Effect of Temperature on Bitumen/Water Relative Permeability in Oil Sands

Abstract

The steam-assisted gravity drainage (SAGD) process is among the most applicable thermal enhanced oil recovery (TEOR) methods in North American heavy oil reservoirs. In addition to improving oil mobility through viscosity reduction, the high-temperature condition that a TEOR method causes may significantly alter the fluid flow performance and behavior, as manifested by the relative permeability to fluids in the reservoir. Therefore, in a SAGD and cyclic steam stimulation (CSS), the relative permeabilities can change within the temperature-gradient region developed around the SAGD chamber or between two cycles of CSS processes. However, there is no unique two-phase relative permeability model, especially for bitumen systems to cover a wide range of temperatures. Therefore, the primary objective of this study is to history-match the results of the recent study done by Esmaeili et al. using a new methodology and to conduct limited steady-state relative permeability measurements at different temperatures to confirm the validity of displacement-based relative permeability curves and then to propose a reliable general relative permeability model as a function of temperature. Twelve history-matched bitumen/water relative permeability sets are obtained in a wide range of temperatures from 70 to 220 °C under a confining pressure higher than 1000 psi and the test pressure in the range of 350–400 psi. An in-house developed reservoir simulator was used to obtain relative permeability curves from isothermal displacement data using the history-matching approach. The results demonstrated that both production and pressure-drop data can be matched using the optimized values of parameters of the generalized Corey relative permeability model. Furthermore, a more reliable value for actual residual oil saturation was determined by applying our new methodology in history matching. A comparative analysis with the steady-state relative permeability data allowed us to determine the extent to which the unsteady-state relative permeability is affected by viscous fingering. A considerable shift in both oil and water relative permeability at higher temperatures is noticed. Furthermore, it is also noted that the endpoint relative permeability to oil and water is also altered significantly. The implicit relative permeability data obtained from this study are consistent with the results of the JBN method that were reported in our previous study. By making the parameters of the Corey relative permeability model dependent on temperature, a new model of temperature-dependent bitumen/water relative permeability in sand was developed. It is anticipated that this model can facilitate inclusion of temperature-dependent relative permeability in reservoir simulation studies.