The influence of salinity on the viscous instability in viscous-modified low-interfacial tension flow during surfactant–polymer flooding in heavy oil reservoirs

Abstract

In this study, the effect of viscous instability at varying salinities of the displacing non-wetting phase (i.e., surfactant–polymer solution) in surfactant–polymer flooding of heavy oil reservoirs– which is a viscous-modified low-interfacial tension (IFT) flow through an initially preferential oil-wet porous medium– is quantified in the presence of the adverse mobility ratio. The dynamic mean pore-scale capillary number values are determined using two different approaches. The first approach is a Pore network approach (PNA) that excludes the viscous instability effects. The second approach is using the Viscous instability model (VIM) proposed by Peters and Flock [49] in which the concept of the wavelength of the viscous fingers is introduced. Afterwards, these two dynamic mean pore-scale capillary number values are compared to each other to highlight the effects of viscous instability at different salinity levels of the surfactant–polymer solution. The results show that including the viscous instability effects in the qualitative and quantitative evaluations of the viscous-modified low-IFT flow is vital. In particular, the viscous instability effects become more complex near the breakthrough of the displacing non-wetting phase. Furthermore, the effects of the salinity on the dynamic mean pore-scale capillary number (by excluding/excluding the viscous instability effects, i.e., from PNA and VIM, respectively), IFT, dynamic viscosity, contact angle, displacement front configuration, wavelength of the viscous fingers, dynamic values of the desaturated displaced wetting phase, breakthrough time, and the time of infinite injected pore volume is discussed in the surfactant–polymer flooding of an initially preferential oil-wet porous medium containing heavy oil.