Experimental investigation of divalent ions and CTAB effects on heavy oil emulsion stability in carbonate reservoirs.

Low-salinity water injection can boost oil extraction but often triggers asphaltene instability, leading to damaging emulsions and clogging in carbonate reservoirs. This research explores a solution by combining ion-tuned brines with a cationic surfactant (cetyltrimethylammonium bromide (CTAB)) to manage these effects. We specifically examine how the ionic composition of injected water, when mixed with CTAB and reservoir rock particles (calcite), governs emulsion behavior and oil recovery potential. A series of laboratory experiments simulated reservoir conditions by mixing heavy crude oil with various brines and calcite particles. Key experimental evaluations were performed, including measurements of interfacial tension (IFT), emulsion fraction and separation time, changes in rock surface wettability, and analyses by Fourier-transform infrared (FTIR) spectroscopy, zeta potential, and SARA (Saturates, Aromatics, Resins, and Asphaltenes). The result showed that brines enriched with sulfate ions, in combination with CTAB, resulted in the most favorable outcome. This system reduced the interfacial tension to 5.5 mN/m, whereas the magnesium-modified seawater in the presence of CTAB achieved only about 20 mN/m. Furthermore, the sulfate-CTAB mixture altered the calcite surface toward a more water-wet condition, a change that plays a critical role in enhancing the displacement of trapped oil. The emulsion analysis showed that using sulfate-enriched seawater in the presence of calcite particles and CTAB reduced asphaltene precipitation and produced less stable emulsions that break more easily. This helps lower the chance of formation damage. In contrast, brines high in magnesium or calcium cations promoted the formation of rigid asphaltene complexes that stabilized emulsions and hindered oil mobilization. SARA and zeta potential results showed that in the aged oil-(SW10d.4SO₄) system (the oil was exposed to sulfate-enriched seawater in the presence of CTAB and calcite), the less-negatively charged oil components tended to migrate. In contrast, cation-rich brines interacted more strongly with the negatively charged asphaltenes, removing them preferentially over the less-polar components and resin fractions. The FTIR-derived indices clearly indicated that different brine compositions in the presence of CTAB and calcite particles influenced the contribution of various oil components to the fluid-fluid interfacial interactions. The long chain index (LCI), representing less-polar hydrocarbon groups, showed the lowest value in aged oil-(SW10d.4SO₄), consistent with the migration of these fractions. Meanwhile, in the aged oil-(SW10d.4Mg) system (oil exposed to magnesium-enriched seawater with CTAB and calcite), the polar aromatic (PA) index and the aliphatic index (ALI) reached 0.366 and 0.193, respectively. This indicates the preferential migration and removal of more polar functional groups under cation-rich conditions. Tailoring the injected water with sulfate and surfactant gives two benefits. It improves oil recovery by changing rock-fluid interactions and it keeps operations efficient by reducing problematic emulsion formation.