The scope of the vendor of subsea production systems often includes instrumentation and other types of flow measuring devices. Typically these include pressure and temperature sensors on the subsea tree and digital interfaces to downhole equivalents. In addition to this are flow meters for the measurement of single and multiphase flow rates on the gathering and injection networks. Whilst these present the traditional solution to the matter of flow measurement, powerful software based solutions are available, but are often overlooked or ruled out in the initial field development. An example of a useful solution (along with traditional alternatives) is the virtual flow meter or software simulation defined in the American Petroleum Institute's (API) Recommended Practice 86 (2005), which is fast becoming much needed real-time operational tools. This paper will review the key principles of a virtual flow meter by synthesising some of the important findings of several published papers. A quantitative analysis of the cost of implementing the traditional methods of flow measurement will be presented, along with a qualitative assessment of their value.

The Challenge

Measuring multiphase flow rate in the case of production networks is not trivial. The challenge illustrated by Figure 1 is to measure water, gas and oil flow rates where the flow regime is changing and, quite often, the composition of the well varies or deteriorates to water over time. Accurate metering of flow rates and prediction of water breakthrough are important issues in offshore oil production (Melbø 2003). The multiphase flow rates can be found, for instance, from frequent well testing, multiphase flow meters or software simulations. Multiphase flow meters are 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. (Fig. 1 is available in full paper)

Long Tiebacks and Inaccurate Instrumentation

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 in 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 minimising operating expenses (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, where the various owners may share the same infrastructure and production facilities. In such cases reliable production monitoring is of the utmost importance. 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 remotely, whereas hardware "such as a multiphase flow meter" usually needs to be maintained on the site.

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