Abstract
Both experimental and field trials have shown that low salinity water (LS) injection produces incremental oil recovery. One of the major advantages of LS is that it lowers salinity, resulting in favorable conditions for the addition of chemicals such as surfactants to enhance oil recovery. Surfactant flooding can benefit from lower ionic strength as it becomes possible to use a large variety of surfactants which are not applicable at higher salinities. Lower surfactant adsorption at lower ionic strength reduces the need for using alkali. Surfactant injection can also be implemented at a lower concentration and probably without the need for a co-surfactant when used with LS water. These advantages may result in a cost-effective and more environmentally friendly chemical EOR.
In this investigation, laboratory surfactant flooding experiments were conducted with aged Berea sandstone cores. The samples were aged using a typical crude oil from the Norwegian Continental Shelf. In-situ brine contained both monovalent and divalent cations. The surfactant sodium dodecylbenzenesulfonate (SDBS) was used at concentrations of 0.05wt% and 0.2wt% to enhance oil recovery. In tertiary surfactant injection, low salinity surfactant (LSS) is injected after LS water and a high salinity water (HS) injected as the chase water after surfactant; however in after-tertiary surfactant injection the sequence was HS-LS-LSS. Combination of LS water with high salinity surfactant (HSS) was also investigated in two experiments with injection sequences of LS-HSS-HS and HS-HSS-LS. HS is waterflooding with the same salinity as in the HSS. HSS solution had ultralow interfacial tension with the crude oil.
LSS flooding with 0.2wt% SDBS concentration did not result in higher oil recovery than the flooding with 0.05wt% SDBS in tertiary LSS injection. Tertiary LSS injection had a better recovery than the after-tertiary LSS. Recovery by only surfactants in HS-HSS-LS was higher than that in LS-HSS-HS. However the whole injection in the latter had higher recovery than the former. All the results were reproduced through repeating experiments on a different type of Berea sandstone. Results were discussed in terms of ionic exchange between the rock and aqueous phase, surfactant retention and phase behavior. Interfacial tensions at different salinities were measured to find the optimal salinity before injection. Rock samples were characterized in micro scale using X-ray micro-CT, and the geometrical properties of pore and throat size distribution were extracted.
Maintaining optimal conditions of a multicomponent system during a dynamic flooding in alkaline-surfactant-polymer (ASP) is challenging. Produced oil and water by multiple chemicals is also expensive to treat. Improving performance of surfactant flooding by manipulating salinity and ionic composition of brine seems to be more convenient than designing and controlling a complex ASP injection.
