Exploring the Limit of Low-Salinity Waterflooding in a Carbonate Reservoir With Low Total Acid Number Oil

Summary This paper presents a workflow for designing the optimal injection brine composition for an offshore carbonate reservoir. The crude oil from this reservoir has a very low total acid number (TAN of 0.01 mg KOH/g), leading to the expectation that injecting diluted seawater (SW) would be an ineffective enhanced oil recovery (EOR) fluid. To address this, we designed a water composition that maximizes electrostatic repulsion (total disjoining pressure) at the oil/rock interface. This was achieved by combining two surface complexation models (oil/water and calcite/water interfaces) to estimate surface potential, calibrated to represent the reservoir conditions, with the extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. The total disjoining pressure was calculated for more than 30 different brine compositions, and the composition demonstrating the highest value was selected. The optimized injection brine, termed “repulsive” water, was then evaluated in the laboratory for its oil recovery performance. Both spontaneous imbibition tests and coreflooding tests showed limited success with the repulsive water (RW), resulting in additional oil recovery factors of only 1–2%. We believe that the poor oil recovery results from insufficient repulsion at the oil/rock interface. Greater repulsion would be necessary for further oil recovery; however, this was not attained within the scope of this study. Additionally, injecting diluted SW also failed to yield promising oil recovery results. Based on these findings, we conclude that low-salinity waterflooding (LSW) is not a viable EOR option for the studied carbonate reservoir with a very low TAN. To the best of our knowledge, this is the first study to propose a workflow for designing the optimal injection water composition for LSW EOR using an electrokinetic approach.