reference brine and preserved a cycle-5 modulus retention of 101.3% even at 150,000 mg/L salinity. In fracture-sealing tests, Lap-DN sustained a breakthrough pressure of 3.47 MPa and reduced fracture conductivity by 92.4% in a 1.60 mm fracture. More importantly, the same sealing body maintained a breakthrough pressure of 4.55 MPa after five steam impact–recovery cycles in a 1.20 mm fracture, corresponding to 106.1% of the first-cycle value, while 95.0% of the pre-breakthrough pressure resistance was restored within 30 min of cooling. These results are consistent with a cycle-induced reorganization of the Laponite-mediated physical constraints within the permanent covalent scaffold, although the transient dissociation and reassociation of individual polymer–Laponite junctions were not directly observed. Within this evidence-based interpretation, cyclic thermal perturbation is associated with mechanical reinforcement and repeated fracture resealing rather than acting solely as a damaging factor. This work provides a materials-design strategy for hydrogel sealing systems operating under cyclic steam and high-salinity conditions.