A Review on the Progress of Ion-Engineered Water Flooding <s> W e t t a b i l i t ya l t e r a t i o n , Y o u s e fe ta l .[ 4 ] <s> Low-salinity waterflooding has been used to improve oil recovery for many decades. Several theories regarding the mechanism of low-salinity flooding have been discussed in the literature including interfacial tension reduction, wettability alteration, change in pH value, emulsion formation, and clay migration. This work presents the results of flooding tests on selected carbonate core samples taken from Bu Hasa field in Abu Dhabi using sea water and two field injection waters, Um-Eradhuma (UER) at 197,357 ppm and Simsima at 243,155 ppm. These results were used to evaluate the effects of brine salinity and ionic composition on the possible interactions of limestone rock/brine/and oil system and to identify the oil recovery mechanism. The field injection waters were diluted to salinities of 5,000 and 1,000 ppm and the optimum salinity was determined and then modified by varying the sulfate and calcium ion concentrations. Wettability alteration was determined by contact angle measurements. Interfacial tension measurements of the studied systems were also performed in an attempt to evaluate the flow mechanism with low-salinity flooding. The experimental results revealed that a significant improvement in the oil recovery can be achieved through alteration of the injection water salinity. Reducing the salinity of UER water from 197,357 to 5,000 ppm resulted in an improvement of oil recovery from 63 to 84.5 % of OOIP and the latter salinity was used to evaluate the impact of changing the sulfate and calcium ion concentrations on oil recovery. Results also indicated that sulfate concentration has a significant effect on the flooding process and that increasing the sulfate concentration beyond some optimum concentration of 46.8 ppm resulted in a negative effect on the flooding process. Contact angle measurements indicated that lowering the solution salinity could shift the wettability of the system towards intermediate wettability levels and that the UER water exhibits higher shift toward intermediate wettability compared to other waters. Results also indicated that there is no clear correlation between the improvements in oil recovery and interfacial tension and the pH of the studied systems. The results of this work are useful for people working in this field. <s> BIB001 </s> A Review on the Progress of Ion-Engineered Water Flooding <s> W e t t a b i l i t ya l t e r a t i o n , Y o u s e fe ta l .[ 4 ] <s> in the oil industry today. Almost all the conventional reservoirs go through a waterflood cycle to recover a portion of the remaining oil after pressure depletion. A considerable amount of oil still remains trapped underground, however, even after secondary waterfloods. This is attributed to inefficient macroscopic sweep and the microscopic capillary trapping caused by interfacial and surface forces that retain the oil within the pores. Currently, the oil industry is showing great interest in improved enhanced oil recovery (EOR) technologies to either maximize the ultimate oil recovery by waterflooding or recover additional oil from the residual oil left behind after waterflooding. The chemical properties of the injected water initially were not considered in the design of a waterflooding project except for the purpose of preventing formation damage triggered by an incompatibility between injected and formation waters. In recent years, extensive research into both sandstone and carbonate reservoirs has shown that tuning the salinity and ionic composition of the injected water can favorably affect oil/brine/rock interactions, alter rock wettability, enhance microscopic displacement efficiency and eventually improve waterflood oil recovery. As reported in other work, we refer to brine with a designed composition as “SmartWater” and to the waterflooding process governed by increased oil recovery as “SmartWater Flooding.” Unlike conventional EOR, SmartWater Flooding can be implemented at any time during the life cycle of a reservoir, and with minimal investment in current operations it can potentially provide higher <s> BIB002
Contact angle measurements, NMR studies. core flooding Rock surface become more water wet by diluting injected sea water, 18% additional oil recovery after secondary stage with sea water.   Zeta potential studies By decreasing the pH of LSW, the electric charges of oil/brine and rock/brine surfaces changed from highly negative to close to zero value, which means that the expansion of EDL was reduced. 14 IFT reduction Yousef et al.  IFT studies Salinity of injected brine has minor impact on the IFT and fluid-fluid interactions. recovery beyond sea water recovery. Therefore, the salinity and ionic composition of the brine has significant effect on brine/rock/oil interaction, wettability, and microscopic displacement efficiency. Another core flooding experiment was conducted by the author in order to study the effect of dilution of sea water. After plain sea water injection, injection of two times and ten times diluted sea water resulted in significant oil recovery (7% and 9% of OOIP, resp.). However, twenty times diluted sea water and hundred times diluted sea water injection resulted in 1.6% and 0% additional oil recovery. Romanuka et al.  presented the results of the screening experiments of low salinity water on different carbonate rocks through capillary imbibition tests in Amott cells. The oil production was compared between formation water and wettability modifying brines where ionic compositions and ionic strengths were altered. Higher oil recovery was observed by injecting lower ionic strength brine. The authors performed wettability modification with two approaches: by increasing the concentration of surface interacting ions (SO  2− , BO 3 3− or PO 4 3− ) and by lowering the ionic strength of brines. The results indicated that, by lowering the ionic strength of the brine, the oil recovery can be increased in carbonate rocks. This behavior is possibly due to the wettability alteration towards more water wetness. Al-Harrasi et al.  conducted laboratory experiments on LSW effect on carbonate rocks through spontaneous imbibition and core flooding experiments. They used brines with different dilutions of formation water from two to hundred times in their experiments. All of these brines improved the oil recovery. From spontaneous imbibition, as the salinity of brine is reduced, the oil recovery increased with highest recovery observed for hundred times diluted brine. These results let the authors to believe that low salinity water leads to wettability alteration. Another experiment was conducted to study that the effect of LSW is core flooding. In order to avoid capillary end effect and lowering IFT between oil and brine, they first flooded the core with high salinity water at high flow rate and then switched to low salinity brine. The results of the flooding tests showed 3-5% increase in recovery after injection of one pore volume of low salinity brine. From IFT studies, the authors found that there was a little change in IFT between brines and oil which cannot be considered as a significantly contributing mechanism of LSW. They concluded that, from experiments of spontaneous imbibition and core flooding, the wettability alteration is the main mechanism for improved oil recovery by LSW in carbonate rocks. A research study on low salinity water injection with different values of salinity and concentration of SO  2− and Ca 2+ ions on carbonate rocks was conducted by Al-Attar et al. BIB001 . Using the cores, sea water and injection water from Middle East region in a flooding unit, they found that, with decreasing salinity, the oil recovery increased dramatically up to 84% OOIP. Then, to study the effect of different ion compositions they used the most promising salinity brine. First, they saturated the brine with different concentrations of SO  2− . From SO 4 2− concentration studies, they concluded that, with increasing sulfate concentration in the brine, more oil recovery was observed up to the critical saturation above which the recovery decreases. By increasing the sulfate concentration up to four times, the oil recovery increased up to 87.2% OOIP, while the brine with six times sulfate resulted in oil recovery 61.5% OOIP. However, with increasing calcium concentration, they observed a reduction in oil recovery which means that calcium ions might have some negative effect. To establish the possible mechanism for improving oil recovery, the authors conducted several other experiments. Contact angle studies suggest that, with decreasing salinity, the rock surface wettability tends to change to more mixed wet state. Interestingly, from this study the authors could not state any correlation between IFT and oil recovery, which means that the change in IFT does not affect the oil recovery much. The same conclusion has been made for pH values, stating that there is no correlation between different pH values and oil recovery. Also they compared the performance of composite core flooding, which indicated that there is a good match with short core plugs which means that the results can be applied to field scale. Alameri et al.  conducted laboratory studies on the effect of low salinity water on oil recovery with and without 6 Journal of Petroleum Engineering surfactant. Whole experimental studies consisted of core flooding apparatus, ultrafast centrifuge, and contact angle apparatus to determine the possible mechanisms of low salinity water in carbonate rocks. The core flooding experiments showed that omitting NaCl from sea water increased oil recovery by 8% and by diluting the sea water two and four times, oil recovery resulted in 6.0% and 1.1% additional oil recovery, respectively. From contact angle studies, they found that with the reduction of salinity both aged and unaged carbonate rock surface became more water wet both with and without the surfactant addition. Al Quraishi et al.  conducted several experiments on low salinity water in carbonate reservoirs including core flooding, zeta potential, and contact angle studies. The core flooding studies as a tertiary recovery process resulted in 17% OOIP recovery by diluting the brine up to 10 times after 64% oil recovery from secondary flooding. The core flooding studies as a secondary recovery resulted in 74% OOIP cumulative recovery by ten times diluted SW while flooding with sea water alone showed 64% OOIP recovery. Increase in oil recovery by low salinity water flooding was explained by the authors as a result of wettability alteration. From contact angle measurements they found that the wettability of the rock surface changes towards more water wet condition. In the presence of formation water, the contact angle was 102 ∘ , which is intermediate wet. The sea water and twice diluted sea water showed slight changes of contact angel to 98 ∘ and 95 ∘ , respectively. However, the most significant change towards water wet condition was observed with 10 times diluted sea water and the contact angle dropping to 70 ∘ . In order to enlarge the understanding of the mechanism behind low salinity water in carbonate rocks, the authors performed zeta potential studies. By diluting and changing the ionic composition of brines, the overall surface charge approaches more negative value, with significant negative charge at 10 times diluted sea water. From the explanation of the author, the results from core flooding, contact angle, and zeta potential experiments are strongly related to wettability change of carbonate rock surface from intermediate to more water wet surface. The effect of individual PDIs (Ca 2+ , Mg 2+ , and SO 4 2− ) together with other common ions such as Na + and Cl − on carbonate rocks was studied by Kwak et al. BIB002 . This research was performed by NMR (Nuclear Magnetic Resonance) studies to see the chemical and physical behaviors of brine and rock surface only and oil/brine/rock interactions were not included. The results from brine/rock interaction studies are useful in multiphase studies on oil/brine/rock interactions. From experimental works, the authors stated that, among three PDIs, Mg 2+ and SO 4 2− ion's reactivity is stronger than Ca 2+ ion's reactivity. When these ions come into contact with the formation, the surface relaxivity on NMR changes due to the rock/brine interaction. Individual input of these three ions differs on NMR T2 response. When Ca 2+ and Mg