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Summary This paper discusses the design, operating principles, flow-loop testing, and initial field installations of the world's first all-fiberoptic flowmeter for downhole deployment. The flowmeter provides real-time measurement of the flow rate, phase fraction, pressure, and temperature. It is deployed with the production tubing and is rated to 125°C and 15,000 psi. It is fullbore, nonintrusive, electrically passive, has no moving parts, and overcomes the design limitations imposed by downhole environments. Thus, it has the potential to provide highly reliable downhole measurements. The flowmeter has been tested extensively in industrial flow loops in a wide range of conditions. Results from the testing have demonstrated the flowmeter's ability to measure flow rates and water fractions in oil/water systems to within ±5% for the entire range of water cuts. These results have been validated by data from several field deployments. Introduction Real-time, downhole, multiphase flow-rate data are widely acknowledged to be of significant value for production optimization. This is particularly the case for high-cost deepwater developments and complex multilateral wells. Applications of downhole flow data include zonal production allocation, identification and localization of production anomalies, direct determination of the well's productivity index (PI), ability to commingle production from multiple zones, and reduction of surface well testing and facilities requirements. However, despite the potential value of this data, in the past, reliable, continuous measurements of downhole flow rates in producing wells have not generally been available because of difficulties in designing and deploying measurement devices for hostile in-well environments. During the past 5 years, there has been a significant increase in the installation and application of permanent, in-well monitoring systems. This has been especially true in high-cost, complex completions, such as multilateral and deepwater wells. Traditionally, permanent monitoring has referred primarily to downhole pressure and temperature measurement. Recently, however, the development and deployment of accurate and reliable downhole flowmeters has extended the types of in-well measurements available to fluid flow rates and phase fractions. Production and reservoir engineers have appreciated the value of real-time, continuous downhole flow-rate information for years. Applications for downhole flow data are numerous. Zonal Production Allocation. In multizone completions, data from a downhole flowmeter can be used to allocate production from individual zones. This can be achieved either with a flowmeter placed above each producing zone or by installing meters between adjacent zones and using the total flow measured at the surface to obtain the contribution of the uppermost zone. Identify and Localize Production Anomalies. One or more downhole flowmeters placed in the lateral section of a horizontal well can help locate production anomalies, such as which part of the lateral is contributing to flow and where water or gas breakthrough has occurred. This allows localized well stimulation or other well treatments to be performed to increase well productivity. Direct Determination of the PI. Real-time downhole flow-rate and pressure data allow the determination of a well's PI at any time without the need for intervention. Commingled Production. Reliable downhole flow data allows for the potential to commingle production from multiple zones. Reduce Surface Well Tests. Real-time downhole flow data reduce the need for surface well tests to determine the productivity of individual wells. Reduce Surface Facilities. The ability to measure flow rates downhole may eliminate the need for a surface test separator, thereby significantly reducing the facilities requirements on offshore platforms. In addition to the value added by applying downhole flow data, there are practical benefits to measuring flow rates downhole vs. at the surface or on the seabed. As depicted in Fig. 1, hydrocarbon production can lead to a wide variety of flow regimes.1 Although the downhole environment does impose significant design challenges for hardware manufacturers, the higher pressures and lower gas-volume fractions downhole typically result in conditions more conducive to multiphase flow measurement than those at the surface. Flowmeter Design A permanent, downhole fiber-optic flowmeter has been developed to provide real-time measurements of pressure, temperature, flow rate, and phase fraction (holdup). It makes use of an array of axially spaced Bragg grating sensors, which allows multiple, all-optical measurements, multiplexed on a single fiber-optic cable.2 The meter contains no downhole electronics, moving parts, or optical windows; is completely nonintrusive; and provides fullbore access. It is deployed during the completion as part of the production tubing string. The flowmeter system consists of two separate modules, as shown in Fig. 2. An upper assembly consists of a gauge carrier that houses a fiber-optic pressure and temperature transducer. The lower assembly contains the optical flow and phase-fraction sensors. Both the pressure/temperature transducer and the flowmeter sensors can be interrogated with a single optical fiber.

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Multi-capacitor multiphase flow meters have been tested at five field locations covering a wide range of crude properties and process conditions. Results of these field tests show excellent repeatability and good agreement with reference measurements, when available. These meters are now being applied at two different locations in Oman as the only means of testing individual wells. INTRODUCTION The need for a compact, reliable multiphase flowmeter is well established. Such a meter will enable the cost effective development of both offshore and onshore satellite fields and the possibility of optimising the operation of existing fields. Test separators, the conventional way of metering multiphase, can suffer from a range of operational problems and can also be unrepresentative because they sample the flow rate for only a small part of the production time of a well, e.g. one day per month. They are bulky and expensive, particularly for use offshore where size and weight are at a premium, and for satellite developments they require the use of expensive manifolds and long test lines. They can be intensive in the use of production and maintenance staff to ensure proper operation. It is attractive to replace test separators by compact multiphase flowmeters with similar metering accuracy, i.e. around ± 10% of actual flow rate for oil, water and gas, and sufficiently low cost to be applied economically to individual well flowlines. To meet this need, the multi-capacitor flow meter (MCF), a device for the measurement of flow rates in multiphase intermittent flow, has been developed in a commercialisation project between Shell Research in the Netherlands and manufacturers Kongsberg Offshore, a.s. in Norway.