Pore Scale Network Modeling of Relative permeability in Chemical flooding

Abstract

Abstract Relative permeability provides important information for understanding the dynamic behavior of two-phase flow. EOR technology featured by polymer flooding, surfactant flooding and ASP compositional flooding requires relative permeability data to characterize the flow behavior in reservoir engineering calculation and numerical simulation. A dynamic pore scale network model and its application in simulating the impact of IFT and oil/water viscosity on relative permeability are presented in this paper. The parameters of both viscous force and capillary force, instead of the only one parameter the capillary pressure as in conventional or invasion percolation algorithm, control the displacement configuration in this model, and so the model can better reflect the impact of chemical flooding on flow behavior. The study presented that both water and oil relative permeability curves shift with variation of IFT and oil/water viscosity ratio. It was found that both water and oil relative permeability curves shift upward as IFT is reduced. They tend to become linear with saturation as IFT reach ultra low value. The effect of viscosity ratio is very small when the interfacial tension is high. But when the interfacial is low, the water relative permeability decreases with the increase of the water viscosity. The oil relative permeability also decreases but not as much as water, especially at high water saturation, the decrease can be neglected. The breakthrough saturation tends to decrease with reduction of IFT, however within a certain range of IFT value, this simple correlation between breakthrough saturation and IFT might be changed with oil/water viscosity ratio. Introduction As world oil reserves dwindle, the development of EOR techniques to maximize recovery is of great importance. Methods such as chemical flooding, miscible flooding, and thermal recovery involve altering the mobility and/or the interfacial tension between the displacing and the displaced fluids. Means for increasing tertiary oil recoveries from previously waterflooded oil fields is receiving more and more attention today as a result of industry-wide efforts to improve the oil producing rates and reserves. The flow behavior of chemical flooding differs from that of conventional water and oil, it depends upon interfacial tension, viscosity, and flow rate as well as the rock properties of pore size distribution and wettability. The mechanism of two-phase flow in porous media in chemical flooding has long been a hot topic for discussions. The concept of relative permeability was introduced to describe simultaneous flow of fluids in a porous medium by an apparently simple modification of Darcy's equation. To evaluate the potential magnitude of improved recovery and economics of prior chemical injection, it is necessary to use relative permeability data in performance evaluation calculations. Many studies have shown that the presence of polymer and/or surfactant in water phase had a significant and consistent effect. Mathematical model studies provide a reliable means for evaluating potential benefits of chemical flooding. However, such studies require input data that permit the model to simulate the physical process that may occur in the reservoir. With the increased use of mathematical reservoir simulators to predict recovery from different EOR processes, the need to model the various flow properties, especially relative permeability, becomes more and important.