Accurately measuring oil, water, and gas flow rates is a significant difficulty for the oil and gas industry. Multiphase flow meters or wet gas flow meters (i.e. MPFMs) have opened the door to the development of marginal assets and promoted more efficient exploitation of larger fields. However, these MPFMs must be calibrated, and a correct uncertainty assessment is necessary. The new paradigm of the oil and gas industry is to calibrate them in the field and especially for the ones used in allocation, as well as to achieve in situ validation, to significantly cut OPEX. Indeed, MPFM’s manufacturers frequently charge a monthly fee to ensure the technology’s performance over time without being able to independently assert the MPFM's field performance, requiring the end-user to conduct their own tests to determine the MPFMs’ true field performance.

How do we address the MFPM performance? Two methods are available. The first method is to take the manufacturer’s statements and documentation. This is called the Type B analysis from an uncertainty point of view. But there is a fundamental assumption made with such analysis which believes the well production is stable; this is far to be the reality and especially when a long tieback is happening between the wellhead and the MPFM. Large sluggy behavior not because of the well production but from the pipe configuration either land or subsea can lead to such phenomena The analysis made by our expert has shown that the type B analysis is very optimistic and could be used only as a guideline for the best conditions and in the real life the reported MPFM performance is, on average, too optimistic, based on the manufacturer’s claims only. Additionally, it was shown that manufacturers rarely disclose the predicted output specification (i.e. uncertainty) of oil, water, and gas flow rates to the end user. Rather than that, they provide a mixture of various parameters at line conditions. The second method called also Type A analysis from an uncertainty point of view refers to the MPFM performances based on field data recorded from the MPFM which may or not require witnessing during the data collection following the regulation or contract in place between partners.

Finally, inherent to both methods, because, and in general, MPFM’s manufacturers lack the competence in fluid characteristics necessary to convert to standard circumstances, there is no way to establish a performance statement at standard conditions, which is the end user’s true requirement. This leaves the end-user to translate/calculate/convert any stated numbers to the expected parameters and associated values by themselves. Sometimes, the manufacturers have provided them with enough relevant data or information to achieve this. As this is left to manufacturers’ discretion, there are no standard requirements that can be applied directly and multiphase metering expertise is requested to achieve such a statement. This should, of course, include the traceability or uncertainty for the worst associated with the PVT package, which is unlikely to happen in 99 % of the cases that we have been facing.

In summary, to precisely describe the uncertainty and define the calibration frequency, and hence the MPFMs performance, expertise and precise calculations are required. A thorough mapping of MPFM performance to its in situ application should be established by oil and gas operators or third-party multiphase flowmeter experts – and validated at a calibration facility when possible. Utilizing a third party is helpful because it avoids buyer-seller conflict of who is right between both stakeholders.

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