The Effect of Salinity and Salt Type on the Coalescence Time of Oil Droplets in Low-salinity Enhanced Oil Recovery

The mechanisms that enhance oil recovery through low-salinity waterflooding can be categorized into two main groups: fluid-fluid interactions and rock-fluid interactions. Fluid-fluid interactions have been less explored in the existing literature. One significant effect of these interactions is the maintenance or increase of oil phase connectivity, which boosts the relative permeability and production rate of oil from the reservoir. This research aims to deepen the understanding of these effects and their time scales by examining the coalescence of two adjacent oil droplets in presence of saline water. A novel device and method were developed in this study. In this method, two oil droplets (one hanging from the top and one from the bottom) are placed near the desired brine. After an aging period, they are brought together to initiate contact. The time it takes for the droplets to merge, known as the “coalescence time,” is recorded. The results show that coalescence time increases with aging time, however starts to stabilize after about 15 minutes. Additionally, the coalescence time of two oil droplets exhibits a nonmonotonic relationship with salinity, peaking at an intermediate salinity level. The maximum coalescence time occurs at lower ionic strengths in brines with divalent salts like calcium, magnesium, and sulfate compared to monovalent salts. The specific values for sodium chloride, magnesium chloride, calcium chloride, and sodium sulfate brines are 0.5, 0.05, 0.05, and 0.01 M, respectively. Ultimatly, this study indicates that there is an optimal salinity for the fluid-fluid effects in low-salinity waterflooding, and understanding these effects on oil recovery necessitates further waterflooding experiments.