A modified fluid-mechanically coupled algorithm in PFC^2D was adopted in this article to study the influence of grain size heterogeneity and in-situ stress on hydraulic fracturing behavior. Simulated results showed that the in-situ stress and grain size heterogeneity significantly affect the initiation, growth, and spatial distribution of the hydraulic fractures: (1) the initiation and breakdown pressure are gradually reduced with the increase of the grain size heterogeneity; (2) with increased in-situ stress, the initiation and breakdown pressure increase, and the reduction effect of grain size heterogeneity on the breakdown pressure becomes more obvious; (3) in grain size homogeneous rock, the initiation pressure decreases with increasing in-situ stress ratio, however, the initiation pressure of grain size heterogeneous rock is almost unaffected by the in-situ stress ratio; (4) The in-situ stress ratio and grain size heterogeneity affect the spatial distribution of hydraulic fractures simultaneously. When the in-situ stress ratio is larger than 1, the hydraulic fractures propagate substantially along the direction of the maximum principal stress. When the in-situ stress ratio is 1, the initiation position and extension direction of hydraulic fractures are random and complex fracture networks can easily develop in a grain size homogeneous model.

Rock is an aggregate of mineral grains, and the grain shape has an obvious influence on rock mechanical behaviors. Current research on grain shape mostly focuses on loose granular materials and lacks standardized quantitative methods. Based on the CLUMP method in the two-dimensional particle flow code (PFC^2D), three different grain groups were generated: strip, triangle, and square. Flatness and roughness were adopted to describe the overall contour and the surface morphology of the mineral grains, respectively. Simulated results showed that the grain shape significantly affected rock porosity and further influenced the peak strength and elastic modulus. The peak strength and elastic modulus of the model with strip-shaped grains were the highest, followed by the models with triangular and square grains. The effects of flatness and roughness on rock peak strength were the opposite, and the peak strength had a significant, positive correlation with cohesion. Tensile cracking was dominant among the generated microcracks, and the percentage of tensile cracking was maximal in the model with square grains. At the postpeak stage, the interlocking between grains was enhanced along with the increased surface roughness, which led to a slower stress drop.

Hydraulic fracturing is a key technical means for stimulating tight and low permeability reservoirs to improve the production, which is widely employed in the development of unconventional energy resources, including shale gas, shale oil, gas hydrate, and dry hot rock. Although significant progress has been made in the simulation of fracturing a single well using two-dimensional Particle Flow Code (PFC2D), the understanding of the multi-well hydraulic fracturing characteristics is still limited. Exploring the mechanisms of fluid-driven fracture initiation, propagation and interaction under multi-well fracturing conditions is of great theoretical significance for creating complex fracture networks in the reservoir. In this study, a series of two-well fracturing simulations by a modified fluid-mechanical coupling algorithm were conducted to systematically investigate the effects of injection sequence and well spacing on breakdown pressure, fracture propagation and stress shadow. The results show that both injection sequence and well spacing make little difference on breakdown pressure but have huge impacts on fracture propagation pressure. Especially under hydrostatic pressure conditions, simultaneous injection and small well spacing increase the pore pressure between two injection wells and reduce the effective stress of rock to achieve lower fracture propagation pressure. The injection sequence can change the propagation direction of hydraulic fractures. When the in-situ stress is hydrostatic pressure, simultaneous injection compels the fractures to deflect and tend to propagate horizontally, which promotes the formation of complex fracture networks between two injection wells. When the maximum in-situ stress is in the horizontal direction, asynchronous injection is more conducive to the parallel propagation of multiple hydraulic fractures. Nevertheless, excessively small or large well spacing reduces the number of fracture branches in fracture networks. In addition, the stress shadow effect is found to be sensitive to both injection sequence and well spacing.

The mechanical characteristics of gas hydrate-bearing sediments (HBS) are important for evaluating reservoir stability. The interbedded formation of HBS is common in target mining reservoirs. Existing studies on the triaxial mechanical properties of HBS are primarily based on homogeneous and isotropic samples. Therefore, the stress–strain law of the target mining reservoirs cannot be predicted accurately. In this study, a series of sediment models with interlayers of coarse and fine mineral grains were established based on the PFC3D code, and the influence of the layered distribution characteristics of sediment particles and hydrates on the macroscopic mechanical behaviour of the reservoir was comprehensively analysed. The triaxial compression simulation results indicate that the peak strength, deformation modulus, and cohesion of the layered HBS are significantly lower than those of the homogeneous model. The deformation modulus of the reservoir is mainly affected by the fine-grained layer without hydrates. When the coarse and fine grains correspond to different mineral components, the two minerals are heterogeneous in terms of their micromechanical parameters, which can further reduce the macroscopic mechanical parameters of the HBS. In addition, the layered distribution of hydrate results in significant anisotropy of the reservoir. This study constitutes a reference regarding the control mechanism of gas hydrate reservoir strength.

Natural gas hydrate (NGH) is considered as a type of clean energy to replace coal and oil. During exploitation, permeability is one of the key parameters controlling production efficiency, reservoir stability, and greenhouse gas sequestration. Limited by experimental and numerical simulation tools, in current research, the directionality of permeability is usually ignored. In this work, a DEM–CFD coupling simulation method is developed to compute the anisotropic permeability. The sedimentary process of reservoir sediments is reconstructed, enabling the acquisition of numerical models that possess pore structures consistent with the actual fabric characteristics. The fluid transport process in various directions can be simulated with a finite element method. Taking the natural gas hydrate reservoir in the Shenhu area of the South China Sea as an example, the proposed method is validated and applied to explore the effect of compaction stress on permeability anisotropy. With the increase in compaction stress, the permeability anisotropy exhibited a rapid initial increase, followed by a sustained stabilization. The primary cause is the rearrangement of sediment particles. The non-spherical particles are driven to align in a predominantly horizontal orientation, thereby enhancing anisotropy. The proposed method provides a tool for the efficient exploitation of hydrate resources.