Effect of Temperature on Gas/Oil Relative Permeability in Viscous Oil Reservoirs

Abstract

Abstract Oil displacement tests were carried out in a 45-cm long sand-pack at temperatures ranging from 64 to 217 °C using a viscous 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 assess the effect of temperature on gas/oil relative permeability in viscous oil systems. We employed a new systematic algorithm to successfully implement a history matching scheme to infer the two-phase gas/heavy oil relative permeabilities from the core-flood data. We noted that at the end of the gas flooding, the "final" residual oil saturation still eluded us even after tens of pore volumes 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. A history-matching technique was used to determine the uncertain parameters of the oil/gas relative permeability curves, including the two exponents of the extended Corey equation (N° and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted. The remaining four parameters (i.e., Corey exponents, true residual oil saturation and gas endpoint relative permeability) were obtained from history matched 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.