Numerical Simulation Method and Laboratory Experiments of Starting Pressure Gradient in Tight Sandstone Oil Reservoirs

Abstract

Abstract In the process of the tight oilfields development, it is difficult to establish an effective system of injection-production displacement because of the high seepage resistance. The seepage does not follow the linear Darcy's law. However, the reservoir simulation software has not considered this phenomenon, which leads to the numerical simulation prediction results better than actual production data. Therefore, it is necessary to establish an effective method to calculate the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation. This paper introduced a factor called starting pressure gradient (SPG), which can be used to describe non-Darcy seepage phenomenon. First of all, laboratory experiments of differential pressure flow method were carried out to get the relationship between core permeability and the SPG. In addition, according to the reservoir heterogeneity and exploitation degree, three methods were put forward for characterization the SPG in tight sandstone oil reservoirs numerical simulation. Finally, this numerical simulation method was used in the X tight sandstone oil reservoir history matching process to verify its accuracy. The results of the laboratory experiments showed that, SPG exists in tight sandstone oil reservoirs. Liquid starts to flow when the production pressure gradient is greater than the SPG. SPG is an additional pressure resistance for each flow unit, the existence of SPG has intensified the degree of pressure drop. Analysis of the experimental data gave a power series relationship between the SPG and the permeability. And the SPG increases with the decreases of core permeability. Reservoir heterogeneity criterion was established by introducing R and C factors. The greater R value and C values are, the higher the heterogeneity is. When the reservoir heterogeneity is weak (0< R≤0.3), we set SPG for each layer. When the reservoir heterogeneity is strong (0.3 < R≤ 1 or 0 < C≤1), we set SPG for each rock type. When the reservoir with intense heterogeneity (1<C<2), we set SPG for each gird. After considering SPG, single well history matching coincidence rate improves from 64% to 87%, and every layer oil production prediction has high coincidence with the actual production data. Therefore, SPG cannot be ignored in tight sandstone oil reservoirs numerical simulation. This paper provides a new method to describe the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation, and can guide the tight sandstone oil reservoirs development effectively. This method can also be applied in heavy oil reservoirs and tight gas reservoirs numerical simulation.