Novel Method for Inverted Five-Spot Reservoir Simulation at High Water-Cut Stage Based on Time-Varying Relative Permeability Curves

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.

An Evaluation of Water and Gas Injections with Hydraulic Fracturing and Horizontal Wells in Oil-Saturated Shale Formations

“…The object selected for modelling is a part of a reservoir with dimensions 1500 by 1500 meters and a production well positioned in the centre. As part of the reservoir pressure maintenance system (RPMS), four injection wells were added to the model according to a five-spot pattern (Davies & Silberberg 1968;Hofmann, Al-Obaidi & Kamensky 2021;Sun, Liu, Wang et al 2020) at equal spacing from the central well, with a grid density of 25 ha per well. In the design, the wells were expected to last 30 years.…”

Numerical Simulation of Time-Varying Characteristics in a High-Permeability Sandstone Reservoir: A Case of Gaoqian Southern Area

“…Water flooding is the most widely used method of improving the ultimate oil recovery (IOR) including artificial water flooding and natural water flooding [3][4][5][6][7][8][9]. However, in the process of water flooding development, the decrease of reservoir temperature and pressure and the change of fluid properties lead to the break of the equilibrium, which affects the development of the oilfield [10]. The erosion of injected water causes physical changes in reservoir structure, and the incompatibility between injected water properties and reservoirs causes chemical effects such as water swelling, crystallization, precipitation, and dissolution of special minerals in reservoirs [11].…”

The numerical simulation study on the dynamic variation of residual oil with water drive velocity in water flooding reservoir

“…The water cut of the oil field has been rising after a long period of water flooding development. Enhancing liquid for oil increment is an effective way to sustain stable production and improve recovery factors in the mid-late life of reservoirs developed by water flooding (Feng et al, 2013;Liu et al, 2017;Sun et al, 2020). Many scholars have found that increasing the displacement pressure difference can improve the oil displacement efficiency through microscopic displacement experiments by CT and microfluidic technology (Zhang et al, 2017;Zhu et al, 2017;Liu et al, 2021;Tan et al, 2022).…”