Tight sandstone gas reservoirs are rich in reserves and are an important part of unconventional oil and gas resources. However, natural fractures’ impact on hydraulic fracture propagation behavior and network formation mechanisms remain unclear. Exploring how to optimize fracturing parameters to maximize post-fracturing productivity requires further investigation. Therefore, this study focused on the characteristics of tight sandstone gas reservoirs and established a three-dimensional numerical simulation model for hydraulic fracture propagation and post-fracturing productivity using production history matching to validate the reliability of the model. Based on this model, this study investigated the influence mechanisms of natural fracture angles, density, and lengths on hydraulic fracture propagation behavior and network formation. The spatial distribution of hydraulic fracture widths in three dimensions is also explored. When natural fracture angles are lower, a greater number of natural fractures are activated, leading to more developed secondary hydraulic fractures and the formation of complex fracture networks. Hydraulic fractures tend to penetrate directly through high-angle natural fractures. Single-well cumulative gas production increases initially with increasing natural fracture angles, then decreases, but increases with higher natural fracture density and length. Optimal fracturing in areas with longer natural fractures, lower angles, and higher density distribution enhances single-well productivity effectively.

Frequent wellbore loss incidents in the Mesozoic reservoirs of the Zhengning oilfield in the Ordos Basin, China, have severely impacted the development of tight oil and gas reservoirs in the basin. This study analyzed the mineral composition, microstructure, natural fracture distribution, and hydration–dispersion characteristics of rocks in the loss-prone intervals of the Mesozoic reservoirs using a laboratory experimental system. The effects of natural fractures and drilling fluid immersion on the mechanical properties and failure behavior of the rocks were investigated, and the wellbore loss mechanisms in the Mesozoic reservoirs of the Zhengning oilfield were comprehensively analyzed. Experimental results show that the reservoir rocks in the loss-prone intervals are widely distributed, with natural fractures having a width of 0.2–0.3 mm, and the clay mineral content is generally above 40%. When the relative content of illite/smectite interstratification exceeds 80%, the rock exhibits strong hydration–dispersion behavior, with a thermal recovery rate of less than 85%. Drilling fluid immersion causes the rock mass to become unstable. The presence of natural fractures and the hydration–dispersion effect significantly weaken the strength of the surrounding rock mass, leading to enhanced rock plasticity. During drilling, the expansion and interconnection of natural fractures, combined with the hydration–dispersion effect, are the main causes of wellbore loss incidents. Our study clarifies the mechanisms underlying wellbore loss incidents in the Zhengning oilfield and provides reliable experimental evidence for preventing such incidents in this area.

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.

Bedding planes widely exist in stratified reservoirs and strongly restrict the vertical cross-layer growth of hydraulic fractures. Traditional displacement discontinuity method (DDM) tends to produce spurious negative apertures for compressed weak bedding interfaces and neglects multi-cluster stress superposition in inclined formations. This work proposes an improved DDM incorporating bedding-plane normal-tangential support-stiffness contact constraints together with Mohr–Coulomb-based opening-slip-closure discrimination, which removes non-physical negative-aperture artifacts of closed weak interfaces. The proposed numerical framework is adopted to model fracture initiation, propagation and bedding-interface penetration under multi-fracture interference. Key coupled influences of net pressure, bedding-plane dip angle and fracture-cluster number are quantitatively investigated. Numerical simulations reveal that higher net pressure enhances the lasting cross-layer propagation capacity of hydraulic fractures. Among the examined cases, a bedding dip angle of 60° facilitates fracture penetration through interfaces. Bedding features amplify inter-cluster mechanical interference and lead to asymmetric fracture evolution, tip arrest and interface-parallel fracture propagation, which becomes more pronounced as the number of fracture clusters increases. This study provides theoretical references for multi-cluster fracturing design in low-permeability layered reservoirs.