A Review on the Progress of Ion-Engineered Water Flooding <s> Early Studies on Low Salinity Water Flooding <s> The effect of aging and displacement temperatures and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This study is based on displacement tests in Berea sandstone with three crude oils and three reservoir brines (RB`s). Salinity was varied by changing the concentration of total dissolved solids (TDS`s) of the synthetic brine in proportion. Salinity of the connate and invading brines can have a major influence on wettability and oil recovery at reservoir temperature. Oil recovery increased over that for the RB with dilution of both the initial (connate) and invading brine or dilution of either. Aging and displacement temperatures were varied independently. For all crude oils, water wetness and oil recovery increased with increase in displacement temperature. Removal of light components from the crude oil resulted in increased water wetness. Addition of alkanes to the crude oil reduced the water wetness, and increased oil recovery. Relationships between waterflood recovery and rate and extent of oil recovery by spontaneous imbibition are summarized. <s> BIB001 </s> A Review on the Progress of Ion-Engineered Water Flooding <s> Early Studies on Low Salinity Water Flooding <s> Although attention is given to the composition of the injected brine in a waterflood with respect to compatibility with the formation, tests are not usually made to determine its effect on oil recovery. This study shows that the wettability and laboratory waterflood recoveries of crude oil/brine/rock (COBR) ensembles can be strongly dependent on brine composition and on related COBR interactions. The sensitivity of these interactions to temperature and crude oil composition is also demonstrated. <s> BIB002 </s> A Review on the Progress of Ion-Engineered Water Flooding <s> Early Studies on Low Salinity Water Flooding <s> In this work, coreflood studies were carried out to determine the recovery benefits of low salinity waterflood compared to high salinity waterflood and the role of wettability in any observed recovery benefit. Two sets of coreflood experiments were conducted; the first set examined the EOR potential of low salinity floods in tertiary oil recovery processes, while the second set of experiments examined the secondary oil recovery potential of low salinity floods. Changes in residual oil saturation with variation in wettability, brine salinity and temperature were monitored. All the coreflood tests gave consistent increase in produced oil, corresponding to reduction in residual oil saturation and increase in water-wetness (for the second set of experiments) with decrease in brine salinity and increase in brine temperature. <s> BIB003 </s> A Review on the Progress of Ion-Engineered Water Flooding <s> Early Studies on Low Salinity Water Flooding <s> The idea of injecting low salinity water into a petroleum reservoir is not novel and was often used in the 70s prior to the injection of surfactant. Recently it was shown that simply injecting sufficiently low salinity water improves oil recovery. Many possible mechanisms concerning low-salinity waterflood have been proposed in the literature. This paper describes an experimental investigation into some of the factors controlling the increased oil recovery observed when low salinity brine is injected into oil saturated reservoir core samples. Extensive chemical analyses were performed on the effluent showing the extent of interaction between the injected brine, the oil and the rock matrix. <s> BIB004 </s> A Review on the Progress of Ion-Engineered Water Flooding <s> Early Studies on Low Salinity Water Flooding <s> Both laboratory and single well field tests have documented that enhanced oil recovery can be obtained from sandstone reservoirs by performing a tertiary low saline waterflood. Due to the complexity of the crude oil-brinerock interactions, the mechanism behind the low saline EOR process has been debated in the literature for the last decade. Both physical and chemical mechanisms have been proposed, but it appears that none of the suggested processes has so far been generally accepted as the main contributor to the observed low salinity EOR effect. Based on published data and new experimental results on core flooding, effects of pH and salinity on adsorption of acidic and basic organic components onto different clay minerals, clay properties like ion exchange capacity and selectivity, and oil properties, a new chemical mechanism is suggested, which agrees with documented experimental facts. At reservoir conditions, the pH of formation water is about 4 due to dissolved acidic gases like CO2 and H2S. At this pH, the clay minerals, which act as cation exchange material, are adsorbed by acidic and protonated basic components from the crude oil, and cations, especially divalent cations, from the formation water, like Ca. Injection of a low saline fluid, which promotes desorption of Ca, will create a local increase in pH close to the brine-clay interface because Ca is substituted by H from the water. A fast reaction between OH and the adsorbed acidic and protonated basic material will cause desorption of organic material from the clay. The water wetness of the rock is improved, and increased oil recovery is observed. To observe low salinity EOR effects in sandstones, a balanced initial adsorption of organic components and Ca onto the clay is needed. Both the adsorption capacity and the pH-window for adsorption/desorption of organic material is somewhat different for various types of clay minerals. A detailed knowledge of the chemical mechanism behind the low saline EOR process together with information on formation brine composition, oil properties and type of clay material present, will make it possible to evaluate the potential for increase in oil recovery by a low salinity waterflood. Introduction A great number of laboratory tests by Morrow and co-workers (Tang and Morrow, 1999a; Tang and Morrow, 1999b; Zhang and Morrow, 2006; Zhang et al., 2007b) and also by researchers at BP (Lager et al., 2007; Webb et al., 2005a; Webb et al., 2005b) have confirmed that enhanced oil recovery can be obtained when performing a tertiary low salinity waterflood, with salinity in the range of 1000-2000 ppm. Based on 14 tests from different sandstone reservoirs, Lager et al. (Lager et al., 2007) have reported that the average increase in recovery was about 14%. The laboratory observations have even been confirmed by single well tests performed in an Alaskan reservoir (Lager et al., 2008b). As increasing amounts of laboratory experiment results have been published in the last decade, various suggestions of the mechanism behind the low salinity process have appeared. Unfortunately, none of the suggested mechanisms have so far been generally accepted as the “true” mechanism. The reason is that many parameters linked to the rock, to the reservoir fluids (oil and brine), and to the injection fluid are involved. In order to give the reader a good background to understand the proposed mechanism in this paper, a list of the accepted experimental conditions is given, followed by a short recap of the previously suggested mechanisms. Conditions for low salinity effects The listed conditions for low salinity effects are mostly related to the systematic experimental work by Tang and Morrow (Tang and Morrow, 1999a), but some points has also been taken from the work by BP (Lager et al., 2007; Lager et al., 2008a). <s> BIB005
The first study on the effect of reduced salinity on water flood oil recovery was performed by Bernard  , in which he reported the effect of saline water and fresh water on oil recovery in core plugs containing hydratable clays. From this study, the author concluded that more oil was recovered from fresh water flooding than from brine flooding. According to the author, higher oil recovery from fresh water flooding was due to two mechanisms. First, the clay swelling in contact with fresh water, which leads to squeezing of the oil out of the pores; and second is the fines migration as a result of dispersed clays attached with the fine oil droplets. The migration of fines causes plugging of flow channels which may alter or create new channels. The proposed mechanism was explained by several core flood experiments, using fresh water and brine separately as well as by sequential injection, to investigate the effect of salinity on clay swelling and migration. After a gap of few decades, Tang and Morrow BIB001 initiated studies on the effect of salinity of injected brine and temperature on the wettability of the rock and oil recovery. From results of imbibition experiments, they found that, for crude oil, brine, and rock interactions, the more diluted the brine, the slower the initial recovery and higher the final oil recovery. Increase in oil recovery by decreasing brine salinity was observed for water flooding experiments as well. The same conclusion of slow recovery at initial stage of flooding and higher recovery from final flooding of low salinity brine was made by Zhang and Morrow  . Another important observation was the strong impact of rock wettability on oil recovery. The recovery efficiency of low salinity water in sandstone reservoirs is demonstrated by laboratory experiments of several other researchers such as Morrow et al.  , Morrow et al. BIB002 , Zhang and Morrow  , and Agbalaka et al. BIB003 ; all of them came to the conclusion that, by decreasing the salinity of injected brine, the oil recovery factor could be enhanced. The possible mechanisms of low salinity water work differently in sandstone and carbonate rocks. Austad et al. BIB005 gave a detailed description on the microscopic activities occurring when low salinity water is injected to sandstone reservoirs. Though it was assumed that the wettability alteration is the main reason for low salinity water effect, other mechanisms suggested by different investigators are not ruled out. The possible mechanisms suggested by various authors are fines migration, fluid flow due to osmotic pressure caused by salinity gradients, pH increase, multicomponent ion exchange (MIE), and electric double layer expansion, in addition to the contribution from IFT reduction. According to Austad et al., when low salinity water is injected into the reservoir, the initial chemical equilibrium in the reservoir is disturbed and Ca 2+ ions are replaced by H + ions which leads to an increase in pH of the system. This phenomenon is due to the high attraction of H + ions towards the clay surface. With desorption of cations from clay surface the polar components of oil which are attached to reservoir minerals will also be removed from the clay surface since it is very sensitive to pH changes. The concentration changes of Mg 2+ and Ca 2+ with changes in the brine pH are also observed in these experiments. However, Lager et al.  concluded from geochemical analysis of the core flood effluent that, during injection of low salinity water into the carbonate formation, the polar compounds of oil will be detached from the rock surface and replaced by cations such as Mg 2+ and Ca 2+ . This activity is related to multicomponent ion exchange (MIE) that causes the wettability alteration of the rock. Another conclusion from their research is that the increase in oil recovery is not related to an increase in pH, because of some evidences from other studies showing improved oil recovery at lower pH  . Lager et al. BIB004 further confirmed that MIE is a responsible mechanism of increase in oil recovery on the field scale. The oil recovery increased dramatically by injection of low salinity water. Produced water showed total removal of Mg 2+ from the injected water which proved strong interaction in the brine/rock system.