An Investigation Into the Need of a Dynamic Coupled Well-Reservoir Simulator

Abstract

Abstract Within the research framework of the "Integrated System Approach Petroleum Production" (ISAPP) knowledge center of TNO, TU Delft and Shell, the necessity of taking the interaction between dynamic reservoir and dynamic well behavior into account when optimizing a producing asset is investigated. To simulate dynamic phenomena in the well and in the reservoir, a dynamic multiphase well simulation tool (OLGA) and a dynamic multiphase reservoir simulator (MoReS) have been used. Both simulators have been coupled using an explicit scheme. The dynamic well simulator, the dynamic reservoir simulator and the coupled dynamic well-reservoir simulator have been used to simulate a realistic test case which consists of a horizontal well with three inflow sections located in a thin oil rim. A number of scenarios are investigated that play a crucial role during different stages of the well's lifetime: naturally occurring phenomena, e.g. coning, and production dynamics, e.g. shut-in. The results of dynamic well simulations, dynamic reservoir simulations and coupled well-reservoir simulations are presented and an overview is given of the cases where the results of the coupled simulations are significantly more accurate in comparison to stand-alone well or reservoir simulations. For gas coning it is shown that the coupled simulator has much faster pressure transients after gas breakthrough than the dynamic reservoir simulator. Therefore, the coupled well-reservoir simulator should be used to simulate gas breakthrough and to optimize production using gas coning control. For small time scale phenomena, order of less then one day, the well and reservoir transients overlap. Simulations show that the coupled simulator is essential for an accurate prediction of the well-reservoir interaction during these small time scale phenomena. Introduction Production instabilities are undesirable and play a crucial role in the production lifetime and ultimate recovery of any reservoir. These instabilities can arise from or be governed by the interaction between the well and the reservoir.1 Production instabilities can be subdivided into two groups. Firstly, the naturally occurring dynamical phenomena, such as coning and slugging. Secondly, the production dynamical phenomena, such as shut-in, clean-up and gas lift heading. Figure 1 displays the time and spatial scales for different naturally occurring and production dynamical phenomena. The values of the time and spatial scales are indicative and based on experience. There are several phenomena which have a certain amount of overlap. In these areas it is expected that the well dynamics are strongly influenced by the reservoir dynamics and visa versa. Simulations are widely used to predict oil and gas production. The current status of these simulations is to either use a dynamic well model combined with some analytical reservoir model2 or to use a dynamic reservoir model combined with either lift tables or a steady state well model.3, 4 The disadvantage of these models is the fact that they underestimate the pre-mentioned well-reservoir interactions and therefore give non-realistic production forecast in cases where well-reservoir interactions play a crucial role.