Using multiphase flowmeters in field operations has now become a widely accepted practice especially in the range of Gas Volume Fraction (GVF) of 0 to 85%. There is still some doubt about the performance of this type of device especially in the High (92–96%) or Very High GVF (96–98%) ranges. Most of the purchasers put a cut off in the GVF range of 85–92% following the type of technology. These criteria are often based on past experience or special cases, which could be several years old. A split in terms of naming is even commonly accepted in the multiphase business between Multiphase Flow Meter and Wet Gas Meter. With the recent dedicated Gas Mode developed by Schlumberger, it is now possible to test both gas and oil wells with the same hardware. The focus put in the past few years on a combination of robust and simple measurements (Venturi and gamma ray) in multiphase flow-metering solutions for any type of well based on the advantages and benefits of the industry recognized Vx* Technology. In this paper, we will review the benefit of the combination of Venturi and gamma ray fraction meter and its application to gas well testing. Today, the use of the entire information of a gamma ray spectrum gamma ray (more than 2 rays) allows a real-time or an a posteriori quality control and improvement of the overall performance of the meter in any type of conditions. This statement will be presented through a campaign of tests done in South America. First of all, we will show how the entire information of a gamma ray spectrum permits a quality control in real time, and allows tracking of fluid composition change over time. Then we will focus on high producing gas wells clean-up that have been successfully tested using the Vx technology in Gas Mode in 2005. Exceptional results against conventional test separator have been presented in previous paper (Ref [10]) with a maximum error of 2–3% for the gas. The current paper will also put a special emphasis on the salinity change. Introduction A 3 phase flow measurement requires as minimum information the velocity for each phase (i.e. 3 velocity measurements) and 2 holdups (i.e. fractions) knowing that the sum of the 3 holdups is equal to 1. Numerous techniques exist to try to achieve these 5 measurements ([Ref [1, 2, and 9]). Meanwhile, a multiphase flowmeter is measuring at line conditions the different flowrates; therefore it is necessary to associate two other measurements for PVT Conversion from line to standard conditions (i.e. Pressure and Temperature Sensors). The most common technique used in the industry to measure flowrates is the Venturi (or differential measurements); all manufacturers are using one or several Venturi and most of the time coupled with a density nuclear measurement. The fraction measurement techniques are more versatile and we could split them between low energy gamma ray measurement, the most common one, and electromagnetic measurement. The former is the simplest option to get the multiphase meter as less complex as possible. Indeed, the high energy gamma ray being already present for density measurement, the addition of a second radionuclide or an appropriate chemical source could provide the two energy levels required to do the fraction measurement [Ref 2]. This leads to a compact and efficient solution.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe identification of condensate banking has always been a challenge. Furthermore, large productivity losses can result from the absence of early detection of a condensate bank in the near well bore area of the well. The traditional means of detecting a condensate bank range from comparison of the dew point to downhole pressure measurements, identification of composite radial models and quantification of skin using pressure transient analysis. One of the methodologies that have been more theoretical than practical has been the detection of a leaner stream of effluent at the well head during production. This type of approach has been quite challenging in the past, as a high resolution measurement of the condensate to gas ratio is essential to a successful diagnostics of condensate banking.The paper presents a case of analysis of the development of a condensate bank during a well test. The multiphase flowmeter identified a gradual reduction of the condensate to gas ratio with increasing choke sizes. The methodology of diagnostics is demonstrated, in particular with the discrimination against liquid loading issues.The PVT compositional analysis provides a verification of the analysis, and the observation of the evolution of the phase diagram leads a further understanding the downhole and near well bore thermodynamic phenomena.The degradation of the productivity of the well is also analyzed, with a significant drop of gas productivity observed even on smaller choke sizes at the end of the test.Finally the paper presents a numerical simulation match of the data and provides a number of recommendations for the utilization of single well -near well bore compositional models to help interpreter to obtain better and simpler matches.This paper provides a new methodology to make full use of the benefits of the dual energy gamma Venturi multiphase flowmeters in the evaluation of gas wells. Operational issues related to gas well testing with traditional test separatorsThe test of gas wells has always been a challenge compared to testing oil wells. The high level of energy contained in the stream in the form of compressible fluids, the higher pressure usually encountered at surface due to the lower hydrostatic head in the tubing and the potential presence of toxic components such as H2S in the effluent contribute to increase the Health and Safety risks inherent in the handling of gas wells.On the operational side, the presence of water in the stream combined with a large temperature drop across restriction or the choke can lead to severe plugging issues with hydrates.Erosion can also be a serious risk encountered with the combination of high fluid velocities (in particular at low pressure) and a bit of sand. Perforation of the walls of the surface piping can present very serious risk to the operational personnel and the facilities.However, the main difficulty of testing gas wells comes from the determination of accurate gas, condensate and water flow rate measurements. The sh...

The identification of condensate banking has always been a challenge. Furthermore, large productivity losses can result from the absence of early detection of a condensate bank in the near well bore area of the well. The traditional means of detecting a condensate bank range from comparison of the dew point to downhole pressure measurements, identification of composite radial models and quantification of skin using pressure transient analysis. One of the methodologies that have been more theoretical than practical has been the detection of a leaner stream of effluent at the well head during production. This type of approach has been quite challenging in the past, as a high resolution measurement of the condensate to gas ratio is essential to a successful diagnostics of condensate banking. The paper presents a case of analysis of the development of a condensate bank during a well test. The multiphase flowmeter identified a gradual reduction of the condensate to gas ratio with increasing choke sizes. The methodology of diagnostics is demonstrated, in particular with the discrimination against liquid loading issues. The PVT compositional analysis provides a verification of the analysis, and the observation of the evolution of the phase diagram leads a further understanding the downhole and near well bore thermodynamic phenomena. The degradation of the productivity of the well is also analyzed, with a significant drop of gas productivity observed even on smaller choke sizes at the end of the test. Finally the paper presents a numerical simulation match of the data and provides a number of recommendations for the utilization of single well - near well bore compositional models to help interpreter to obtain better and simpler matches. This paper provides a new methodology to make full use of the benefits of the dual energy gamma Venturi multiphase flowmeters in the evaluation of gas wells. Operational issues related to gas well testing with traditional test separators The test of gas wells has always been a challenge compared to testing oil wells. The high level of energy contained in the stream in the form of compressible fluids, the higher pressure usually encountered at surface due to the lower hydrostatic head in the tubing and the potential presence of toxic components such as H2S in the effluent contribute to increase the Health and Safety risks inherent in the handling of gas wells. On the operational side, the presence of water in the stream combined with a large temperature drop across restriction or the choke can lead to severe plugging issues with hydrates. Erosion can also be a serious risk encountered with the combination of high fluid velocities (in particular at low pressure) and a bit of sand. Perforation of the walls of the surface piping can present very serious risk to the operational personnel and the facilities. However, the main difficulty of testing gas wells comes from the determination of accurate gas, condensate and water flow rate measurements. The short retention time in traditional test separators can lead to significant carry over of condensate in the gas line, resulting in an underestimation of the condensate rate, and a potentially significant error on the gas rate. The level of error on the gas rate will depend on the type of measurement technology used. If traditional orifice plate is used, the presence of condensate in the gas stream leads usually to an overestimate of the gas rate. The error on the gas measurement can also be compounded with the accumulation of well liquids (water or condensate) in the legs of the DP cell around an orifice plate which can create large errors (usually identifiable in the raw data by a near linear trend of drift of the DP measurement). There can also be significant amount of liquid trapped at the bottom of the pipe in front of the orifice plate which also can affect the flow rate measurements. The field identification of such problem can be straight forward, but its remediation may be impossible during the course of the well test operation.

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