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Downhole Permanent Monitoring and Control Systems invoke the vision of adapting real-time process control to the hydrocarbon drainage process. This paper discusses some aspects of the evolution towards that vision. Three functions of Reservoir Management are focused:Estimating physical downhole states (inverse problems) for Reservoir CharacterizationUpdating models (history matching)Controlling well inflow The potential for a real-time system to contribute successfully seems to differ from function to function. Introduction Downhole Permanent Monitoring and Control Systems, or Intelligent/Smart Wells implies that the reservoir and the well are continuously monitored and that the well completion may be remotely reconfigured to adapt to changes and/or surprises in downhole conditions. Todays objectives are toImprove reservoir characterizationAvoid interventions both for logging and completion reconfigurationsAccelerate productionImprove total recovery If these objectives are reached, remote production systems like deep water fields may hopefully be drained as effective as more accessible platform and onshore wells. According to generally accepted experience data, accessible wells feature up to 20% higher recovery than subsea production systems. Other reservoir candidates include: complex structures, reservoirs with high model uncertainty, etc. Today, the industry is working hard to demonstrate the new technology. Poor life cycle reliability seems to be the main challenge. The evolution of the systems is slow compared to the operators' expectations. It seems to be a conflict of interest between technology suppliers, who want to build up some experience data from field installations, and the operators' wishes to "sit on the fence", not taking the risk until the technology is fully qualified. However, systems like the multiple zone SCRAMS system from PES/Halliburton and other more simple systems have been installed in several wells worldwide. The benefits are clearly demonstrated in some cases. An example is the Oseberg field in the North Sea, where the operator seem to have reached their objectives by successful handling of reservoir surprises with wells equipped with up to four isolated zones each. During the next few years, the system life cycle reliability is expected to come up to the level required to reach today's objectives in most fields, the next step to be added to the list of objectives for Permanent Monitoring and Control Systems is most likelyProduction optimization. Given a suitable permanent monitoring system, the reservoir engineers may be able to fine-tune some of the processes related to the hydrocarbon drainage by the use of downhole linear chokes and the right zone isolation. Status, Downhole Permanent Monitoring The benefit of permanent monitoring has already been demonstrated through the last ten years. Several cases are reported,1,2,3,4,5 and various conclusions are drawn:Generally, long-term data from permanent gauges have the potential to provide more information about the reservoir than traditional short-term data.

This paper describes the interventionless approach that was successfully executed during the Pyrenees early production phase to identify the timing and location of water breakthrough. Chemical inflow tracers were installed in key production wells within the lower completion along the horizontal production sections. Results from this work have supported the reservoir simulation history matching process and confirmed the performance of the inflow control devices (ICDs). These data in conjunction with the real time rate information from subsea multiphase meters has allowed proactive reservoir and production management that has contributed to the early identification of additional infill opportunities.

North Amethyst is the first subsea tieback field development for Husky Energy's White Rose project, located off the East Coast of Newfoundland and Labrador, Canada. The geographical location presents some of the harshest weather conditions in the world due to the elevated sea states and ice conditions. The North Amethyst field achieved first oil in 2010 and at the end of December 2011, had three production wells and three water injectors. Further wells are planned as part of the development.To counter imbalance in the horizontal flow profile that can lead to early water or gas breakthrough, the field development strategy employed Inflow Control Device (ICD) technology. The ICD technology application was the first offshore on the East Coast of Canada.A method of proving effective horizontal clean-out and flow distribution for the ICD technology was necessary. However, due to the subsea configuration complexity, semi-submersible rig costs and delays due to unfavorable weather conditions, the prospect of production logging the horizontal wells was deemed a high risk and expensive operation.To overcome these hurdles, unique inflow tracer technology was used in tandem with the ICDs to provide validation of clean-out and horizontal flow distribution. The North Amethyst producers were equipped with unique oil and water soluble tracers placed along the horizontal, embedded in the ICD screens. The tracer technology's objectives were to monitor the zonal contributions during clean-out and during the production phase. Water tracers were to monitor and identify the location of zonal water breakthrough.Topside fluid samples were analyzed, and tracer concentrations provided the basis for extracting well inflow information. The utilization of inflow tracer systems in collaboration with other reservoir engineering tools has provided validation of horizontal contribution and feedback about individual ICD nozzle placement. This paper will document the design, execution, and analysis of the tracer results in two initial North Amethyst ICD producers.

This paper discusses technical and practical aspects on the future needs for monitoring of flow conditions in deviated and horizontal production and injection wells. A monitoring technique based on ultrasound has been developed. Examples of measurements in various North Sea wells are presented. The results are promising, and show the potentials of nonintrusive techniques for flow monitoring. It is expected that a combination of several sensor principles would facilitate the interpretation of downhole flow conditions.