Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable.In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195 F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na þ , Ca 2þ , Mg 2þ , and SO 2À 4 ) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment.The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca 2þ , Mg 2þ , and SO 2À 4 ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

Waterflooding has been used for decades as a secondary oil recovery mode to support oil reservoir pressure and drive oil into producing wells. Recently, extensive experimental work has indicated that optimizing the salinity of the injected water is an enhanced oil recovery technique that improves oil recovery in sandstone and carbonate reservoirs. Ion interactions between formation water, crude oil, injection water, and rock surface are quite complex. The question is how the surface charge of the minerals of sandstone formation affects the waterflooding performance. In this study the zeta potential measurements are conducted for rock/brine interfaces using the Phase Analysis Light Scattering (PALS) technique. This work demonstrates the results of zeta potential experiments to evaluate the effect of electrical surface charge and double layer expansion for common sandstone minerals. Four sandstone rock types (Buff Berea, Grey Berea, Parker, and Bandera) with different clay contents are studied. In addition, several minerals such as quartz, carbonate (calcite and dolomite), clays (kaolinite, chlorite, and montmorillonite), micas (muscovite, biotite, and illite), feldspars (microcline and anorthoclase), and ilmenite are selected to perform this work. Various brines are tested including seawater, 20% diluted-seawater, 0.5 wt% NaCl, 0.5 wt% MgCl2, and 0.5 wt% CaCl2. Based on the results of 100 experiments we found that the monovalent cations are more efficient in increasing the absolute values of the zeta potential than the divalent cations at 25°C. Zeta potential becomes more negative while the salinity of the brine decreased. Changing the pH of the solution causes a significant alteration in charge of Buff Berea and Bandera sandstone particles and subsequently, the zeta potential values. The zeta potential of Bandera is more negative than that of Buff Berea at any condition of pH in the range of 5 and 10. It is observed from the results that most of the minerals tends to be more stable for 0.5 wt% NaCl solutions compared to 0.5 wt% CaCl2 and 0.5 wt% MgCl2 solutions. Feldspars surfaces charge are significantly influenced using 0.5 wt% NaCl, followed by micas and clays. The resulting zeta potentials for the dolomite and calcite minerals showed different trend from the other sandstone minerals for low-salinity brine. For dolomite, all the samples show positive zeta potentials at original pH. At low pH, dolomite shows small negative zeta potentials in 0.5 wt% NaCl.

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