A strong increase in gas inflow due to gas coning and the resulting bean-back because of Gas to Oil Ratio (GOR) constraints can severely limit oil production and reservoir drive energy. In this paper we will use a coupled reservoir-well model to demonstrate that oil production can be increased by using controlled inflow from a gas cone as a natural lift. This model was developed in the knowledge centre Integrated System Approach Petroleum Production (ISAPP) of TNO, TU Delft and Shell, and is based on a commercially available dynamic multiphase well simulation tool (OLGA) and a dynamic multi-phase reservoir simulator (MoReS). In order to give a proof of principle we have implemented a PID feedback controller, which controls the gas fraction in a well by changing its wellhead choke or inflow control valve (ICV) settings, on a realistic test case. We introduce a strategy to find an optimal production set point for this controller and the benefits of using downhole ICVs in comparison to the wellhead choke are investigated. Simulation experiments show that a PID controller is an effective means to prevent a full gas breakthrough and, moreover, can be used to increase the produced oil rate by tuning ICV settings to achieve an optimal well gas fraction. Results show that the coupled simulations could be significantly more accurate in comparison to stand-alone well or reservoir simulations. In current operations ICVs are mostly used to completely shut down well segments that experience gas coning. We show that by keeping these ICVs open in a controlled way the - otherwise undesirable - phenomenon of gas coning can be used to increase oil production. Introduction: Gas Coning Control Gas coning is a phenomenon where the gas-oil-contact (GOC) of a reservoir slowly moves towards a well as a result of oil drawdown. In case of horizontal or deviated wells this is often a zonal phenomenon, which occurs at a limited amount of perforations, and is referred to as 'cresting' (Figure 1). At a certain moment in the production life of a gas coning well the gas-oil-contact will reach the well and a gas breakthrough will occur. Upon breakthrough the well will experience a high gas inflow. Largely for three reasons this is an undesired phenomenon. Firstly because the gas phase may start to dominate production, which will deem the well to be uneconomical. Secondly, the inflow of gas may damage topside equipment that is not designed to process large quantities of this phase. Thirdly, after breakthrough the gas cap of the oil reservoir will be depleted fast, taking away its drive energy. The difficulty of containing these three negative consequences lies in the relative speed of a gas breakthrough - typically expressed in hours. Unfortunately the industry is increasingly faced with these hard to contain consequences because many mature fields experience gas coning. Also, oil is increasingly produced from reservoirs like thin oil rims that tend to cone easily.

A strong increase in gas influx due to gas coning and the resulting bean-back because of Gas to Oil Ratio (GOR) constraints can severely limit oil production and reservoir drive energy. The purpose of this paper is to demonstrate that oil production after a gas breakthrough can be optimized by means of an inflow control strategy that takes the effects of 'natural gas lift' and production choking into account. Within the research framework of the "Integrated System Approach Petroleum Production" (ISAPP) knowledge center of TNO, TU Delft and Shell, it has been shown that this optimization can be achieved by controlling the location and amount of gas influx in a horizontal smart well. In order to show a proof of principle we have implemented a PID feedback controller, which controls the gas fraction in a well by changing its Inflow Control Valve (ICV) settings, on a test case in a dynamic reservoir simulator. We introduce a three step strategy for production optimization: firstly we model how the controlled production rate after breakthrough depends on the gas fraction; secondly we will determine the optimal gas fraction; thirdly we will consider the capability of a PID controller to produce at this optimal gas fraction. Simulation experiments show that a PID controller is an effective means to prevent a full gas breakthrough and, moreover, can be used to increase the produced oil rate by tuning ICV settings to an optimal gas fraction. These experiments also demonstrate the benefits of using downhole ICV control in comparison to wellhead control. In current operations ICVs are mostly used to completely shut down well segments that experience gas coning. We show that by keeping these ICVs open in a controlled way the, otherwise undesirable, phenomenon of gas coning can be used to optimize oil production. Introduction: Gas Coning Gas coning is a phenomenon where the gas-oil-contact (GOC) of a reservoir slowly moves towards a well as a result of oil drawdown. In case of horizontal or deviated wells this is often a zonal phenomenon, which occurs at a limited amount of perforations only, and is referred to as 'cresting' (Figure 1). At a certain moment in the production life of a gas coning well the gas-oil-contact will reach the well and a gas breakthrough will occur. Upon breakthrough the well will experience a high gas influx. Largely for three reasons this is an undesired phenomenon. Firstly because the gas phase may start to dominate production, which will deem the well to be uneconomical. Secondly, the influx of gas may damage topside equipment that is not designed to process large quantities of this phase. Thirdly, after breakthrough the gas cap of the oil reservoir will be depleted fast, taking away its drive energy.

Increasingly the upstream oil & gas industry is using active flow control (e.g. feedback loops) or passive flow control (e.g. passive ICD) technologies to optimize asset production. They are used, for example, to commingle production, stabilize production in case of water or gas breakthrough, and to mitigate the effect of slugging in wells. While the merits of such flow control technologies are becoming clear, so do their limitations.One main limitation of using traditional flow control technologies is that, in the presence of complex and changing process dynamics, it is difficult to come up with a controller design that optimizes asset production. Advanced control, specifically Model Predictive Control (MPC), is widely used in the industry to optimize complex downstream processes. In this paper we will start to explore the merits of MPC for upstream applications by means of a realistic test case of a thin oil rim that suffers from gas breakthrough. In the paper three aspects of MPC will be explored into detail.Firstly, we take a look at the dynamic process models, which lie at the basis of MPC. In MPC the dynamic model is used to compute control actions that optimize the future behavior of the production process. In order to do this, the model has to be sufficient accurate and needs to have a computational burden that allows for real-time optimization. We will discuss how a mixture of physical modeling and data driven models may be used for this purpose.Secondly, we give concrete examples of such fast dynamic models for the production process of the thin oil rim case. The models describe the dynamic behavior of the gas cone in the reservoir, as well as the effect that gas breakthrough has on well performance. Using such a model, we will evaluate 2 different thin oil rim production strategies that are based on downhole and topside flow control.Thirdly, we develop a production strategy using the MPC framework. In this approach the dynamic well-reservoir model is used to determine optimal settings of wellhead and ICD valve positions that optimize production. This advanced production control production strategy is benchmarked in terms Net Present Value (NPV) and barrels produced, and compared to cases that use only conventional feedback wellhead flow control. Production improvement in oil production over the first 1.5 years is 17% in the test case.Since beginning of the 1990's, starting in refineries and base chemical plants, MPC has become the standard advanced control methodology in downstream industries, putting more process knowledge (models) into production control and giving rise to optimal production. A similar development may be expected in the upstream industry. As the paper shows MPC has the potential for bringing real-time production optimization a step closer.

During end-of-life production from an oil well it is often impossible to sustain continuous production. Gas coning is a common cause of production problems, especially in thin oil reservoirs. This study compares three production strategies that can be used to deal with this problem for a specific field case. The strategies will be evaluated on the basis of two criteria: Total number of barrels produced and Net Present Value (NPV). The three strategies considered are (i) intermittent production, (ii) Well Head Control (WHC), (iii) Inflow Control Devices, (ICD). The first two are currently common practice, while the latter is an emerging technology which is not applied on a large scale yet, because of the larger expense incurred by ICD installation.The onset of gas breakthrough occurs in a much shorter timescale than many other production upsets, such as water flooding, making it a very challenging situation for a control strategy. A coupled dynamic reservoir-well model has been used in order to describe the breakthrough accurately. A simulation environment has been constructed and validated in which different well and reservoir models can be coupled. Since correct prediction of flow and pressure drop over ICDs is essential, special care was taken to accurately model these devices. For the WHC control strategies a Proportional Integral Derivative (PID) algorithm was used.Despite the higher initial completion costs associated with ICDs, they can provide a cost-effective way to reduce long-term operating costs and increase yield. Production targets are achieved with longer, but fewer wells, maintenance and overhead. From a reservoir management point of view, ICDs can improve the productivity index (PI) by maximizing reservoir contact, minimizing gas coning by operating at lower drawdown, and increasing overall efficiency.In this study we evaluate a field case, which suffers from gas coning, to verify whether the implementation and usage of ICDs are cost-effective alternatives, and quantify the relative merits for each technology. The comparison is based on both the total barrels produced and the NPV, taking into account the integral cost, including installation, operating, and maintenance costs.