Abstract
Abstract More than half of the oil discovered in existing oil reservoirs is left behind after primary and secondary recovery. It is essential to increase oil recovery from existing fields to meet future oil demand. The injection of solvents, an established enhanced oil recovery (EOR) technique, has shown significant improvement in oil recovery over conventional water floods. However, injection of pure solvent slugs is expensive for field operators. To mitigate this problem, recent literature has proposed the use of brines that are saturated with mutual solvents (which dissolve in both oil and water phases). In this paper, we investigate the behavior of two mutual solvents, carbon dioxide (CO2) and diethyl ether (DEE). We have performed several core-floods in sandstone and carbonate cores. Injecting CO2-rich brine (carbonated water) into sandstone cores did not improve oil recovery. However, there was an improvement in oil recovery as a result of carbonated water injection in carbonate cores, which also displayed significant plugging during the experiment. There was also a noticeable improvement in oil recovery in the case of DEE-rich brine, but without any plugging issues. Mutual solvents dissolved in oil, swelled oil, and decreased oil viscosity which mobilized the oil. The experimental work was corroborated with numerical modeling to reproduce the results of both the solvents. Although the simulator is capable of handling rock–fluid interactions, such as mineral dissolution, the exact nature of the grain mobilization and pore-throat plugging was not incorporated in the numerical model. As a result, the simulator was unable to fully mimic the experimental observations of carbonated water floods. In contrast, since there was no apparent nor significant rock-fluid interaction in the DEE-rich brine case, it was successfully matched by the simulator.
Published Version
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