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Abstract The accurate measurement of multiphase rates of produced oil, water and gas has always been a significant challenge to the oil and gas industry. Over the last few decades the traditional approach driven by the use of test separators has gradually been replaced by multiphase flow meters, which offer continuous monitoring of multiphase rates in real-time, without separating phases. Currently, there are multiple technologies available on the market, but multiphase flow meters generally are incapable to handle all ranges of fluid properties and operating conditions with satisfactory accuracy in addition to being expensive to purchase and maintain. The last point has motivated the oil and gas industry to seek other alternative metering technologies. In particular, the emergence of cheap sensors and their widespread installation in production systems has led to an exponential increase in data availability obtained from a well. These data combined with a dedicated mathematical algorithm can facilitate the extraction of actionable information relevant to multiphase flow rates. This methodology, which is also known as a Virtual Flow Metering (VFM), is a promising tool which is capable to mitigate the disadvantages of conventional multiphase flow metering and provides the functionality which was not previously available, such as an estimation of downhole flow rates. The objective of this review paper is to outline the current challenges within multiphase flow measurements and to introduce the most promising digital techniques, which have the potential to become a digital successor of a multiphase flow meters.
Gryzlov et al. (Mon,) studied this question.