Multiphase metering technology continues to evolve, with significant implications for the oil and gas industry. Current technology is sufficiently capable for some oilfield applications and requires further development for others, particularly low-maintenance measurement of high GVF fluids. This paper discusses a field trial of four commercially available multiphase meters, including the test set-up, meter evaluation criteria, and general conclusions.
Accurate determination of oil, water, and gas production rates is an important element of oilfield management and optimization. Information from well testing is used for identification of wellwork and in-field development opportunities, artificial lift optimization and troubleshooting, and optimization of production through surface facilities. Additionally, well tests have direct impact on fiscal accounting, reservoir management, and production forecasting. Metering of fluids from production wells has traditionally utilized large separation vessels to separate the combined fluid into gas, oil, and water streams, which are then measured individually. More recent methods involve twophase separation into gas and liquid streams, with supplementary metering to determine the water/oil fraction of the liquid stream.
Traditional test separators are large pressure vessels (with significant capital expense), requiring a large footprint, overpressure protection, and chemical injection to break oil/water emulsions. Due to the volume capacity of the vessels and test pipelines (particularly in subsea fields), lengthy purge and stabilization periods are required between wells, reducing the efficiency of the testing system. Solids build-up in the vessel affects separation efficiency by altering effective fluid level, weir height, and retention time. The production characteristics of wells are masked by the dampening effects of a large vessel, and additionally this limits the potential for gas lift optimisation.
A multiphase flow meter (MFM) capable of accurate flow measurements could provide significant cost savings and improved well management and optimization. In an onshore development, a MFM permanently installed on the production line of every well would eliminate the need for a traditional test vessel, separate test header, and the associated divert valves. This would also reduce the footprint of the pad, the fire and gas suppression requirements, and the necessary automation and safety systems. Continuous monitoring would also provide the ability to make much faster, better-informed decisions and well interventions. Many MFMs claim considerable tolerance to emulsion, which has the potential to reduce the dependence and cost associated with emulsion breaker.
MFMs also have the potential to augment or replace traditional pad separators that are consistently troublesome. In addition to more frequent and timely information on well production, ultimately this could reduce operator dependence on portable testing units which are currently employed for compliance testing. MFMs also have the potential to replace the portable testing units themselves. Elimination of the vessel means a more mobile, more efficient operation, with no purge time, reduced rig-up and rig-down time, and increased testing frequency in a given time period. Elimination of the vessel also reduces HSE exposure by eliminating overpressure potential at a weak point in the system.
Previous industry experiences with multiphase flow meters included operational problems arising from constant recalibration requirements, mechanical breakdown, "black box" data output, and measurement inaccuracies at high gas volume fraction (GVF, the volume fraction of gas as seen by the meter, at line pressure and temperature). In an effort to evaluate the current technology available, a field trial was performed in September of 2003 on the North Slope of Alaska.