Qihui Zhang

This work presents a numerical study of side boundary effects in pore-scale digital rock flow simulations, where the side boundaries are often treated as no-slip walls. While the capillary end effects from inlet and outlet boundaries are well known, the influence of side boundaries has not been systematically studied, especially for two-phase flow. We employ a well-established three-dimensional color-gradient lattice Boltzmann model to simulate immiscible two-phase flow on both real and synthetic rock samples. Our results reveal significant artifacts in small samples caused by side boundaries, leading to non-representative saturation profiles, even though absolute permeability remains consistent with larger samples. In drainage, non-wetting phase saturation is substantially lower near the side boundaries due to increased trapping of the wetting phase, while in imbibition, the wetting phase preferentially flows along the walls, forming steep V-shaped saturation profiles near the side boundaries. Increasing sample size can reduce boundary influence, but this is often impractical for certain samples, owing to, for instance, high computational demands. Enforcing periodic boundary conditions directly on the side boundaries only marginally improves saturation near the boundaries for the drainage cases, as poor pore connectivity across quasi-periodic boundaries remains a limitation, especially in low-porosity media, while the approach causes unphysically high wetting phase saturation near the side boundaries during imbibition. An alternative approach is to generate synthetic rock samples that are inherently periodic in the transverse directions, enabling more representative two-phase flow simulations. By comparing simulations with no-slip and periodic boundary conditions on a low porosity synthetic rock sample, the side boundary effects can cause more than 10% differences in steady-state saturation. Thus, synthetically generated periodic digital rock samples offer a promising solution for pore-scale studies of low-porosity media.

Ultra-deep fractured tight sandstone reservoirs are key targets for natural gas development, where gas flow is controlled by pore structure, capillary forces, and water saturation. Using the ultra-deep tight sandstones from the Tarim Basin as study object, this paper investigates the gas flow behavior in matrix and fractured cores under high-temperature, high-pressure, and various water saturation conditions. The controlling factors of gas flow are investigated through scanning electron microscopy, casting thin-section, and high-pressure mercury intrusion measurements. The results show that increasing the water saturation can significantly reduce the permeability. The permeability of matrix and fractured cores decreases by 71.15% and 79.67%, respectively, when water saturation reaches 50%. The gas slippage is negligible, but the effect of gas threshold pressure is significant, which is primarily controlled by the pore structure and water saturation. The threshold pressure gradient of gas flow ranges from 0.0004 to 0.8762 MPa/cm, with the matrix cores exhibiting values approximately 13.21 times higher than the fractured cores. The water phase preferentially occupies the larger pores, forcing gas flow to rely on the finer pores. The pores with a maximum radius of 0.21 μm require 0.66 MPa of driving pressure for gas, whereas pores with a median radius of 0.033 μm require 4.18 MPa. The fracture networks can significantly reduce the lower limit for gas flow, serving as the key flow channels for the efficient development of ultra-deep tight sandstone gas. These findings not only reveal the gas flow mechanisms under water invasion but also provide theoretical and practical guidance for enhancing gas recovery from ultra-deep tight sandstone reservoirs.

Ultra-deep tight sandstone gas reservoirs are key targets for natural gas exploration, yet their pore structures under high temperature, pressure, and stress greatly affect gas occurrence and flow. This study investigates representative reservoirs in the Kelasu structural belt, Tarim Basin. Porosity–permeability were measured under in situ conditions, and multi-scale pore structures were analyzed using thin sections, a SEM, mercury intrusion, and nitrogen adsorption. The results show that (1) the median permeability of cores at an ambient temperature and a confining stress of 3 MPa is 13.33–29.63 times that under the in situ temperature and pressure conditions. When the core permeability is lower than 0.1 mD, the stress sensitivity effect is significantly enhanced; (2) nanopores and micron-fractures are well developed yet exhibit poor connectivity. The majority of a core’s porosity is derived from the intergranular pores in clay minerals; (3) the volume of nano-sized pores within the 100 nm diameter range is mainly composed of mesopores, with an average proportion of 73.37%, while the average proportions of macropores and micropores are 22.29% and 4.34%, respectively; (4) full-scale pore sizes show bimodal peaks at 100–1000 nm and >100 μm, which are poorly connected; (5) the pore structure exhibits distinct fractal characteristics. The fractal dimension D_f1 (2.65 on average) corresponds to the larger pore diameters of the primary intergranular pores, residual intergranular pores, and intragranular dissolution pores. The fractal dimension D_f2 (2.10 on average) corresponds to the grain margin fractures, micron-fractures and partial throats. The pore types corresponding to the fractal dimensions D_f3 (2.36 on average) and D_f4 (2.58 on average) are mainly intercrystalline pores of clay minerals and a small number of intraparticle dissolution pores. These findings clarify the pore structure of ultra-deep tight sandstones and provide insights into their gas occurrence and flow mechanisms.