Nanoparticle-assisted surfactant formulation for high salinity and temperature conditions: Integrated laboratory evaluation of interfacial properties and wettability modification in carbonates

Adsorption and low resistance to high temperature and formation water salinity are among the challenges in applying surfactant-enhanced oil recovery. However, when combined with nanoparticles, surfactants can exhibit improved thermal stability, reduced adsorption onto rock surfaces, and enhanced performance in high-salinity environments. This study goes beyond conventional testing by systematically optimizing a nanoparticle-assisted surfactant solution tailored to the specific high-salinity and high-temperature conditions of the Pilaspi Formation to develop a region-specific EOR solution. It uses crude oil and formation water from the Kurdistan Region of Iraq. A series of experimental tests, including surfactant stability, interfacial tension (IFT), contact angle, spontaneous imbibition and coreflooding were performed at 1800 psia and 80°C. The IFT, stability and zeta potential results identified that the 0.5 wt% SiO 2 /1.5CMC-CTAB formulation was the optimum for IFT reduction and stability, exhibiting a zeta potential of -28 mV. Additionally, it reduced the IFT further by 83% compared to a 67% reduction achieved by the surfactant alone. However, a 1 wt% SiO 2 /1.5CMC-CTAB formulation is required to achieve the highest wettability alteration by reducing the contact angles from 170° to 41°. Furthermore, spontaneous imbibition tests demonstrated an oil recovery increase from 30.30% using formation water to 74.60% with 1 wt% SiO 2 /1.5CMC-CTAB surfactant. Lastly, the coreflooding test showed oil recovery improvements from 39.02% with formation water to 54.27% using 1 wt.% SiO 2 /1.5CMC-CTAB surfactant. These findings highlight that the powerful synergistic effect of nanoparticle–surfactant formulation is contingent upon formulation optimization, which remains a critical step to ensure maximum and consistent performance.