The method of multivariate calibration is experimentally investigated to establish estimators of the required pertinent flow parameters in multiphase pipe flow. The unfiltered primary signals, provided by a capacitance sensor, are analysed as discrete time series and the signal characteristics are extracted. The multivariate model that is generated estimates the flow composition based on the extracted information existing in the broad-band capacitance signal. The data analysis and test results are presented

Permanent downhole multi-phase monitoring (DMM) can give several advantages in field development, such as increased flexibility in the development of multi-lateral and horizontal wells, optimisation of artificial lift systems and monitoring of multi-layered wells. This paper gives an overview of existing permanent downhole measurement systems and a status of topside and subsea multi-phase flow meters (MFM). The main focus will be directed to the challenges in downhole multiphase measurements. Topics to be taken into consideration for realisation of a downhole multi-phase meter will be discussed, such as actual flow conditions occurring at the point of measurement, which quantities that need to be measured, sensor principles, data processing needs and signal transmission capability. Introduction Multi-phase flow measurement technology is now in the process of reaching an industrially accepted level of maturity for topside applications, and several MFMs are at present being installed for permanent well monitoring purposes. Some of these have been designed for subsea applications. The next step will be to develop this technology for downhole applications. One benefit from introducing downhole multiphase monitoring is to control the production from each branch of multi-lateral wells, especially with respect to water cut and gas liquid ratio. In addition, flow rate measurements may be important for control of gas lift systems and Electrical Submersible Pumps (ESP). Continuous monitoring of individual layers in multi-layered reservoirs can reduce the needs for well intervention and increase the total oil production from each well e.g. by closing specific layers in case of water breakthrough. Benefits from DMM Field development, especially in the North Sea, is becoming a more challenging economic problem with the requirement to develop smaller hydrocarbon accumulations, more difficult fluids (e.g. heavier oils), or to undertake complex production technology and drilling projects such as artificial lift, multilateral wells or extended reach drilling. One of the key components in these development issues is monitoring of well performance during the appraisal and production stages of field development. Acquired data allows timely (re-) assessment of field production mechanisms, reserves and in- place volumes which in turn allows the optimisation of the field development. The permanent monitoring of bottom hole pressure and temperature is an established data acquisition technique in hydrocarbon field developments. The ability to monitor the 3-phase flow at bottom hole conditions in addition to pressure and temperature has a number of advantages in field development that increase the value of the project to the operator:–Increased flexibility in the development of new well and completion technologies (multi-lateral, horizontal)–Optimisation of artificial lift systems (Electrical Submersible Pumps, gas lift)–Monitoring of multi-layered wells Downhole multi-phase monitoring in Multi-lateral wells Multi-lateral wells offer significant technical and economic advantages over the more conventional orthodox and single-branch horizontal wells in a number of reservoir types. Additionally, significant effort is being expended on the development of flow control systems for the independent branches of multi-lateral wells. The monitoring of flow at surface gives no indication of the contributions from the branches, especially when water breakthrough or changes in the gas liquid ratios are observed. P. 209

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Vestflanken 2 (VF2) is an ongoing field development project in the Oseberg area. The development concept chosen includes an unmanned wellhead platform (Oseberg H) with seven gas lifted production wells, two gas injection wells in addition to two sub-sea production wells using existing infrastructure. Four of the production wells will be multi-laterals completed with autonomous inflow control devices (AICDs). AICDs in VF2 wells have two main objectives: Accelerate oil production by delaying gas breakthroughChoke back gas after gas breakthrough AICDs have been successfully implemented at the Troll field, and further implementation on other fields are pursued. There are differences between fields and careful considerations must be taken when implementing the technology on a new field development like VF2. It is essential to select a type and size of the AICD that fit the application. This paper discusses the process of selecting the AICD flow capacity. The lower completion design was based on experiences and results from inflow simulations. However, the design for future wells will be made based on production experience from the first VF2 wells in production. This paper also discusses the clean-up and start-up of the first VF2 well and presentation of results. The well is well instrumented with downhole P/T gauge and multi phase flow meter on well head. This is the operators first AICD well equipped with multi phase meter which makes it a very good candidate for evaluating flow performance and AICD efficiency. The well was started October 2018. Step-rate tests were performed on both branches and on the comingled MLT production. This allowed to compare measured data from the multi-phase meter to results obtained by the simulation model. The simulation results matched the measured data to a varying degree with different model assumptions. The initial well performance data and simulation model will be valuable tools when evaluating AICD design for future wells.