_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 230172, “Autodiagnostic Solution for Multiphase-Flowmeter Systems: Case Study and Lessons Learned From an Oil Operator in Abu Dhabi, ” by Erismar Rubio, SPE, Gaurav Gupta, SPE, and Abdallah Al Ameri, ADNOC, et al. The paper has not been peer-reviewed. _ This paper offers a comprehensive exploration into the field applications of multiphase flowmeters (MPFMs) across global contexts and the insights from a smart oil field that represents an exemplary sample for evaluating MPFM technologies because it encompasses several types of MPFM available in the market. The study uncovers lessons learned and best practices derived from diverse operational environments that drove the development of a robust autodiagnostic solution to enhance MPFM performance. Introduction Recent field studies have demonstrated that the performance of MPFMs can vary widely depending on asset-specific characteristics and operational practices. Lessons learned from these applications highlight the necessity for robust autodiagnostic capabilities and continuous calibration to address measurement uncertainties and maintain high standards of data integrity. A benchmark study across several onshore assets revealed one asset in particular experiencing high well-test-rejection rates after MPFM installation, resulting in inefficiency and poor reservoir management. After an in-depth investigation, the sources of errors were identified and an autodiagnostic tool was developed to detect MPFM issues automatically by integrating real-time equipment alarms, ensuring well-test quality and identifying equipment or fluid property problems on the spot. This solution increased test-acceptance rates from 50 to 85%, reducing discrepancies with portable separators, and significantly improved system efficiency and production performance. Flow-Loop Tests Recent research demonstrates that MPFMs can operate at high gas/volume fractions (GVF) in the range of 85–99%; however, accuracy degrades significantly under these conditions. A review of more than 30 technical papers covering real field applications across diverse operating regions confirms that measurements errors range from 15 to 40% for the main phase (oil) at high GVF. In the complete paper, the authors selected two previous studies most relevant to the studied fields and referred to those studies as examples. Discrepancies in liquid measurement have been observed between three-phase separators and MPFMs using dual gamma technology under high-GVF conditions, particularly in gas lifted wells. These liquid-rate deviations have been attributed to the turbulent-flow fluctuations that occur within the venturi section of MPFMs, phenomena that may not be captured adequately by traditional three-phase separators. Despite these findings, operational experience in the fields studied suggests that the elevated liquid rates recorded by MPFMs are not always consistent with the established production profiles of individual wells. In many instances, these discrepancies are inconsistent with the volumes recorded by custody transfer meters at the field level. Additionally, irregular fluctuations in water cut and gas/oil ratio (GOR) were observed that did not correspond to expected physical behavior. Moreover, real-time wellhead data showed that differential pressure fluctuations were noisier and wider than those seen by wellhead-flowing-temperature and pressure transmitters and did not align with slugging patterns, while both instant and cumulative rates from the three-phase separator could closely match the well flow at the nearby wellhead.
Chris Carpenter (Sun,) studied this question.