Effects of pressure and wettability on residual phase saturation in sandstone rock A.S. Lackner ⁎ , O. Torsaeter Norwegian University of Science and Technology (NTNU), Norway Received 25 May 2004; accepted 7 March 2006 Abstract The nature of fluid distribution in porous media is among the least understood mechanisms when describing porous media statics and dynamics. Particularly for a three-phase flow, this is far from a revealed field of science. Because of unfavourable water injectivity, several reservoirs in the North Sea have been waterflooded while maintaining production pressure below the bubble point. One crucial parameter for this process is the critical gas saturation which has a great impact on the oil production. Both production pressure and fluid mobility control the amount and distribution of free gas in the system. Two-phase waterfloods and three-phase waterfloods with simultaneous pressure depletion were performed. The rock material was Berea sandstone and the fluids used were a recombined C 1 /nC 5 -mixture and brine and the experiments were performed at laboratory temperature and pressures ranging from 10–20 bar. To evaluate the effect of wettability on recovery, both water-wet and intermediate-wet cores, prepared by silanisation, were used. For the three-phase experiments, each core was waterflooded and simultaneously depleted by a fixed depletion rate to a unique constant back pressure below the initial bubble point of the binary mixture. The data analysis show that the recovery is dependent on the amount of gas liberated, and also on the wetting preferences of the core. The intermediate-wet cores give a higher recovery and the results indicate higher critical and residual gas saturation for intermediate- wet cores. © 2006 Elsevier B.V. All rights reserved. Keywords: Critical gas saturation; Wettability; Three-phase flow; Oil recovery 1. Introduction In many reservoirs, three mobile fluid phases are simultaneously present (Pejic and Maini, 2003) during production. Some examples of processes are water drive, steam drive, gas drive and solution gas drive. Because of experimental difficulties, limited data exist on these processes. Virnovsky (1985) extended the method for calculation of two-phase unsteady-state relative perme- abilities (Johnson et al., 1959) to three phases. However, this method can only give valid data when the capillary pressure is negligible. In reality, the capillary forces are important inside the reservoir and to reproduce a realistic laboratory experiment, this method is often not well designed to give valid relative permeability data. In the North Sea many reservoirs have too low injection capacity; the ratio of injection pressure to injection rate is very high. This problem is often run into when the absolute permeability of the rock is low combined with a water-wet rock that has low end point water relative permeability (Lien et al., 1998; Andersen et al., 2000). In these cases, to avoid an unsafe injection Journal of Petroleum Science and Engineering 52 (2006) 237 – 243 www.elsevier.com/locate/petrol ⁎ Corresponding author. Fax: +47 73 58 43 72. E-mail addresses: alsl@statoil.com (A.S. Lackner), oletor@ipt.ntnu.no (O. Torsaeter). 0920-4105/$ - see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2006.03.013