Injection of water for pressure maintenance and waterflooding applications is becoming an increasingly important issue. Historically, the total suspended solids of the water were given more consideration rather than the total dissolved solids. The water from injection wells physically sweeps the displaced oil to adjacent production wells. Displacement of the oil is highly affected by many interacting variables. Wettability has been recognized as one of the controlling parameters of the remaining oil-in-place. Brine salinity, oil chemistry, and rock lithology are believed to play a significant role on altering rock wettability. Recent studies highlted that low salinity water can increase oil recovery in carbonate reservoirs.
This paper highlights extensive wettability studies to determine the optimum brine salinity, which results in higher oil recovery. Contact angle and Amott imbibition methods are considered as the most common methods to measure the preferential affinity of reservoir rocks. Crude oil, formation core samples (dolomite, and calcite), and synthetic brines from Middle East (formation, aquifer, and seawater) are used to evaluate wettability quantitatively, and qualitatively. All experiments were conducted at high pressure (up to 2,000 psia), and elevated temperature (up to 270°F).
Contact angle decreased with pressure, and temperature upto 194°F. The optimum salinity is found that can enhance the rock wettability toward water-wet. Currently, there is confusion concerning the optimum brine salinity for injection wells. The results of this study give a new insight on the optimum salinity and provide better understanding of some wettability challenges in carbonate reservoirs.