Oil/water/rock wettability: Influencing factors and implications for low salinity water flooding in carbonate reservoirs

Wettability of the oil/brine/rock system is an essential petro-physical parameter which governs subsurface multiphase flow behaviour and the distribution of fluids, thus directly affecting oil recovery. Recent studies [1-3] show that manipulation of injected brine composition can enhance oil recovery by shifting wettability from oil-wet to water-wet. However, what factor(s) control system wettability has not been completely elucidated due to incomplete understanding of the geochemical system. To isolate and identify the key factors at play we used SO42-free solutions to examine the effect of salinity (formation brine/FB, 10 times diluted formation brine/10 dFB, and 100 times diluted formation brine/100 dFB) on the contact angle of oil droplets at the surface of calcite. We then compared contact angle results with predictions of surface complexation by low salinity water using PHREEQC software. We demonstrate that the conventional dilution approach likely triggers an oil-wet system at low pH, which may explain why the low salinity water EOR-effect is not always observed by injecting low salinity water in carbonated reservoirs. pH plays a fundamental role in the surface chemistry of oil/brine interfaces, and wettability. Our contact angle results show that formation brine triggered a strong water-wet system (35 degrees) at pH 2.55, yet 100 times diluted formation brine led to a strongly oil-wet system (contact angle=175 degrees) at pH 5.68. Surface complexation modelling correctly predicted the wettability trend with salinity; the bond product sum ([> CaOH2+][-COO-]+[> CO3-][-NH+]+[> CO3-][-COOCa+]) increased with decreasing salinity. At pH < 6 dilution likely makes the calcite surface oil-wet, particularly for crude oils with high base number. Yet, dilution probably causes water wetness at pH > 7 for crude oils with high acid number.