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FLOW & LEVEL CONTROL


MAPPING MFM PERFORMANCE


Dr Bruno Pinguet, Multiphase Domain senior advisor at TÜV SÜD National Engineering Laboratory, explains how it is possible to achieve the utopia of in-situ flow meter calibration


challenge. Multiphase flow meters (MFMs) have opened the door to the development of marginal assets and enabled more efficient exploitation of larger fields. The ability to provide real-time flow


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measurement will lead to a greater uptake in MFMs worldwide but, because of the costs required to send them back to facilities for calibration, the challenges of validating them in-situ throughout their time in service must be addressed. However, the use of MFMs in oil and gas applications, particularly when installed for remote or subsea applications, is fraught with challenges and so far, little has been done to address the challenges associated with their ongoing verification or calibration in-situ, for both topside and subsea installations.


Accurate conversion All metering devices monitoring oil and gas flows provide information at the in-situ conditions (i.e., at line pressure and temperature). Meanwhile, the volumetric flow rate of water, oil, and gas needs to be converted to standard conditions i.e. at a well-defined and agreed pressure and


24 MAY 2022 | PROCESS & CONTROL


or the oil & gas industry, accurately measuring a mixture of oil, water and gas in field conditions is a major


temperature. To accurately convert in-situ meter readings to report flow rates at standard conditions requires knowledge of fluid properties as process conditions change (pressure-volume-temperature (PVT) relationships). This is irrespective of the type of meter or technology used.


Significant correction MFMs are particularly affected using the PVT information for two main reasons. They can be working at extremely high pressure and temperature, which requires a significant correction to convert the measured flow rates to standard conditions. This will have an effect on flow measurement accuracy if not properly accounted for. Also, because no separation is made between the different flow phases, a large amount of gas can be dissolved inside the oil, or some condensates could be in gas phases at meter conditions but liquid at standard conditions. An uncertainty budget for the flow meter


when in use must therefore be constructed, taking into account additional uncertainties arising from interpolation and extrapolation from calibration conditions. Traceability is the process of proving the performance of equipment for each stage of calibration. To provide the highest quality of measurement


and therefore, the lowest uncertainty budget, flow meters should be traceable to primary standards, which are calibrated against National Measurement Standards. It is important to have a proper mapping


of the performance and uncertainty of an MFM based on the expected profile of oil and gas production. However, end-users face a substantial challenge when trying to fully understand meter performance because the information that is readily available will most likely be generic, and not relevant to the actual field conditions that the meter will experience.


Valid and useful Research carried out at TÜV SÜD National Engineering Laboratory has shown that generic meter performance figures are unsuitable for use in actual field service, both in terms of accuracy and in the way they are presented. They often provide a combination of different parameters at line conditions because they do not have the expertise in fluid properties to translate to standard conditions. This means that the end-user often must convert units and values to make the corrections valid and useful. When the end-user has selected an MFM, the fluid behaviour should also be


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