Software That Enables Flow Metering of Well Rates With Long Tiebacks and With Limited or Inaccurate Instrumentation
Authors: Melbø Hallgeir , Morud Svein Arne , van der Geest Robert , Bringeda Bjørn , Stenersen Kjetil 
Published: October 2008

Abstract
Accurate metering of flow rates and prediction of water breakthrough are important issues in offshore oil production. The multiphase flow rates can be found for instance from frequent well testing, from multiphase flow meters, or from software simulations. Multiphase flow meters are very expensive and so are single-well tests, especially in cases with long tiebacks. On the contrary, software simulations are cheap, they can be made accurate, and simulations can usually be based on existing sensors. Also, software is easy to install, operate, and maintain compared to hardware multiphase meters.
In this article we describe the main components needed in a flexible software system for flow metering that can handle sparsely instrumented production facilities. Several sources of implicit information are pointed out, and a tuning strategy that avoids single-well tests is described. We also present examples that show the power of advanced simulations in situations that are not well handled by multiphase flow meters and standard software because of very low flow rates. What makes the situation in the examples even harder is that: There is no available information about the choke, the bottom hole sensors fail, and the temperature measurements are influenced by the seawater temperature. Despite this, good results are obtained.

Introduction
The offshore oil industry is facing a market where the number of brown fields is growing, and where more and more of the green fields are marginal fields. In addition, many of the new findings are on deep water. These facts all point in the direction of more production networks with long tiebacks, a stronger need for limiting the number of expensive well tests, and a push towards minimizing OPEX in general. The need for reliable monitoring of the production from each well in a production network is therefore continuously increasing. Furthermore, reservoirs may have more than one owner, whereas the various owners may share the same infrastructure and production facilities. In such cases reliable production monitoring is of course highly demanded.
A software system for flow rate estimation may satisfy the above needs. Software is relatively cheap, and both installation and usage can be made very easy. Furthermore, software is easily maintained and supervised from remote, whereas hardware, such as a multiphase flow meter, usually needs to be maintained on the site. This is an important issue since many larger green fields are far away from where many of the oil companies' expertise traditionally is situated. Remote access can easily be obtained using standard web browsers and internet technology.
However, if the instrumentation is sparse or inaccurate most software systems will not give reliable rate estimates. In this article we will look at how to deal with such problems. We will present the main building blocks for a flexible software system that can handle almost any production network configuration. We also show how inaccurate measurements and what may look like useless information may contribute to good rate estimates.