Abstract:
Water injection is a process to maintain reservoir pressure and to sweep remaining hydrocarbon toward a production well when primary recovery is not adequate. Recent studies suggested that injecting Low Salinity Brine (LSB) could yield additional oil recovery. LSB injection is simulated using CMG STARS in this study.
The results show that sensitivity of several parameters significantly affects the effectiveness of LSB injection in inclined sandstone reservoirs. LSB is assumed to be injected throughout the production period of reservoir. The result shows that LSB injection yields 5.1% to 7.7% of additional oil recovery factor compared to conventional waterflooding. Besides, the benefit of LSB injection is greater when formation water salinity is higher, reaching 15.2% to 16.7% when formation water is 100,000 ppm. The presence of mobile connate water, highly viscous oil, and oil-wet reservoir significantly reduces the ultimate oil recovery factor. Besides, unsuitable Corey-oil exponent leads to an error in simulation. The LSB slug size of 0.25 PV seems to be an optimal size, whereas LSB injection should be implemented from the first day of reservoir exploitation. Injection rate also significantly affects the oil recovery since the worst injection rate leads to water tongueing and hence, early water breakthrough is pronounced. Under the production conditions used in this simulation study, the dip angle of 45° is found as the best inclination that stabilizes the waterflood front and provides the best LSB injection result.
