Effect of temperature on two-phase gas/oil relative permeability in unconsolidated sands

Thermal Enhanced Oil Recovery (TEOR) for heavy oil reservoirs involves the simultaneous flow of oil and steam, mimicking the gaseous phase with an elevation in the temperature. While implementing the TEOR process, reservoir performance prediction tools require the water/oil and gas/oil relative permeability data. Many studies reported the temperature effect on two-phase water/oil relative permeability despite knowing that steam or vapor is conventionally injected, mimicking the gaseous phase during heavy oil recovery. Thus, this requires the knowledge of temperature effect on two-phase gas/liquid relative permeability as well. However, limited studies are reported in the literature regarding the temperature dependency of relative permeability in gas/liquid systems; offer no census about its effects. The scarcity of such studies in the literature is due to the lack of systematic experimental studies and complications observed while conducting the higher temperature tests to mimic the thermal EOR. Hence, the objective of this study was to examine the temperature effect on two-phase gas/liquid relative permeability at varying temperatures from 64 to 132 degrees C using a systematic and reliable experimental process. In this study, Poly Alpha Olefin (PAO-100) was used as the oleic phase, deionized water as the immobile phase, and nitrogen gas as the displacing phase in a clean unconsolidated sandpack under the confining pressure around 1000 psi. Furthermore, Johnson-Neumann-Bossler (JBN) method was opted to interpret the two-phase gas/liquid relative permeability curves from the displacement data, i.e., cumulative oil production and pressure drop measured across the sandpack. The experimental observation suggests that irreducible water saturation and endpoint oil relative permeability are temperature independent. The residual oil saturation decreased with the increase in temperature and led to a higher endpoint relative permeability to gas. On the other hand, the oil relative permeability at equal saturation uplifted, suggesting the enhanced mobility of oil through pores with increasing temperature. On the other side, the gas relative permeability at equal saturation was temperature insensitive other than at residual oil saturation. Also, the two-phase flow region increased with the rise in temperature as both the relative permeability curves shifted upwards, and the broader curve was observed. Hence, this study strongly suggests that the reservoir engineers or commercial reservoir simulators should account for the temperature effects on two-phase gas/oil relative permeability to efficiently predict heavy oil reservoir performance and management during the thermal enhanced oil recovery process (TEOR).