Effect of Temperature on Two-Phase Gas/Oil Relative Permeability in Viscous Oil Reservoirs: A Combined Experimental and History-Matching-Based Analysis

Thermal enhanced oil recovery (TEOR) is the most widely accepted method for exploiting the heavy oil reservoirs in North America. In addition to improving the mobility of oil due to its viscosity reduction, the high temperature down in the hole due to the injection of the vapor phase may significantly alter the fluid flow performance and behavior, as represented by the relative permeability to fluids in the formations. Therefore, in TEOR, the relative permeabilities can change with a change in temperature. Also, there is no model that accounts for the change in temperature on two-phase gas/oil relative permeability. Further, the gas/oil relative permeability and its dependence on temperature are required data for the numerical simulation of TEOR. Very few studies are available on this topic with no emerging consensus on a general behavior of such effects. The scarcity of such studies is mostly due to experimental problems to make reliable measurements. Therefore, the primary objective of this study was to overcome the experimental issues and investigate the effect of temperature on gas/oil relative permeability. Oil displacement tests were carried out in a 45-cm-long sandpack at temperatures ranging from 64°C to 210°C using a viscous mineral oil (PAO-100), deionized water, and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to interpret the relative permeability curves for gas/heavy oil systems using the experimentally obtained displacement results. We noted that at the end of gasflooding, the “final” residual oil saturation (Sor) still eluded us even after several pore volumes (PVs) of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable. The complete two-phase gas/heavy oil relative permeability curves are inferred with a newly developed systematic history-matching algorithm in this study. This systematic history-matching technique helped us to determine the uncertain parameters of the oil/gas relative permeability curves, such as the two exponents of the Corey equation (No and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted, except these four parameters (i.e., Corey exponents, true residual oil saturation, and gas endpoint relative permeability) were interpreted from simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.