An Experimental Investigation of WAG Injection Performance under Near-Miscible Conditions in Carbonate Rock and Comparison with Sandstone

Abstract In this study, the effect of rock type on two-phase and three-phase flow and displacements have been experimentally investigated as a part of a study on the performance of WAG injection in sandstone and carbonate rocks. A series of core flood experiments have been performed under reservoir conditions to investigate the effect of parameters pertinent to the performance of WAG injection. Clashach sandstone and Indiana limestone cores with almost similar porosity and permeability were selected for this work. To reduce the effects of experimental artifacts, large cores were used with diameter and length of 2 in × 2 ft respectively. To investigate the role of rock type, the WAG design parameters including injection order, injection strategy, and slug size were kept unchanged for the sandstone and carbonate rocks. Both core flood experiments were performed on water-wet cores and at near-miscible gas/oil IFT conditions. Comparison of our core flood experiments reveal that even though the waterflood efficiency was higher in carbonate core than in sandstone rock, the overall oil recovery performance by the alternation of water and gas injections in the sandstone rock outperformed its trend in the carbonate core. Ultimate oil recovery values of 88.35 % (IOIP %) and 71.0 % (IOIP %) were obtained for the sandstone and the carbonate cores, respectively. The results show that about 39.12 % (IOIP %) and 12.37 % (IOIP %) of additional oil was recovered by the alternation of water and gas injection in the sandstone and carbonate cores, respectively. Comparing the average saturation profiles in the cores revealed that the higher trapped gas saturation in sandstone rock had significantly enhanced its oil recovery performance, during the tertiary water and gas injections, compared with that in the carbonate rock. The results also revealed the impact of rock type on pressure drop and fluid saturation distribution.