Relative Permeability Variation Depending on Viscosity Ratio and Capillary Number

Abstract

The relative roles of parameters governing relative permeability, a crucial property for two‐phase fluid flows, are incompletely known. To characterize the influence of viscosity ratio (M) and capillary number (Ca), we calculated relative permeabilities of nonwetting fluids (knw) and wetting fluids (kw) in a 3D model of Berea sandstone under steady state condition using the lattice‐Boltzmann method. We show that knw increases and kw decreases as M increases due to the lubricating effect, locally occurred pore‐filling behavior, and instability at fluid interfaces. We also show that knw decreases markedly at low Ca (log Ca < −1.25), whereas kw undergoes negligible change with changing Ca. An M‐Ca‐knw correlation diagram, displaying the simultaneous effects of M and Ca, shows that they cause knw to vary by an order of magnitude. The color map produced is useful to provide accurate estimates of knw in reservoir‐scale simulations and to help identify the optimum properties of the immiscible fluids to be used in a geologic reservoir.

Impact of Oil Viscosity on Dispersion in the Aqueous Phase of an Immiscible Two‐Phase Flow in Porous Media: An X‐Ray Tomography Study

“…The non‐wetting fluid becomes disconnected, and the size of each cluster decreases. The low connectivity of the non‐wetting phase explains the decrease in its relative permeability measured in Section 2.3, similar to the results of previous simulation experiments (Suwandi et al., 2022). Additionally, even with a decrease in the permeability of the wetting phase, more heterogeneous flow fields are generated by the wide distribution of small oil clusters.…”

“…Meanwhile, heterogeneities of the porous media are highly increased accordingly to the significant increase of coefficients α L and α T (Table 3). This is a result of the high stability of viscous oil adhering to the surface of porous media (Sasidharanpillai et al., 2022), where stably trapped oil clusters narrow the pore size (Scanziani et al., 2018; Singh et al., 2016) and reduce the permeability of the partially saturated porous media (Suwandi et al., 2022). The conventional definition of the Pe number regarding average interstitial velocities fails to describe the actual advection behaviors of the co‐injection flow.…”

“…In previous publications (Ehrlich, 1993;H. Li et al, 2005;Suwandi et al, 2022;J. Wang et al, 2006), the lubrication effect was referred to an increased oil relative permeability by water due to viscous force at oil-water interfaces.…”

“…The viscous coupling is reduced for nonzero interfacial shear viscosity (Ehrlich, 1993; H. Li et al., 2005). The connectivity of the non‐wetting fluid decreases, forming more clusters with smaller sizes (Suwandi et al., 2022). For oils with viscosities ranging from 430 to 1,860 mPa·s, similar relative permeability curves of the wetting phase appear with a slight decrease in the non‐wetting phase relative permeability (J. Wang et al., 2006), which is disadvantageous in terms of CO 2 storage capacity in highly viscous oil fields (Yoshida et al., 2016).…”

“…Differences in viscosity contrast can contribute to large differences between pressure gradients and the relative permeabilities of two fluids. At a low viscosity contrast ratio M (e.g., 0.1–5), the relative permeability of the wetting fluid decreases as M increases based on an increase in the shear force of the non‐wetting fluid (viscous coupling effect) (Suwandi et al., 2022). The viscous coupling effect is also known as the lubrication effect.…”