Low Salinity Waterflood in Combination with Surfactant/Polymer; Effects of Kinetics and Brine Composition

Improving the oil recovery beyond what is possible by conventional methods is a topic of great interest, and the potential oil recovery for a field can be improved if unconventional methods are implemented. Reducing the salinity of injection water is known to be able to improve the oil recovery. This has been proven in numerous lab studies and some field tests, but the underlying mechanisms are not fully understood. More research is needed to be able to predict when an improvement in recovery can be expected, and how large the improvement would be with low salinity injection. This master thesis consists of experimental work carried out at Uni CIPR, and is a continuation of earlier research performed at Uni CIPR. The main goal has been to further study the influence on oil recovery by low salinity water, in addition to the effect of combining low salinity injection at reduced capillarity by injection of surfactants. Dynamic core displacement experiments have been performed for six Berea outcrop rocks with permeability of approximately 400 mD. Four of the six rocks were saturated with a North Sea crude oil and aged to shift the wettability to a less water wet condition. A mixture of crude oil and octane was used for the displacement experiments. Brine with different salinities has been injected into the cores. Injection of 3000 ppm NaCl and diluted seawater in both secondary and tertiary mode was performed. Two cores were tested to investigate if the mechanisms associated with lowsal could be slower than the timespan of a typical core flooding experiment. Two other cores were injected with water with oscillating salinity to test if a salinity shock could improve the oil recovery. The six cores were flooded with a surfactant solution in tertiary mode, followed by a polymer injection for mobility control. 3000 ppm NaCl was injected after the polymer solution. The results did show some response to lowsal for the aged cores, around 3-5 % increased production of original oil in place, but the two cores that had not been aged did not respond to lowsal. Low salinity surfactant flooding did improve the recovery factor from around 60 % to around 75 % of original oil in place. This was not as much as previous studies have shown, and the oil mobilization by surfactant flooding was less than expected from a capillary desaturation curve. Injecting a polymer solution after the surfactant injection, improved the ultimate recovery of oil, and the efficiency of 600 ppm HPAM seemed to be better than using 300 ppm