Digital oilfield

Virtual Metering Tool Brings Real-Time Benefits to Production Monitoring

This paper describes a virtual metering tool that can monitor well performance and estimate production rates using real-time data and analytical models, integrating commercial software with an optimization algorithm that combines production and reservoir information.


This paper describes a virtual metering tool that can monitor well performance and estimate production rates using real-time data and analytical models, integrating commercial software with an optimization algorithm that combines production and reservoir information. The tool feeds external reservoir analysis applications and uses the results for validation purposes. Included in the complete paper are results from applications of the real-time virtual flowmeter (RTVFM) in oil, gas, and gas condensate fields.


Reliable estimation of production flow rates for wells is of paramount importance for 3D-model history matching, well-test interpretation, back allocation, real-time monitoring, and reservoir management. Virtual metering technology is used to evaluate well production rates—usually an uncertain parameter—and is based on real-time data and analytical models.

RTVFM technology has been developed by integrating a commercial software platform and mathematical models (algorithms). The algorithms solve dynamic pressure and temperature gradients simultaneously, along with the choke equation, to find optimal solution rates that match physical sensor readings. The tool manages the communication between real-time data and the models, enabling safe storage of the results. After calibration, the algorithm can run automatically in real time.

Major outcomes are the work-flow description of RTVFM: virtual metering work flow, real-time production calculation, and implementation in the digital oilfield (DOF) framework (Fig. 1). The complete paper discusses the methodology in detail. The paper presents three RTVFM case studies in offshore oil, gas, and gas condensate fields, showing the benefits and limitations of the technology in each.

Fig. 1—RTVFM general work flow in the DOF framework.

Case 1: Offshore Gas Field With No Multiphase Flowmeter (MPFM) Installed

The virtual-meter approach was successfully applied in an offshore gas field to estimate gas-production rates of each well in real time by using upstream-choke, bottomhole-pressure, and temperature-gauge data. The algorithms performed dynamic pressure-gradient calculations to find optimal solution rates to match physical sensor readings. The daily back-allocation methodology at well level did not rely on well rate measurements because MPFMs were not available at wellhead and only field fiscal production was measured. Technical measurements were available onshore for each separator train, but no dedicated test separator existed to test single wells periodically. In this framework, the RTVFM supported reservoir management by estimating production rates of each well in real time and by performing a daily back allocation.

The algorithms were calibrated at reference dates after startup on the basis of well-test interpretation output in an effort to match total field production measured at onshore facilities. The daily reference raw field total production was available from official reports, and was calculated as the sum of daily fiscal gas export production plus the consumption terms (fuel and flares).

Real-time technical measurements of produced gas were available for each separator train located onshore. The total sum of separator trains’ production measurements matched raw daily field production within acceptable limits of 1–2% and was plotted on productivity-index (PI) system screenshots together with total RTVFM simulated production and raw daily field production for quality checks.

After calibration at reference dates with stable production parameters, the virtual-meter algorithm was able to estimate gas production of each well automatically in real time by retrieving sensor data and saving the results into the DOF historian. The reliable outcomes of pressure and rate transient analysis application confirmed the quality of the RTVFM rate estimation. The allocated rates were also used as input data for 3D reservoir modeling, and a good-quality history match was achieved.

Case 2: Offshore Gas Field With MFPM Installed

The same methodology was applied to a gas and condensate field that was fully equipped with subsea MPFMs installed at each tree. Additionally, the total production of each flowline was monitored by a dedicated MPFM installed topside on the floating production unit, before the separator trains.

The results of this application demonstrated that virtual metering is a valid tool that can be applied as a redundant system in the presence of MPFMs installed on each wellhead, monitoring the performance and reliability of the MPFMs and troubleshooting for them. After virtual metering detected that malfunctioning had left only 30% of the MPFMs providing readings, a decision was made to modify the back-allocation procedure, using RTVFM production rates in place of MPFM ­readings to back-allocate total field production at well level.

The implementation of virtual metering also allowed careful monitoring of the wells’ production, because RTVFM provided a valid alternative to MPFM, thus enabling effective production optimization actions. Virtual-meter production profiles have been used to perform decline curve analysis for reserve evaluation.

Case 3: Offshore Oil Field With MPFM Installed

In an offshore oil field with variable production parameters, the RTVFM provided reliable, independent rate estimation by combining vertical lift performance and the pressure drop across the choke. By using the RTVFM algorithm, two production parameters evolving over time (i.e., variable oil and water cut with constant gas/oil ratio [GOR], or variable oil and GOR with constant water cut) can be simulated automatically.

This methodology was applied to an undersaturated oil reservoir. GOR was kept constant as an input parameter, because the reservoir pressure was above bubblepoint and pressure was supported by means of water injection. The algorithm found the optimal solution in terms of oil rate and water cut to match the tubing and choke pressure and temperature sensor readings. The real-time flow rate can be used as a basis for pro-rata allocation of fiscal production in the framework of a production data-management system (PDMS) software.


  • RTVFM can estimate well-production rates for gas fields, gas and condensate fields, and oil fields with variable water cut and GOR.
  • RTVFM estimated well gas rates for a field whose wells were not equipped with MPFM, showing the potential of replacing them, especially if the gas is dry.
  • RTVFM has been applied successfully to estimate well production rates correctly in real time.
  • An automated work flow for well-drawdown calculation has been developed to monitor wells.
  • The real-time production flow rates can be used as a basis for back-allocation of daily fiscal production to be performed in the framework of PDMS software. Daily average RTVFM rates can be queried directly from the PI system and used in the back-allocation work flow implemented in PDMS.
  • Virtual-meter outputs have been used to effectively monitor inflow performance relationship shape changes and static reservoir pressure decline with time.
  • In a gas condensate field with wells equipped with MPFMs, RTVFM helped assess which MPFMs were providing incorrect readings, and has been used as an alternative system for production monitoring, optimization, and daily back-allocation.
  • Potential exists to apply RTVFM methodology extensively to all digital assets equipped with MPFM to assess benefits and limitations.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196654, “The Benefits of Virtual Meter Applications on Production Monitoring and Reservoir Management,” by Fabrizio Ursini, Roberto Rossi, and Luca Castelnuovo, SPE, Eni, et al., prepared for the 2019 SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, 17–19 September. The paper has not been peer reviewed.