The intersection behavior of hydraulic fractures and single natural fractures has been studied in detail; however, in fractured reservoirs, natural fractures are numerous and interlaced and the intersection of hydraulic fractures and multiple natural fractures occurs during the fracturing process. This intersection behavior is more complex and there is a lack of research on this topic at present. In this study, a numerical simulation model of the interaction between hydraulic fractures and a series of natural fractures was established, the main factors that affect the formation scale of a fracture network during the hydraulic fracturing of a fractured reservoir were studied using the numerical simulation method, and the parameters were also studied. The results showed that the natural fracture trend, in situ stress difference, and injection flow rate have an impact on the scale of a fracture network. The larger the in situ stress difference, the smaller the scale of the fracture network, which gradually changes from multiple clusters of fractures to single fractures. The larger the injection flow rate, the larger the scale of the fracture network. In the uniform stress field, the direction of a natural fracture is closer to the direction of principal stress, so the lower the fracture extension pressure, the smaller the scale of the network. On the contrary, the farther away from the principal stress direction, the lower the fracture extension pressure and the higher the extension pressure, the larger the scale of the fracture network.

Drilling fluid loss in depleted reservoir has been an import issue faced by further tapping the potential of old oil fields. Accurate evaluation of the fracture pressure is the foundation to avoid mud loss. Traditional views suggest that tensile failure is the only fracture mode and the fracture pressure should be determined by a tensile failure criterion, which are not suitable for wells drilled in the depleted reservoir. In this paper, the analysis focuses on the fracture mode and fracture pressure in depleted reservoir, and case studies show that three fracture modes may first occur, and the fracture mode will be changed with reservoir depletion which highly depends on reservoir depletion degree, well azimuth and deviation angle, and the in situ stress state; different failure criteria at different stages of reservoir depletion should be selected to accurately evaluate the fracture pressure. For the vertical well, fracture pressure is no longer a single linear reduction with reservoir depletion; instead, a three-step and two-step reduction may appear, and for the directional well, the fracture pressure is not always decreased; the other patterns such as increase and first increase then decrease may also appear for the wells drilled in reverse and strike fault stress regimes.

Hydraulic fracture height growth in thin sandstone–mudstone interbeds is often limited by bedding interface failure and multi-cluster stress interference. In this study, a coupled fracture–matrix interface finite element model was developed for the He-8 sandstone–mudstone interbeds in the Sulige Gas Field and validated against previously published true triaxial hydraulic fracturing experiments. The simulations indicate that vertical–horizontal stress difference (VSD; the difference between overburden stress and minimum horizontal stress within a layer) promotes fracture-height growth, whereas interlayer stress difference (ISD; the minimum horizontal stress contrast between adjacent layers) acts as a stress barrier that promotes bedding interface shear failure and arrests vertical growth. For the investigated reservoir configuration, each 4 MPa increase in VSD increased fracture height by approximately 1.5 m in the three-cluster case and 1.8 m in the four-cluster case, whereas each 2 MPa increase in ISD reduced the average fracture height by approximately 4.0 m in the three-cluster case and 3.5 m in the four-cluster case. Under moderate ISD, increasing the fluid viscosity was more effective than increasing the injection rate alone, although the benefit depended on cluster number and interface failure state. These results clarify how stress contrast, interface strength, and multi-cluster stress shadows jointly control cross-layer fracture propagation in thin interbedded reservoirs.

To address the significant decline in fracture conductivity after cross-layer fracturing in the L3 sand–mudstone interbedded reservoir of the WZ Oilfield, which restricts efficient development, this study investigates three typical fracture types formed after fracturing: simple fractures in muddy siltstone, simple fractures in mudstone, and complex fractures in muddy siltstone. Based on downhole full-diameter cores, fracture conductivity plates were prepared, and long-term (50 h) conductivity evaluation experiments were conducted under a simulated formation closure pressure of 28 MPa. The interaction modes between fracture surfaces and proppants, as well as the conductivity evolution laws of different fracture types were systematically analyzed. The results indicate that the interaction modes between proppants and fracture walls vary significantly with lithology and fracture morphology. Specifically, proppant embedment dominates in simple muddy siltstone fractures, whereas hydration-induced embedding and wrapping by swelled clay particles dominate in mudstone fractures. The conductivity evolution of simple fractures in muddy siltstone and mudstone follows an exponential decay law, with attenuation amplitudes of 35% and 98% after 50 h, respectively. Complex fractures in muddy siltstone exhibit a staged decay pattern with an attenuation amplitude of 92%, and their long-term conductivity primarily depends on shear-induced self-support. The overall conductivity of cross-layer fractures is controlled by the minimum conductivity among the intersected layers. Under the specific experimental conditions of 28 MPa closure pressure and 30/50 mesh ceramic proppant, the poor long-term conductivity of mudstone simple fractures (only 2% of the initial value) becomes the key bottleneck restricting productivity. This study characterizes the evolutionary features of conductivity evolution of cross-layer fractures in sand–mudstone interbedded reservoirs and provides theoretical support and engineering guidance for optimizing fracturing fluid systems to inhibit hydration and refining stage isolation strategies in similar reservoirs.