The pore geometry and slip conditions are two principal characteristics of liquid flow in shale noncircular nanopores. We have considered the pore shape and liquid slippage on the pore interior wall in pore-network models of the Yanchang shale in China. Multiple scanning electron microscopy (SEM) images of the Yanchang shale samples were analyzed to document and summarize various pore shapes and sizes. Fluid-flow behavior in noncircular pores significantly deviates from the flow behavior in circular pores used in many current models. In addition, liquid flow simulations in conventional reservoir systems assume a no-slip flow boundary condition, which is unacceptable in nanoscale pores associated with the Yanchang shale. We studied liquid permeability in the Yanchang shale by developing realistic pore-network models based on nitrogen sorption data and SEM image analysis. The input data to the developed pore-network models include pore-size distribution, total organic carbon, porosity, surface area, pore geometry, and liquid slip length. We found that the effective permeability based on the realistic multigeometry model is significantly higher than the predicted Darcy permeability. The apparent permeability discrepancy between Darcy’s law and the realistic slip-corrected multigeometry model is higher for shale samples with an increasing number of noncircular pores. We also found that neglecting the liquid slip and noncircularity of pores significantly underestimates apparent permeability in Yanchang shale samples.

A polyurethane slurry was developed to simultaneously enhance the strength and permeability of geological formations, differing from the conventional fracture grouting used for soft-soil reinforcement. Injected via splitting grouting, the slurry cures to form high-strength, highly permeable channels that increase reservoir permeability while improving mechanical stability (dual-enhanced stimulation). To quantify its diffusion behavior and guide field application, we built a splitting-grouting model using the finite–discrete element method (FDEM), parameterized with the reservoir properties of coalbed methane (CBM) formations in the Ordos Basin and the slurry’s measured rheology and filtration characteristics. Considering the stratified structures within coal rock formed by geological deposition, this study utilizes Python code interacting with Abaqus to divide the coal seam into coal rock and natural bedding. We analyzed the effects of engineering parameters, geological factors, and bedding characteristics on slurry–vein propagation patterns, the stimulation extent, and fracturing pressure. The findings reveal that increasing the grouting rate from 1.2 to 3.6 m³/min enlarges the stimulated volume and the maximum fracture width and raises the fracturing pressure from 26.28 to 31.44 MPa. A lower slurry viscosity of 100 mPa·s promotes the propagation of slurry veins, making it easier to develop multiple veins. The bedding-to-coal rock strength ratio controls crossing versus layer-parallel growth: at 0.3, veins more readily penetrate bedding planes, whereas at 0.1 they preferentially spread along them. Raising the lateral pressure coefficient from 0.6 to 0.8 increases the likelihood of the slurry expanding along the beddings. Natural bedding structures guide directional flow; a higher bedding density (225 lines per 10,000 m³) yields greater directional deflection and a more intricate fracture network. As the angle of bedding increases from 10° to 60°, the slurry veins are more susceptible to directional changes. Throughout the grouting process, the slurry veins can undergo varying degrees of directional alteration. Under the studied conditions, both fracturing and compaction grouting modes are present, with fracturing grouting dominating in the initial stages, while compaction grouting becomes more prominent later on. These results provide quantitative guidance for designing dual-enhanced stimulation to jointly improve permeability and mechanical stability.

To address the unclear fracture propagation behavior and the insufficient understanding of the influence mechanisms of fracturing parameters during the hydraulic fracturing of deep coalbed methane reservoirs in the Yan’an Gas Field, Well JY1 in the No. 8 coal seam of the Benxi Formation in Block N was selected as the study object. An integrated three-dimensional geomechanics–fracture propagation model coupling geomechanical conditions, cleat characteristics, and fracture propagation was established. Fracture propagation simulations were conducted under different injection rates, fluid volumes per stage, and proppant volumes per stage. The results indicate that when main fractures intersect with cleats, they may exhibit deflection, branching, or direct crossing. Increasing the injection rate enhances the driving force at the fracture tip and improves the penetration capability of main fractures. Increasing the fluid volume improves fracture coverage and inter-cluster connectivity. Increasing the proppant volume contributes to greater residual fracture width, higher proppant placement concentration, and improved fracture conductivity. An injection rate of 19–21 m³/min, a fluid volume per stage of 2500–2700 m³, and a proppant volume per stage of 280–320 m³ provide a favorable balance between fracture network development and effective proppant support under the studied reservoir conditions.

Proppant-carrying foam fracturing fluids have complex rheological and transportation properties. Current studies on these fluids often focus on experimental phenomena. However, due to the limitation of experimental research, only macroscopic properties, such as the critical settling velocity, can be obtained. Transportation mechanisms and volume fraction distributions are poorly understood as well. In our study, the liquid-solid drag coefficient is corrected, and the mathematical physical model of non-Newtonian fluids of the particle-foam multiple phase is established by using a two-phase model. Proppant settling and transport properties in foam fracturing fluids are numerically studied, particle distribution on pipe cross section is obtained at various conditions, and a criterion for full development of fluid flow in pipe is set. We also find that when the Reynolds number (Re) is less than 190, the critical point of full development of flow increases with Re, whereas when Re is greater than 190, the critical point of full development decreases exponentially with the increasing of Re before stabilizing at approximately 45.