| Numerous laboratory studies and increasing number of field tests have reported that oil recovery could be improved by adjusting the injection water salinity and composition in sandstones, which is commonly referred to as smart waterflood. Recently a number of publications pointed out that smart waterflood is also effective in carbonates. This technique is operationally similar to conventional waterflood, and economically cheaper than other EOR methods. Targeting at maintaining oil production plateau for a tight carbonate formation in U.A.E., the smart water flood was proposed. In addition, since early-stage investigation has verified that CO2 injection in this formation possesses great potential for oil recovery enhancement, in this study, the brine chemistry effect on CO2 injection has also been approached.;In this work, potential of smart waterflood for our objective formation was experimentally investigated under different conditions. Remarkable additional oil recovery, ranging from 8% to 17%, was observed in low temperature (158°F) corefloods when sequentially diluted seawater was injected after secondary seawater slug. In addition, corefloods and spontaneous imbibition test showed that lowering injection water salinity is more effective than increasing the sulfate concentration in injected brine with respect to incremental oil recovery at low temperature. Corefloods under typical reservoir conditions (T=248°F and P=3000psi) illustrated that both diluting the formation water and raising the sulfate concentration in injected seawater could trigger considerable extra oil recovery (around 25%) after secondary formation water flooding. However, one of the corefloods using composite cores under reservoir conditions showed very limited response to sequentially diluted aquifer water slugs after secondary high-salinity aquifer brine injection, which may manifest the complex and unpredictable traits with this technique. For these corefloods, oil production was frequently accompanied with pressure difference increase during tertiary low salinity water injection process, which might be related to fines migration, temporary formation of oil/brine emulsion, and wettability alteration to be less oil-wet. Wettability monitoring at 194°F on core plates demonstrated that significant water-wetness enhancement could be achieved by either lowering the salinity or increasing the sulfate concentration of the surrounding brine, which implies wettability alteration is one of the key mechanisms for smart waterflood in carbonates. However, the water hardness exhibited very limited effect on rock wettability alteration.;Brine salinity effect on CO2 injection was only approached by theoretical studies in this work. Correlation studies showed that at our typical reservoir conditions, lowering brine salinity could significantly enhance the CO2 solubility in brine, which can lead to great variation of the CO2-brine system properties and consequently would undoubtedly impact CO2 injection performance. According to a simple mathematical modeling, it was perceived that reducing brine salinity could considerably reinforce the capacity and speed of CO2 diffusion through water, which would be immensely beneficial to water-isolated oil recovery during CO2 injection process. By conducting compositional reservoir simulation using real PVT and hypothetical geological models, it was noticed that elevating CO2 solubility in injected brine by decreasing brine salinity could promote oil recovery appreciably during carbonated water injection process. Moreover, simulation results illustrated that the performance of carbonated water injection far outweighed that of the unadulterated waterflood in terms of oil recovery. |
