The dynamic compression fracture of brittle rock under seepage pressure is a critical issue for deep underground engineering. It directly influences the stability and safety of the surrounding rock during blasting or seismic loading. However, research on the mechanisms of microcrack evolution under these coupled conditions is still lacking. The relationship between microcrack evolution and macroscopic mechanical properties also remains poorly understood. This study develops a micro–macrofracture model grounded in the wing microcrack propagation framework, integrating both mechanical and chemical interactions between free water and rock. Mechanically, it incorporates seepage pressure, dynamic Stefan force, and dynamic fracture toughness. Chemically, it accounts for the effects of saturated water on rock mechanical parameters. This model characterizes the total stress–strain constitutive behavior of brittle rock under varying seepage pressures during dynamic compression failure, encompassing both strain-hardening and strain-softening phases. This result is validated against experimental data. It accounts for the influence of seepage pressure on both the initial crack and the newly formed wing crack. The seepage pressure weakens the wedging force F W on the initial crack while enhancing the seepage tensile force F P on the wing crack, which constitutes the seepage pressure-driven crack growth mechanism. Furthermore, under the combined effects of dynamic loading and free water, the dynamic Stefan force F S and the dynamic fracture toughness K ICD serve as the mechanism for inhibiting crack growth. The combined influences of seepage pressure, confining pressure and initial crack characteristics on the dynamic mechanical behavior of brittle rock under seepage pressure are discussed.
Rock failure under hydromechanical coupling is a complex process that has attracted considerable attention in deep underground engineering. In this study, a hydraulic coupling analysis method for rock loading and failure is developed based on the finite–discrete-element method (FDEM) combined with the grain-based model, which integrates the dual-medium seepage–stress coupling theory to simultaneously capture pore and fracture seepage. Numerical simulations of sandstone under varying confining pressures were performed and validated against laboratory experiments, and the effects of confining pressure and weak joint content on the permeability evolution were systematically investigated. The results demonstrate that the permeability evolution during loading is governed by the competitive interplay between matrix seepage and fracture seepage, exhibiting a nonlinear pattern. Higher confining pressures prolong the stage of slow permeability growth, whereas an increase in the weak joint content reduces strength and stiffness, leading to an earlier occurrence of the permeability inflection point and an enhanced dominance of fracture flow in controlling macroscopic permeability. These findings provide new insights into the mechanisms of hydromechanical coupling in fractured porous rocks and offer theoretical support for predicting and controlling hydraulic hazards in deep rock engineering.
Overburden rotation and mining disturbance promote deep coal fracture and spalling, potentially inducing dynamic hazards, while the coal–rock thickness ratio largely governs the composite’s dynamic response and failure severity. Based on the geological conditions of a typical deep coal mine, SHPB tests were performed on coal–sandstone composite specimens with four systematically varied coal-to-rock ratios (C:R = 1:0, 2:1, 1:1, and 1:2). High-speed photography and the digital speckle correlation method (DIC) were integrated to capture displacement, strain, energy, and fragmentation fields throughout progressive dynamic compression. Experimental data revealed four findings: (1) Crack development follows a sequential evolution process of initiation, propagation, and failure. Higher impact air pressure accelerates crack development and coalescence, resulting in a higher degree of specimen fragmentation and fewer large blocks. Within the tested range of coal–rock ratios, an increase in the rock proportion accelerates coal fracture, which is attributed to the significantly higher density and hardness of rock compared to coal. (2) Energy evolution consistently follows three stages: absorption, accumulation, and dissipation. Under identical impact pressure, a higher rock ratio elevates equivalent stiffness and wave impedance, leading to monotonic increases in peak stress, peak strain, absorbed energy, and dissipated energy. (3) The fragmentation degree exhibits a pronounced dependence on impact pressure. Specifically, for the pure coal specimen (C:R = 1:0), when the impact pressure increases from 0.3 MPa to 0.7 MPa, the mass percentage of coarse debris (>30 mm) drops from 73.37% to 18.57%, whereas that of fine particles (<4 mm) rises from 15.69% to 35.24%. (4) Under identical impact conditions, a higher rock proportion leads to increasing trends in all measured indicators, including peak stress, strain, and energy accumulation and dissipation, which are consistent with the superior mechanical properties of the rock. Based on these observations, it can be inferred that the wave impedance mismatch and stiffness ratio at the coal–rock interface play a key role in controlling stress wave transmission/reflection and strain incompatibility; however, the individual contribution of each factor warrants further dedicated investigation.
Understanding how rock properties change with depth is crucial for a variety of geoengineering applications. Even rocks that are homogenous at both micro and macro scales, such as Bentheim sandstone, lose this characteristic once fractured. While recent studies have shown how concomitant changes in stress, temperature and pore pressure affects the evolution of intact sample permeability at depths, an equivalent study on fractured material is missing. Therefore, by combining a multi-methodological approach consisting of rock deformation experiments simulating depth conditions up to 4 km, thin section analysis and fluid composition analysis of water samples, the evolution of permeability of fractured Bentheim sandstone is investigated in this study. Results suggests that fine particles produced by the fracturing and the movements along these fractures play a crucial role in permeability evolution. When these particles are removed, the fracture constitutes a preferential pathway and, together with the chemical processes occurring on the rock–fluid system, lead to a 3–7 times reduction in permeability followed by a complete recovery of it after a simulated burial and exhumation path. On the contrary, when these particles are still present within the fracture zone, they impede fluid flow. This causes a slightly reduction of permeability during the burial path followed by almost constant values of permeability throughout the exhumation path. These findings provide crucial information for georeservoir applications and the transfer of results from laboratory experiments to in situ conditions for a correct prediction of hydraulic properties.
Hydraulic-fracture transmission across lithologic interfaces governs fracture-height growth and reservoir connectivity in shale–sandstone interbedded reservoirs, yet the coupled effects of mechanical contrast, interface properties, layer geometry, and operational parameters remain insufficiently quantified. A two-dimensional plane-strain hydraulic-fracturing model was developed in ABAQUS by coupling Biot poroelasticity, cohesive-zone damage, and fracture-fluid flow. The model explicitly represents thin, alternating continental shale–sandstone layers, lithology-dependent in situ stress and stiffness, and cohesive interfaces; its implementation was assessed against the KGD solution and published layered-rock fracture morphologies. Under the simulated conditions, increasing the shale-to-sandstone elastic-modulus ratio from 0.4–0.5 to 0.6–0.8 reduced the number of penetrated layers from eight to six. Increasing tensile strength from 4 to 16 MPa reduced the number of penetrated layers from ten to six and the final fracture length from 32 to 21 m, while increasing the maximum aperture from 6.75 to 9.02 mm. A sandstone interlayer thickness of approximately 3 m marked a transition in the present parameter set rather than a universal threshold. Sandstone-centered perforation and higher injection rates promoted vertical connectivity, whereas very high fluid viscosity increased near-wellbore aperture but restricted long-distance fracture-height growth. These results provide a mechanics-based framework for optimizing perforation placement and stage-specific fluid design in continental interbedded shale reservoirs.