Abstract
After large-scale and long-term waterflooding, reservoir physical properties such as the pore throat structure and rock wettability may change. In this paper, the relative permeability curves under different water injection volumes through core-flood experiments were used to characterize the comprehensive changes of various reservoir physical properties at high water-cut stage. The novel concept of “water cross-surface flux” was proposed to characterize the cumulative flushing effect on the reservoir by injected water, and a novel method for inverted five-spot reservoir simulation at high water-cut stage based on time-varying relative permeability curves was established. From the relative permeability curves measured through two cores from the X oilfield under different water injection volumes (100, 500, 1000, 1500, and 2000 PV), it is found that with the increase of injected water volume, the two-phase co-flow zone becomes wider, the water permeability under residual oil saturation increases, and the residual oil saturation decreases. A waterflooding core model was established, simulated, and verified by the method proposed in this paper. It is found that using time-varying permeability curves for simulation, the highest oil recovery factor (61.58%) can be obtained with injected water volume up to 2000 PV, and the purpose of improved oil recovery (IOR) can be achieved by high water injection volume, but the increment is only approximately 10%. Besides, a waterflooding model of an inverted five-spot reservoir unit based on the X oilfield was also established, simulated, and analyzed. Simulation results have shown that no matter which set of core permeability curves measured from 100 to 2000 PV is directly used alone, the oil recovery factor will be simulated inaccurately. The findings of this study can help in better understanding the quantitative description of the oil recovery changes with time-varying reservoir physical properties in high water-cut reservoirs during waterflooding.
Highlights
Waterflooding is by far the most widely applied method in improving oil recovery.[1−7] large-scale and long-term water injection will cause reservoirs to enter the high water-cut stage, even the extra-high water-cut stage, and the yield will seriously drop in the meantime.[8−11] For decades, the oilfield development industry in China has gradually formed a technology series featuring water injection technology.[12]
According to the simulation results, it is apparent that the purpose of improved oil recovery (IOR) can be achieved by high water injection volume, but the increment is only approximately 10%, and the main growth stage of oil recovery factor is still concentrated upon the low water injection volume stage (
Based on time-varying relative permeability curves, this paper proposed, validated, and applied a simulation method for an inverted five-spot reservoir at high water-cut stage
Summary
Waterflooding is by far the most widely applied method in improving oil recovery.[1−7] large-scale and long-term water injection will cause reservoirs to enter the high water-cut stage, even the extra-high water-cut stage, and the yield will seriously drop in the meantime.[8−11] For decades, the oilfield development industry in China has gradually formed a technology series featuring water injection technology.[12]. Many scholars[15−23] have found that after large-scale and long-term waterflooding, reservoir physical properties such as the pore throat structure and rock wettability may change, leading to the increase of displacement efficiency and the decrease of residual oil saturation, which can usually improve the development effect on reservoirs. Through a number of waterflooding experiments on different types of cores, Loahardjo et al.[24] confirmed that in the process of sequential waterflooding, the residual oil saturation decreased significantly from one flood to the next. Loahardjo et al.[25] demonstrated the systematic decrease of residual oil saturation during sequential waterflooding by nuclear magnetic resonance imaging measurements of in situ saturations. Laboratory tests on sandstone and limestone showed that, even without changing the salinity, the oil recovery increased from one Received: March 27, 2020 Accepted: May 19, 2020 Published: May 28, 2020
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