Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone. (September 2016)

• Record Type: Journal Article
• Authors: Tsuji, Takeshi; Jiang, Fei; Christensen, Kenneth T.
• Is Part Of: Advances in water resources. Volume 95(2016)
• Page Start: 3
• Page End: 15
• Publication Date: 2016-09
• Subjects: Multiphase flow -- 3D digital rock -- Lattice Boltzmann method -- Displacement patterns -- Pore-filling events -- Pore heterogeneity and connectivity; Hydrology -- Periodicals; Hydrodynamics -- Periodicals; Hydraulic engineering -- Periodicals; 551.48
• DOI: 10.1016/j.advwatres.2016.03.005
• Languages: English
• ISSNs: 0309-1708

Abstract

Highlights: Two-phase flow behavior in 3D natural rock is calculated at various conditions. Flow patterns are classified in the diagram of capillary number – viscosity ratio . Optimum fluid saturation scales with capillary number and viscosity ratio. Different flow patterns exist simultaneously in heterogeneous natural rock. This approach is beneficial for identifying preferable reservoir conditions. Abstract: To characterize the influence of reservoir conditions upon multiphase flow, we calculated fluid displacements (drainage processes) in 3D pore spaces of Berea sandstone using two-phase lattice Boltzmann (LB) simulations. The results of simulations under various conditions were used to classify the resulting two-phase flow behavior into three typical fluid displacement patterns on the diagram of capillary number ( Ca ) and viscosity ratio of the two fluids ( M ). In addition, the saturation of the nonwetting phase was calculated and mapped on the Ca–M diagram. We then characterized dynamic pore-filling events (i.e., Haines jumps) from the pressure variation of the nonwetting phase, and linked this behavior to the occurrence of capillary fingering. The results revealed the onset of capillary fingering in 3D natural rock at a higher Ca than in 2D homogeneous granular models, with the crossover region between typical displacement patterns broader than in the homogeneous granular model. Furthermore, saturation of the nonwetting phase mapped on the Ca–M diagram significantly depends on the rock models. These important differences between two-phase flow in 3D natural rock and in 2D homogeneous models could be due to the heterogeneity of pore geometry in the natural rock and differences in pore connectivity. By quantifying two-phase fluid behavior in the target reservoir rock under various conditions (e.g., saturation mapping on the Ca–M diagram), our approach could provide useful information for investigating suitable reservoir conditions for geo-fluid management (e.g., high CO2 saturation in CO2 storage).