Low-salinity water injection for EOR applications and for shale and tight sand fracturing has become a widely accepted approach. Experimental and modeling work is slowly unraveling the complexity of this system, with no unified theory to explain the fundamentals behind it. Our work adds a new spin to the topic, where the non-monotonic impact of salinity on contact angle reported in literature is linked to its non-monotonic impact on the properties of the water-oil interface.
We used a crude oil sample that originated from a field in Texas to create surfactant-stabilized brine-in-oil emulsions. We synthesized different brine systems starting from deionized water using two different salts, NaCl and CaCl2 at 8.55, 85.5 and 855 mMol/L. We quantified the stability of the emulsion using both gravimetric and centrifuge methods. We measured the variation in the viscosity of the emulsion for different brine fractions from 10 to 50 wt%.
The results show a different effect of salt on stability for different values of water-cut. This effect can range from a stability being directly proportional to salt concentration in one case, to being inversely proportional to salt concentration in the other case, including a scenario where a non-monotonic impact is recorded.
The work provides a comprehensive and detailed set of experiments on various measurements relating to the brine-oil interactions away from the influence of rock minerals. It shows similar trends to what is reported in the literature on experiments and simulations where carbonate and sandstone rock minerals are included. This brings to question some of the theories that are used to explain this behavior given that the complexity is evident even without the rock presence.