Influence of reservoir conditions on multiphase flow in natural sandstone using lattice Boltzmann simulation: Investigation of suitable conditions in CCS and EOR

Abstract:

Microscopic two-phase fluid behavior in porous media is influenced by reservoir temperature, interfacial tension, pore structure, and porous medium characteristics (e.g., wettability), which vary significantly from one reservoir to the next. Pore-scale interfacial instabilities, such as snap-off and fingering phenomena, influence the stability, injectivity, mobility, and saturation within the reservoir. Therefore, understanding microscopic multiphase flow in porous media is crucial to estimating critical reservoir-scale characteristics, including storage capacity, leakage risk, and storage efficiency. Here we calculated fluid displacements within 3D pore spaces of natural sandstone using two-phase lattice Boltzmann (LB) simulation and characterized the influence of reservoir conditions upon multiphase flow. We classified the two-phase flow behavior that occurred under various conditions into three typical fluid displacement patterns on the diagram of capillary number (Ca) and viscosity ratio of the two fluids (M). Then the saturation of the nonwetting phase was calculated and mapped on the Ca–M diagram. The saturation map is useful to investigate suitable conditions in CCS and EOR. We further characterized dynamic pore-filling events (i.e., Haines jumps) from the fluid pressure variation. The results revealed the onset of capillary fingering in natural rock at a higher Ca than previously reported for homogeneous porous media, with the crossover region between typical displacement patterns much broader than in a homogeneous granular model. These differences between two-phase flow in natural rock and in a homogeneous porous structure could be the result of the heterogeneity of the natural rock.