Abstract
The existing methods of reservoir management based on bottomhole pressure control imply setting of limited bottomhole pressures that are determined either through equations or based on pressure transient analysis (PTA). However use of project profitability metrics commonly applied in oil industry–cumulative oil production and net present value (NPV)–yields more valid results. In doing so, all basic aspects must be taken into consideration: geological setting, current reservoir performance, reservoir fluid properties, well interference, and others. This can be achieved through application of 3D flow simulation and inverse modeling methods.
To this end, we have developed an algorithm and created a few pilot models with different reservoir characteristics and fluid properties identical to conditions of actual reservoirs operated by the Company. The calculation results were analyzed considering specific reservoir conditions. We have revealed some principles and tendencies that can be applied to improve performance of oil and gas fields. The research results show that the choice of optimal bottomhole pressure is largely dictated by presence or absence of gas-cut fluid flow. In case the bubble point pressure is close to the initial reservoir pressure, optimal bottomhole pressures differ significantly from limiting bottomhole pressures and, thus, should be calculated. In case the bubble point pressure is lower than the original in-situ pressure, limiting bottomhole pressure is the right choice for production wells. We also found that in fractured-porous reservoirs the right time of putting injection wells into operation is of critical importance. The revealed principles and recommendations can be applied to improve the effectiveness of reservoir management operations and increase final recovery.
