TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIntelligent wells and Smart Field concept have been introduced, and recently applied in some assets as a solution to increase production, reduce deferment and increase recovery. The value of Smart Field however can only be fully realized by integrating three main elements, Technology, Process and Resources. Combining subsurface smart well technologies, real-time data gathering, integrated modeling and control elements through appropriate resources and skills are core to close the smart field value loop and will result in better optimization, cost saving and enhancing ultimate recovery.The objectives of this paper are to share the experience on smart field applications and operations in BSP, demonstrate the value of integrating Smart Field elements, demonstrate the importance of team integration to achieve the value loop and share the challenges encountered, lessons learnt and recommendations.

Selective completions have been used in BSP's Iron Duke and Bugan fields to allow commingled production from multiple reservoir intervals, in some cases across fault blocks. Typically, the oil rims in Iron Duke and Bugan are overlain by large gas caps within heterogeneous sandstones. Recent PLT results have indicated that gas breakthrough occurs in high permeability sand streaks. As a result, selective production offers the potential to increase ultimate recovery by improved reservoir management. For example, specific simulation models built to investigate the benefits of a smart well have estimated 20% increase in UR in the Iron Duke. In addition, smart completions offer the potential of accelerated production. The benefits of smart completions are discussed with particular reference to the well Iron Duke 19. This was completed with a 5 zone selective completion. Although the production performance of 3 of the 5 zones was worse that expected, the smart completion has demonstrated considerable value in allowing both production rates and expected ultimate recovery to be increased. This shows that much of the value of selective completions can be in providing flexibility to respond to reservoir surprises. Some of the challenges that have been encountered with the operation of multi-zone selective completions and the solutions that have been put in place to optimise well and reservoir deliverability are also discussed. This experience builds on that described earlier for the much larger Oseberg field in Refs. 1 & 2. Introduction The Iron Duke field, located approximately 50km off the coast of Brunei, is made up of a series of oil rims across a number of fault blocks. The oil rims are overlain by large gas caps that provide the primary drive mechanism. Managing depletion of the gas caps is thus key to maximizing recovery from the field. The Iron Duke field was discovered in 1984 and a phased development approach was adopted in view of the subsurface uncertainty. Iron Duke came on stream in February 1992 from three vertical wells and oil production peaked at 1500 m3/d. These wells typically saw rapid increase in GOR trends and are currently closed in to conserve reservoir energy. Phase 2 development drilling of seven horizontal wells commenced in 1999 and production peaked at over 4000 m3/d in 2000. No selectivity was installed in any of these wells but they were lined and cemented to cater for future zonal isolation should we encounter any troublesome thief zones. Gas breakthrough occurred early in Iron Duke 19 with PLT logs indicating that the gas was produced from several high permeability streaks. The Bugan field is a new development and is located just to the south west of Iron Duke. The first development well, BG-7 was drilled from the Iron Duke platform in 2003. Objectives Iron Duke 19 (ID-19) ID-19 was drilled in 1999 and targeted 5 separate oil rims crossing 2 fault blocks (Fig 1). Although it was planned to eventually recomplete this well with a selective completion, initial production was based on progressive perforation and isolation. The initial production data provided valuable input to the design of the selective completion and the well was recompleted with a 5 zone selective completion in 2002. This is believed to be one of the first 5 zone selective completions in the world. The objective was to optimise oil production while managing GOR in order to maximize ultimate recovery. Reservoir modeling prior to the recompletion indicated that an 18% increase in UR could be achieved by continuously optimizing production.

This paper describes how Brunei Shell Petroleum Co Sdn Bhd (BSP) uses cross validated and reconciled real time production data across large offshore and onshore production networks to support more proactive day-to-day oil and gas production surveillance and management. Examples are presented of the gathering network surveillance systems for the extensive BSP East and Darat Production Assets.In modern oil fields, there is an abundance of instrumentation distributed over often large geographical areas. The production network ranges from the individual wellheads, to production manifolds, test and bulk separators, past surge vessels and export pumps, to crude dehydration tanks at a central crude terminal or to the gas compressors and gas export points. At least the initial parts of the production gathering network at the wells will have multiphase flow with uncertain and variable oil, water and gas proportions. Normally the most downstream flow meters are well calibrated with good calibration records, but the actual accuracy of the majority of the flow meters upstream will be uncertain, and they will not be nominally designed to handle multiphase fluids or mixtures of fluids with varying densities. Conventionally, it is regarded to be problematic to track production variations in real time across the network back to the source wells. This is due to issues with metering multiphase flows and assumed uncertain transport delays.It is shown here that it is now practical to track in real time production rates across large production networks, working back from the most downstream, well metered, points to the individual bulk separator units or production platforms or the wells themselves. Indeed, it is possible to obtain a consistent, real-time reconciled view of the current production rates across these larger production networks. This allows more accurate surveillance of production from the wells, early detection of measurement issues and quicker responses to system upsets. Various common blockers to real time network wide production flow surveillance are addressed, including noisy meters, storage tanks, on-off pumps and hard-to-measure multiphase flows from the wells. The work reported may be seen as a "top-down" approach that complements the existing metering systems, integrating the data to "make the best of" all available metering and instrumentation. An example shows how better metering and instrumentation, virtual metering and real time data analysis are combined to detect and correct significant discrepancies.Raw ultrasonic flow meter signal in black, filtered signal is in red, reconciled filtered signal is in blue.

This paper describes how Brunei Shell Petroleum Co Sdn Bhd (BSP) uses cross validated and reconciled real time production data across large offshore and onshore production networks to support more proactive day-to-day oil and gas production surveillance and management. Examples are presented of the gathering network surveillance systems for the extensive BSP East and Darat Production Assets.In modern oil fields, there is an abundance of instrumentation distributed over often large geographical areas. The production network ranges from the individual wellheads, to production manifolds, test and bulk separators, past surge vessels and export pumps, to crude dehydration tanks at a central crude terminal or to the gas compressors and gas export points. At least the initial parts of the production gathering network at the wells will have multiphase flow with uncertain and variable oil, water and gas proportions. Normally the most downstream flow meters are well calibrated with good calibration records, but the actual accuracy of the majority of the flow meters upstream will be uncertain, and they will not be nominally designed to handle multiphase fluids or mixtures of fluids with varying densities. Conventionally, it is regarded to be problematic to track production variations in real time across the network back to the source wells. This is due to issues with metering multiphase flows and assumed uncertain transport delays.It is shown here that it is now practical to track in real time production rates across large production networks, working back from the most downstream, well metered, points to the individual bulk separator units or production platforms or the wells themselves. Indeed, it is possible to obtain a consistent, real-time reconciled view of the current production rates across these larger production networks. This allows more accurate surveillance of production from the wells, early detection of measurement issues and quicker responses to system upsets. Various common blockers to real time network wide production flow surveillance are addressed, including noisy meters, storage tanks, on-off pumps and hard-to-measure multiphase flows from the wells. The work reported may be seen as a "top-down" approach that complements the existing metering systems, integrating the data to "make the best of" all available metering and instrumentation. An example shows how better metering and instrumentation, virtual metering and real time data analysis are combined to detect and correct significant discrepancies.Raw ultrasonic flow meter signal in black, filtered signal is in red, reconciled filtered signal is in blue.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIntelligent wells and Smart Field concept have been introduced, and recently applied in some assets as a solution to increase production, reduce deferment and increase recovery. The value of Smart Field however can only be fully realized by integrating three main elements, Technology, Process and Resources. Combining subsurface smart well technologies, real-time data gathering, integrated modeling and control elements through appropriate resources and skills are core to close the smart field value loop and will result in better optimization, cost saving and enhancing ultimate recovery.The objectives of this paper are to share the experience on smart field applications and operations in BSP, demonstrate the value of integrating Smart Field elements, demonstrate the importance of team integration to achieve the value loop and share the challenges encountered, lessons learnt and recommendations.