Testing wells, which produce 1-2% liquid in the presence of 99-98% gas volume, is very difficult. The mixture is far from homogeneous, and task is similar to looking for a needle in a haystack. Yet, in the case of condensates, the dollar value of the liquid may equal that of the gas. Biggest economic justification is the case of Gas Lift, where proper gas injection control can make a significant contribution to the profitability of the operation. If the gas contains water, the treatment is very expensive, so knowledge of the exact nature of the produced fluid is essential for proper reservoir control and optimization. In gas wells applications for example, it is crucial to measure the small amounts of liquid to the highest degree of accuracy, since this data is necessary to monitor and control hydrate formation. The difficulty is in the accurate measurement of 2% of the total flow. For 5% accuracy of reading of the liquid flow rate, one requires 0.02 × 0.05 = 0.001, or 0.1% accuracy of the total flow. Moreover, additional knowledge is required to know the water content of the condensates. In the case of multi-layered production, this knowledge contributes a lot to profitability.
The difficulty in achieving this high degree of accuracy is compounded by the nature of the flow. Since the liquid tends to stick to the pipe walls, and is being dragged behind the gas, which is flowing at high velocity in the center of the pipe (Annular Flow). The gas is also carrying with it liquid droplets torn from the walls. Due to uneven terrain or vertical risers, pockets of liquid form at the lowest points, which are shot out in the form of slugs flowing at near the velocity of the gas. Knowledge of these slugs flow helps the design of compressors, slug-catchers, etc.
Field experience with Multi-Phase Flow Meters which operate at Gas lift and Wet gas applications is described in this paper.

Wet Gas Metering is becoming increasingly important to the Natural Gas Production Industry as "Wet Gas" flows are becoming more common in the field and the addition of a field separator is prohibitively expensive. "Wet Gas" is defined here as all flows with a Gas Volume Fractions greater than 95%. There is no agreement in industry to which wet gas metering method is best. Of all the published two-phase flow Differential Pressure (DP) Meter correlations this research has shown seven to be of possible relevance. This paper uses new independent data to compare their performance. Finally, a new correlation is offered.

Monitoring of the multiphase flow at the wellhead eliminates the need for dedicated testlines from remote wellhead completions, and the need for a dedicated test separator at the processing facility. A multiphase flowmeter at the wellhead will also allow improved well control, and hence better reservoir control. For remote or deep subsea wellhead completions the savings and operational benefits offered by this new technology are quite extensive.
In summer of 1997, Petrobras installed a Fluenta multiphase meter in a subsea production manifold, at 450 meter water depth at the Albacora field offshore Brazil. 20 months later, at the end of January 1999, the meter was powered up, signal communication was established, and calibrations were checked and verified. First oil through the meter was in early May 1999. The paper reports the operational experiences from first year of operation, and providse evaulation of measurement performance, compared to the conventional test separator.
Since the development of the subsea multiphase meter for Petrobras, the technology has been further developed to a new, compact design for ROV installation at water depth down to 2500 meters. Design and intervention concept for this new version is presented.

This work presents the facilities of the "Sitio de Teste de Atalaia" (Atalaia test site) from Petrobras, located in Aracaju, Brazil. It was installed in 1994 to investigate the performance and endurance of different equipments related to artificial lift systems or multiphase flow installations, such as gas lift valves, meters, boosters and pumps. A large scale flow loop, 220-meters long and 6-inches of internal diameter, was designed to conduct two and three-phase flow tests. The multiphase flow loop is capable of flowing natural gas, crude oil and water simultaneously, at pressures up to 45 bar. Maximum flow rates are 400 STD m³/h of gas, 120 m³/h of oil and 76 m³/h of water. With these flow rates and pressure ranges, all multiphase flow patterns encountered in operating pipelines can be obtained. A control & data acquisition system is used to acquire data from any equipment under test and from several resident measurement devices. It also provides the necessary control for the flow loop. Experience shows that a very good control of all the flow variables is achieved with this system. The following equipment were tested in the last four years at Atalaia: multiphase flowmeters from Fluenta, Framo and Mixmeter; two-phase flowmeter from ITT Barton; Bornemann's multiphase pumping system; and VASPS separation system (using both Agip and Petrobras-Unicamp designs). The following activities are scheduled for the year 2000: drilling and completion of a testing well 300- meters deep; testing of a WEMD-Leistritz subsea multiphase pumping system; testing of multiphase flowmeters from Framo, DUET and MFI; and phase II of the gas lift valves performance tests.

The popularity of Coriolis meters continues to grow, largely as a result of the high performance and field robustness of dual, curved tube Coriolis meters. Such curved tube designs solved many of the problems that plagued early Coriolis meters, such as mount sensitivity and vibration effects.
Although dual, curved tube Coriolis meters have gained acceptance, this design does not meet all application needs. In some applications, a single straight tube Coriolis meter is required due to process considerations, such as plugging problems, drainablity, and compactness.
Recently, a new single straight tube Coriolis meter having the high performance and field robustness of dual, curved tube Coriolis meters has been introduced. The development of this new flow meter employed advanced computer aided modeling techniques to accurately simulate and mitigate variations due to changing field conditions, including changes in meter installation practices, fluid density, and fluid temperature.
This paper will review and compare the technical challenges associated with designing curved tube and straight tube Coriolis meters, and will provide performance data to support the field robustness of the new straight tube design.