Effect of Temperature on Two-phase Oil/Water Relative Permeability under SAGD Conditions

The successful implementation of any thermal recovery process in heavy oil reservoirs for the enhanced oil recovery requires some indispensable information related to the multi-phase fluid flow characteristics under high-temperature and high-pressure conditions. The relative permeability is an essential element which is required to model the flow performance within porous media. The two- and three-phase relative permeability affect the fluid flow velocity as well as the pressure gradient profile and saturation profile within the oil reservoir during the water flooding or steam and gas flooding. In order to predict the flow performance in thermal recovery processes, in which the temperature changes with position and time, the change of two- and three-phase relative permeability with temperature should be considered. Although numerous researchers have previously studied the variation of relative permeability with temperature since mid-fifties, this issue is still unresolved and remains challenging. Moreover, many contradictory results associated with the temperature’s impact on relative permeability reported in the literature and the relative scarcity of available data points for heavy oil and bitumen systems under thermal recovery conditions make this issue very critical for a reliable analysis. The aim of this research was to comprehensively investigate the effect of temperature on two-phase oil/water relative permeability in different rock-fluid systems, especially for Athabasca bitumen. In this regard, a reliable rig was developed to include the necessary elements to measure the steady- and unsteady-state relative permeability of two-phase systems in unconsolidated sand more accurately. This study was carried out in four phases. As per our objectives, the empirical correlations for two-phase oil/water relative permeability curve characteristics as a function of temperature in different rock-fluid systems were proposed first based on data reported in the literature. In addition, a new data-driven model for two-phase oil/water relative permeability in heavy oil/sand systems was also developed based on the experimentally measured data points. In the second phase, the impact of temperature on two-phase oil/water relative permeabilites was assessed over a wide range of temperatures from 23o to 200 °C in a clean viscous oil/sand system using the unsteady-state approach. In the third phase, the clean viscous oil phase was replaced by an ultra-heavy viscous oil, Athabasca bitumen. In this system, the effect of temperaturet on the two-phase relative permeabilites was evaluated using several core flooding experiments within a temperature range of 70-220 °C under the SAGD pressure (i.e., 2760 kpa). Both steady-state and unsteady-state relative permeability measuring techniques were utilized. In the final phase of this research, a solvent-aided system was employed for the relative permeability measurement at high temperatures to assess the effect of temperature on relative permeability of a diluted Athabasca bitumen/water/sand system in the same temperature range that was used for the unaltered Athabasca bitumen/water systems. Moreover, interfacial tension (IFT) and contact angle measurements were carried out for all systems at different temperatures to evaluate any change in fluid-fluid and rock-fluid interactions with temperature. The history matching of displacement tests was conducted using a reservoir simulator developed in-house. The experimental results revealed that the relative permeability curves in a clean viscous oil/deionized water/sand were practically independent of temperature, even though the viscosity ratio dramatically reduced at higher temperatures. Furthermore, the reduction of IFT to less than one order of magnitude and a small variation in contact angle at higher temperatures were not enough to alter the relative permeability. In contrast to this clean system, the unsteady-state relative permeability to Athabasca bitumen and water was a strong function of the temperature. At higher temperatures, the endpoint relative permeability to water considerably increased as well as the true residual oil saturation decreased significantly. Moreover, the irreducible water saturation slightly increased and endpoint relative permeability to oil also revealed an increasing trend. The steady-state relative permeability curves demonstrated the same behavior as the unsteady-state relative permeability curves at higher temperatures. A reduction in IFT and contact angle (i.e., a shift towards increased water-wetness) were also observed for this system with increasing temperature. The results obtained from several isothermal core flooding experiments using diluted bitumen at different temperatures confirmed that the two-phase relative permeability curves were still temperature-sensitive; however, the effect of temperature on relative permeability was less pronounced in diluted bitumen systems containing 9 wt. % of n-hexane, in comparison with unaltered bitumen systems. Again, a reduction in IFT and contact angle of a smaller level compared to the unaltered bitumen was captured at increased temperatures in this study. Since commercial reservoir simulators often consider the relative permeability curves to be insensitive to temperature, we anticipate that the temperature-dependent relative permeability model developed in this research can assist reservoir simulators to more effectively predict the flow performance in TEOR processes, especially for Canadian bitumen in the future.

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