Virtual Metering Tool Brings Real-Time Benefits to Production Monitoring
Authors: Feder Judy 
Published: February 2020

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 The paper has not been peer reviewed.

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.

Introduction

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.

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).