A Numerical Study of the Effects of Temperature and Injection Velocity on Oil-Water Relative Permeability for Enhanced Oil Recovery

The paper quantitatively explore the influence of injection rate and temperature on oil-water relative permeability curves during hot water flooding operations in a porous medium flow. ANSYS-CFD was used to construct a numerical model of hot-water injection into an oil saturated sandstone core sample. The modelling technique is based on the Eulerian-Mixture model, using a 3D cylindrical core sample with known inherent permeability and porosity. Injection water at 20° C was injected into a core sample that was kept at 63 °C and had 14-mD permeability and 26% porosity. For the investigation, three distinct injection rates of 2.9410^- 6 m/s, 4.41 × 10^-6 m/s, and 5.88 × 10-6 m/s were utilised. Furthermore, same injection procedures were repeated under the same conditions, but the core temperature was changed to 90 °C, allowing us to quantify the influence of temperature on the relative permeability curves of oil-water immiscible flow.

The results of this study show that the relative permeability of oil is strongly influenced by flow, while the effect of the relative permeability of water is negligible. In addition, the flow rate influences the residual oil and water saturation, as well as the associated effective permeability. From 20 ° C to 90 °C there is little sensitivity to relative permeability or temperature. This study does not provide proof that temperature effects do not exist with genuine reservoir fluids, rocks, and temperature ranges. However, this study has demonstrated the feasibility of utilising CFD approaches to estimate fluid relative permeability, as well as the combined influence of temperature change and flow rate on relative permeability, with the potential for considerable cost-time advantages.