Abstract:

As waterflooding reservoirs continue to be developed, the conflicts in water flooding become more pronounced, with significant differences in the underground flow field, pressure field, and remaining oil saturation field. Conducting quantitative evaluation of flow field differences can effectively guide the optimization and control of underground flow fields, mobilize and exploit various types of remaining oil, and enhance the waterflooding recovery efficiency of the reservoir. The study analyzed the factors influencing flow heterogeneity, including static reservoir heterogeneity and dynamic factors such as fluid viscosity, well pattern, and artificial fractures. It highlighted the complexity of flow heterogeneity evaluation and emphasized the necessity of quantitative evaluation. Next, various methods for characterizing heterogeneity were compared, and the Lorenz coefficient was selected as a key parameter for characterizing flow heterogeneity. This coefficient is applicable to non-normally distributed data, ranging from 0 to 1, and can quantitatively characterize flow variability. Additionally, flow velocity, as the most intuitive representation of the flow field, was chosen as the computational indicator to develop a method for evaluating heterogeneity. From the parameter calculation results graph, the diagonal line with a slope of 1, where the Lorenz coefficient was 0, was referred to as the “completely homogeneous line,” indicating the absence of heterogeneity in the evaluated object. Conversely, the largest triangle formed by this diagonal line and the x or y axis, where the Lorenz coefficient was 1, was termed the “completely heterogeneous line.” To make computation faster, simpler, and more intuitive, a plate model was developed to characterize the flow in the fracture and reduce the simulation workload of hydraulic fractures in numerical simulations. By integrating the pressure distribution data from numerical simulation with MATLAB programming, the pressure was converted into flow velocity, enabling the calculation of the Lorenz coefficient using flow velocity as the evaluation criterion. Consequently, a method for characterizing flow heterogeneity was established. Furthermore, the paper designed experimental plans for triangular well patterns and semi-inverse seven-spot well patterns considering factors such as the presence or absence of high-permeability zones and fractures, fracture angles, and permeability of high-permeability zones to investigate the relationship between the Lorenz coefficient and recovery coefficient. Among them, 17 schemes were designed for the triangular well pattern, while 21 schemes were developed for the inverted seven-spot well pattern. The analysis revealed that for triangular well patterns, a linear relationship was observed when the Lorenz coefficient was below 0.94. However, once the Lorenz coefficient exceeded 0.94, the recovery factor decreased exponentially with the increasing Lorenz coefficient. For inverted seven-spot well patterns, this transition occurred when the Lorenz coefficient reached 0.96. The thresholds distinguishing strong and weak seepage field differences were determined to be 0.94 for the triangular well pattern and 0.96 for the semi-inverse seven-spot well pattern. Specifically, for triangular well patterns, when the Lorenz coefficient exceeded 0.94, the recovery factor dropped sharply, indicating excessive flow heterogeneity. In such cases, flow field adjustments were necessary to improve development performance. Similarly, for inverted seven-spot well patterns, optimization and adjustment of the flow field were required when the Lorenz coefficient reached 0.96. Finally, the G7 reservoir was evaluated using the above method and adjustments were implemented to reduce seepage diversity. The evaluation yielded Lorenz coefficients of 0.949 6 for and 0.954 0 for two sand bodies, identifying these two sand bodies as areas with significant seepage disparities within the block. Further analysis revealed the reasons for the strong seepage disparities for the two sand bodies. In the eastern well area of the first sand body, a localized high-permeability zone was present, whereas the central and western regions exhibited weaker seepage. The causes were attributed to both static and dynamic factors: statically, the reservoir heterogeneity resulted in better physical properties and stronger seepage in the central and eastern parts, while the western part had poorer physical properties and weaker seepage; dynamically, the central region suffered from an incomplete well pattern, whereas the eastern region had a more well-developed well pattern. Although the western region had poorer physical properties, the G7-11 well, after the fracturing stimulation and with a relatively complete well pattern, exhibited locally strong seepage. In the second sand body, the central and eastern regions showed significant seepage disparities. The analysis attributed this to the strong reservoir heterogeneity causing substantial seepage differences statically, while dynamically, the overly dense well pattern and injection-production regime in the central and eastern regions exacerbated seepage disparities. Consequently, flow field adjustments were necessary. Strategies were formulated to address the pronounced seepage heterogeneity in these sand bodies post-evaluation. These strategies include optimizing the well pattern combined with segmented water injection to ameliorate both areal and vertical seepage disparities, adjusting the flow field to balance areal seepage differences, and implementing cyclic water injection to reduce flow heterogeneity. Numerical simulation was conducted to forecast the development trends, and a comparison of relevant indicators before and after the adjustments was carried out. The results showed that the Lorenz coefficient was reduced below the critical threshold, and the oil recovery efficiency increased by 1 percentage point over 10 years, effectively achieving water control and oil stabilization. The findings demonstrate that the proposed method can accurately evaluate seepage heterogeneity and help explore the residual oil, offering significant guidance for improving oil recovery efficiency. Meanwhile, this study determines the critical thresholds for strong and weak fluid flow heterogeneity in triangular and semi-inverse seven-spot well patterns, which are commonly found in Subei fault-block reservoirs. In practical applications, these threshold criteria should be re-evaluated based on specific well pattern configurations.

Key words: high water cut reservoirs, flow heterogeneity evaluation, flow characterization in fracture, adjustment strategies to reduce seepage difference, residual oil exploration