Fracture Propagation Characteristics and Influencing Factors in Cross-Layer Fracturing of Interlayered Shale Reservoirs

Influence of Natural-Fracture Connectivity on Hydraulic-Fracture Propagation in Shale Reservoirs

Natural-fracture connectivity substantially influences hydraulic-fracture interaction with pre-existing discontinuities, but its quantitative role in fracture-network propagation remains insufficiently constrained. In this study, a coupled LEFM–cohesive-zone hydraulic-fracture propagation model was developed by combining crack-tip deflection criteria, traction-separation damage evolution and fluid–solid coupling. True triaxial hydraulic-fracturing experiments were conducted on artificial fracture networks with I-, V-, Y- and X-shaped connectivity elements to evaluate the model response. The results show that connected natural fractures redirect hydraulic fractures under low horizontal stress differences, producing deflection angles of 30–50 degrees. When the stress difference exceeds 4 MPa, fracture growth becomes more strongly aligned with the maximum principal stress direction. In the true triaxial tests, the total number of connected natural fractures increased from 14 in the I-shaped network to 17 and 21 in the Y- and X-shaped networks, corresponding to increases of 21.4% and 50.0%, respectively. X-shaped networks showed the strongest sensitivity to stress difference and injection rate, while higher elastic modulus reduced fracture width and promoted longer, narrower fractures. Scale-normalized comparisons based on image-derived experimental measurements showed that the predicted propagation length, fracture width and connected-fracture number followed the experimental trend from I-shaped to Y-shaped and X-shaped networks, with relative errors within 7.1% and a mean absolute percentage error of 4.8%. These findings suggest that fracture topology strongly influences pressure transmission and multidirectional activation in the tested models, whereas field-scale extrapolation requires three-dimensional validation and transport analysis.

Lithology-Dependent Fracture Propagation in Ultra-Large True-Triaxial Hydraulic-Fracturing Experiments

Tight reservoirs commonly exhibit low permeability and pronounced lithological heterogeneity, resulting in complex interactions among far-field stress, local structural weakness, and fluid-driven fracture propagation. In this study, four non-replicated 2 m × 2 m × 1 m physical-model specimens representing tight glutenite, tight sandstone, and No. 3 coal rock from the Huabei Oilfield were investigated using an ultra-large true-triaxial hydraulic-fracturing system. Surface-fracture observations, microseismic monitoring, and high-frequency wellhead-pressure measurements were integrated to compare fracture responses under lithology-specific combinations of injection rate, fluid viscosity, perforation configuration, and stress state. The tested glutenite cases exhibited branched or localized fracture patterns depending on the combined treatment configuration; the sandstone case was dominated by a throughgoing main fracture approximately aligned with the principal-stress direction; and the coal-rock case showed extensive participation of bedding and cleat systems. These morphological differences were accompanied by distinct pressure and microseismic signatures, indicating different pathways of hydraulic-energy redistribution and fracture activation. For the two glutenite cases, the combined change from a single-perforation configuration at 0.5 m3/min to three helical perforations at 120° and 0.7 m3/min was associated with a 42.2% larger microseismic-derived stimulated reservoir volume (SRV). Taken together, these responses indicate a shift from stronger far-field-stress-controlled localization in the comparatively uniform sandstone to progressively greater local structural control by heterogeneous interfaces in glutenite and by bedding/cleat discontinuities in coal rock. Because each configuration was represented by a single specimen and several experimental variables changed simultaneously among cases, the observed differences are interpreted as case-specific mechanistic trends rather than statistically established universal relationships. The results show the value of combining fracture morphology, microseismic spatial evolution, and pressure dynamics for interpreting lithology-dependent fracture propagation in ultra-large physical models and for developing qualitative, lithology-adapted hydraulic-fracturing concepts.

Study on mechanical response and damage models of sandstone-shale interbedding under different cyclic loading modes

Fracture Morphologies of Shale in Brazilian Tests Based on A Thin-Layer Model

Study on the Evolution of Reservoir Conductivity in Inter-Salt Shale under Fluid-Rock Interactions

: The inter-salt shale reservoir in the Qianjiang Depression exhibits strong vertical heterogeneity and high oil content, but unlike conventional shales, it is characterized by complex lithology, poor pore connectivity, high plasticity, and pronounced sensitivity. During reservoir hydraulic fracturing, the interaction between injected fluids and the reservoir matrix not only alters fracture surface strength but also induces matrix softening, leading to damage-induced fractures with limited effective duration and rapid decay of fracture conductivity. However, the reservoir adaptability of different injected fluids remains unclear. In this study, triaxial compression tests and a small-scale core fracture conductivity displacement apparatus were employed to measure mechanical parameters and fracture conductivity. From a coupled mechanical–chemical perspective, the evolution of fracture conductivity under varying fluid soaking durations, fluid types, and lithological matrix conditions was investigated. The results indicate that fluid type has a significant impact on the mechanical properties. After soaking in 15 wt% NaCl solution reduced the elastic modulus of argillaceous dolomite by 47.5%, whereas the ethylene glycol–based gel-breaking fluid caused only a 21.2% decrease. Microscopic observations indicated relatively minor microstructural damage in the latter, characterized by localized surface dissolution without evident salt crystallization. Fracture conductivity tests indicate that soaking duration markedly affects conductivity under low closure pressure; at 9 MPa, extending soaking from 12 to 24 h reduced conductivity by 77.3% (from 8.074 D ⋅ cm). However, as closure pressure increases beyond 27 MPa, the conductivity differences induced by different soaking durations gradually diminish, suggesting a transition from fluid-sensitivity-dominated to stress-dominated conductivity loss. Under identical proppant placement, the ethylene glycol–based gel-breaking fracturing fluid caused less reservoir rock damage than supercritical CO 2 and guar-based fluids, resulting in superior fracture conductivity. This study informs the selection of fracturing fluids and provides a reference for enhancing fracture conductivity in inter-salt shale reservoirs.

Mechanical response and failure mechanisms of sandstone under water–rock interaction: a multi-scale study and constitutive modeling