Jitendra Sangwai

Production of crude oil from a matured oil reservoir is challenging due to the low recovery factor. Hybrid methods have demonstrated potential in oil recovery from the matured crude oil reservoir. In recent years, the low salinity water with chemicals (viz., surfactant, polymer) and nanoparticles have brought the attention of the researchers due to their ability in altering the interfacial properties of the rock-oil-water systems favorable for crude oil recovery. The current interest by industries in injection fluid (i.e., low salinity water injection) has prompted the invention of a hybrid oil recovery agent for matured crude oil reservoirs. In the current study, a novel silica-based hybrid nanofluids (NFs) of variable silica nanoparticles (NPs) concentration in low salinity seawater with anionic surfactant (AOT: dioctyl sodium sulfosuccinate) and polymer (PVP–K30: polyvinylpyrrolidone) (sometimes referred to as SMART LowSal) are used as an injection fluid in a sand-pack reactor. Oil recovery from oil saturated sand-pack reactor is observed to enhance due to NFs (hybrid) injection after secondary recovery. The characteristic study of relative permeability curves discloses that sand surface was initially water-wet and converted to strongly water-wet in the presence of NFs. A nuclear magnetic resonance (1H NMR) study reveals that adsorption of the chemical appeared on the sand surfaces, which could be the reason for wettability alteration, and thereby enhanced oil recovery. Similarly, the scanning electron microscopy (SEM) and energy dispersive X-ray analysis (EDXA) of the sand samples before and after injection disclosed desorption of hydrocarbon from the sand surfaces after NFs injection. An additional 5–10% oil recovery is achieved after chemical flooding due to the injection of NFs. Adsorption isotherm study well agreed with the monolayer adsorption of surfactant on the sand surface.

Controlled salinity water flooding also known as engineered water flood has been tested as a potential enhanced oil recovery (EOR) method in laboratory as well as at pilot/field scale. However, there are cases seen where the method has failed to show its potential for EOR. Scientists believe that the lack of understanding of case specific underlying mechanism is the primary reason. Many of the literatures claims reduction of interfacial tension as the primary oil recovery mechanism; but recent findings highlighted that modification of electrical charges on rock surface with response to injection brine salinity has greater effect. In order to investigate the same and in search of more insightful mechanism, in this study we have designed and performed experiments with selected chemicals which can modify surface properties of sandstone and also the oil water interfacial tension. The electrical charge of the rock surface and oil–brine​ interfacial tension were modified by tuning salinity of injection water and adding surfactants (sodium dodecyl benzene sulfonate, SDBS and cetyltrimethylammonium bromide, CTAB). The electrical charge of the sandstone surfaces was quantified with zeta potential measurement. The oil recovery potential of the injection fluids was tested through laboratory core flooding experiments at controlled near reservoir conditions. Superposition of all the obtained results revealed that low salinity injection brine modifies the sandstone surface to higher negatively charged state than high salinity water. Therefore, with a negatively charged oil–brine interface it causes strong repulsive forces promoting detachment of residual oil and subsequent mobilization. The hypothesis is also proved by the fact that SDBS in spite of resulting in a lower interfacial tension reduction than CTAB yielded higher oil recovery. This is because of the negative zeta potential caused by SDBS to sandstone surface in comparison to the positive zeta potential observed in the case of CTAB.