*4.5. Actual Model*

In this section, we further verify the accuracy of the application of anisotropic relative permeability by comparing the actual production data of the C4N well area in Shengli Oilfield. This well area is a typical fluvial facies sedimentary environment, which belongs to a medium–high permeability reservoir.

In order to apply the anisotropic relative permeability to the actual model more accurately, we carried out a paleomagnetic orientation on the experimental samples (Figure 8). We separated the stable magnetization direction through the high precision magnetometer system in the laboratory and determined the geographic north pole direction of the core. In the paleomagnetic test, the x direction is used as the marking direction. The paleogeographic magnetic declination angle and magnetic inclination angle of the Y direction of the sample are 63.1◦ and −0.9◦, respectively. Two precision parameters K and T95 (the higher the K value, the higher the precision, the smaller the T95, the more reliable the result) are usually used to measure the reliability spectrum degree of the Fisher distribution or the average observation direction of the pole [37–40]. The K value of this paleomagnetic test is 18.7 and T95 is 9.4, which has high reliability (Table 2).

**Figure 8.** Photo of palaeomagnetic core sample.


**Table 2.** The results of characteristic remnant magnetization measurements.

After that, we established a three-dimensional geological model according to the characteristics of the C4N well area, and the grid system was generated with the north by west 63.1 degrees as the X axis. The C4N well area is in the middle and high water cut stage, when deploying infill wells, and the remaining oil drilling potential will refer to the calculation results of reservoir numerical simulation. We often encounter the deployment of wells in places with high remaining oil saturation, and the drilling and production effect is not necessarily good. In fact, this is due to the inaccurate characterization of remaining oil distribution.

Figures 9 and 10 show the current distribution of remaining oil saturation calculated by traditional relative permeability and anisotropic relative permeability in the Cheng 4 South well area, respectively, as of 1 November 2019. There is a significant difference in remaining oil saturation between the two numerical simulation results. The numerical simulation results considering anisotropic relative permeability show that the sweep range of water is larger and the displacement efficiency in the Y direction (perpendicular to the river flow direction) is higher. There is also a great difference in the average remaining oil saturation obtained by the two algorithms. For example, the average remaining oil saturation of well C13-21 obtained by the numerical simulation algorithm considering anisotropic relative permeability is significantly higher than that of the traditional algorithm. This also explains why well C13-21 has a longer stable production period than other production wells, and the current water cut can still be maintained at 53.7% (Figure 11).

**Figure 9.** The remaining oil saturation distribution calculated by a traditional simulator.

**Figure 10.** The remaining oil saturation distribution calculated by the new simulator.

Here, we count the first production of producers since 2017. The statistical results are shown in Table 3. Column 5 in Table 3 shows the average production for the first three months. Column 4 in Table 2 shows the average water cut for the first three months. By comparing the results, it can be seen that the numerical simulation algorithm considering anisotropic relative permeability is close to reality. Particularly in the C14-31 and C18-42 wells, when the water cut of these two wells exceeded 98%, though measures of partition were taken, the production effect was still poor and the water cut remained high. The reason is that the traditional numerical simulation results show that there is still some remaining oil in these two wells, but the numerical simulation results considering anisotropic relative permeability show that the contribution of remaining oil considered

by the former is actually very small and has been swept in the process of water flooding (Figures 12 and 13).

**Figure 11.** The average remaining oil saturation distribution (the left one is calculated by a traditional simulator, the right one is calculated by the new simulator).

**Table 3.** The first production of deployed production wells since 2017.


**Figure 12.** Cross section of remaining oil saturation of well C14-31 (the upper left one and the lower left one are the remaining oil profiles calculated by the numerical simulation method considering anisotropic relative permeability, and the upper right one and lower right one are the results of a traditional simulation).

**Figure 13.** Cross section of remaining oil saturation of well C18-42 (the upper left one and the lower left one are the remaining oil profiles calculated by the numerical simulation method considering anisotropic relative permeability, and the upper right one and lower right one are the results of a traditional simulation).

The coincidence rate between the remaining oil saturation calculated by the traditional relative permeability and the initial production of the oil well is 62.5%, and the coincidence rate between the remaining oil saturation calculated by the anisotropic relative permeability and the initial production of the oil well is 87.5%, which is 25% higher (Table 3). Obviously, the remaining oil saturation calculated by anisotropic relative permeability shows better agreement with the actual situation and can describe the oil–water movement law more accurately.

We compared the change in water cut in the Cheng 4 South well area during the production process. Compared with the water cut calculated by the traditional numerical simulation method, the historical water cut shows a better agreement with that obtained by the numerical simulation algorithm considering anisotropic relative permeability (Figure 14).

**Figure 14.** Water cut change with traditional relative permeability and anisotropic relative permeability in the production process of the Cheng 4 South well area.
