Canadian Journal on Scientific and Industrial Research Vol. 2, No. 8, November 2011
Multiphase Flow Meters Principles and Applications: Applications: A Review Samir Teniou and Mahmoud Meribout — The needs of the chemical, petrochemical, gas and oil pipeline stimulate rapid developments in instrumentation applicable to two and three-phase flow measurement. In this paper, the basic concepts and principles of multiphase flow metering (MPFM) and its applications for the oil and gas industry are introduced. We present a review of key techniques suitable to measure the flow rates of gas, oil and water in a three-phase flow and we discuss a variety of instruments and measurement techniques that have appeared in the recent literature. Some available MPFM technologies, their advantages and limitations are also described.
Abstract
Index Terms—Flow rate, fraction measurements, multiphase
flow, separators, velocity measurement.
I. INTRODUCTION Traditionally, the flow rates of well fluids have been measured by separating the phases by separators and measuring the outputs of the separated fluids by conventional single-phase techniques, e.g., orifice plates for gas and turbine meters for oil. There are some problems with the required three-phase separators: their bulk, high installation cost and considerable maintenance. In addition operation conditions sometimes prevent complete separation of the fluid phases. These conditions cause errors in separator instruments, which are designed to measure streams of single phase gas, oil or water. Moreover, obtaining reliable measurements from test separators require relatively stable conditions, which can take much time. Therefore, it is highly attractive to have a relatively simple suitable instrument, called a multiphase flow meter (MPFM), which is capable of measuring the flow rate of each component directly, without separation.
Within the oil and gas industry, it is generally recognized that MPFM’s could lead to great benefits in terms of: reservoir management, layout of production facilities, well testing, production allocation and monitoring [1]-[3]. For example, in offshore production consisting of several nearby wells (Fig. 1), flow data gathered along a pipeline section of a given well can help in identifying how this well contributes to the aggregate flow and, hence, may help in locating a production anomaly, such as a water or gas breakthrough in the actual well. This allows an easier localization of well stimulation or other well treatments, such as enhanced oil recovery, to be performed to increase the well productivity. In another application, a downhole monitoring of the multiphase flow allows well engineers to control more effectively the propagation of the oil from the actual well by adequately controlling the array of valves in that well (e.g., switching off the valve surrounded by high water cut fluid).
II. BASIC CONCEPTS Unfortunately there is no single instrument, which will measure the flow rates of the different phases directly and it is necessary to combine several devices in an instrument package and to calculate the specific flow rates from the combined readings. There are many possible combinations, and the number of instruments required depends upon whether or not the three components can be mixed together upstream of the instrumentation (homogeneous flow). To compute the flow rates of each phase, the basic parameters of phase velocities and phase fractions (or quantities that can be unequivocally related to these) are measured.
Fig. 1. Example of application of the MPFM in oil fields. 290
Canadian Journal on Scientific and Industrial Research Vol. 2, No. 8, November 2011 The phase velocities and fractions are then combined together to provide the phase flow rate (Fig.2.). Gas, Oil and water fractions measurement ��
Component velocity measurement
Component volume fraction measurements Capacitance Conductivity
Component density measurement
� �
Single/Multiple gamma ray Absorption
� �
Microwave and infrared Volumetric flow rates
Velocity measurements
Venturi Positive displacement device Coriolis device Cross correlation techniques Acoustic attenuation
Table .1. Most used measurement techniques in a MPFM
� �
Mass flow rates � �
Fig .2. Inferential method for multiphase flow measurement For a three-phase flow, three mean velocities and threephase cross-sections are required. Thus, five parameters are needed, namely: three velocities and two-phase fractions (the third-phase fraction is obtained by difference between unity and the sum of the two measured fractions). However the number of required measurements can be reduced by homogenization. By homogenizing the mixture, in such a way that the slip velocity between all the three phases of the fluid becomes negligible; making the individual velocities approximately equal; only one velocity needs measuring and the total measurement requirement can be reduced to three. However, this technique might be valid only if all components of the fluid are in the liquid phase since the liquid flow rate is usually substantially different from the gas flow rate in normal multiphase transportation because of density difference [6]. Another problem is, Even if the gas and liquid velocities become nearly equal immediately downstream of the homogenizer, the situation would quickly change with the velocities becoming unequal and, possibly more important, phase separation taking place under the influence of gravity. Density data for all three components is readily available from other parts of the production process or can be estimated using PVT diagrams. Thus, the problem is to measure the component velocities and two of the three component volume fractions, usually the gas phase fraction and the liquid phase water fraction. Different measurement techniques and strategies can be used to obtain phase fraction and phase velocity information, Tab. 1. illustrates the most used strategies.
III. LITERATURE SURVEY Multiphase flow is a complex phenomenon that is difficult to understand, predict, and model. Common single-phase characteristics, such as velocity profile, turbulence, and boundary layer, are thus inappropriate for describing the nature of such flows.
Thus, most of the existing MPFMs [7]–[13] rely on the electrical (e.g., dielectric properties) and/or other nonelectrical properties (e.g., waves or energy propagation) of the individual phases that compose the mixed fluid to proceed with a proper calibration using either pattern recognition or lookup table techniques, but rarely with analytical equations. MPFMs using gamma- or X-rays have been successfully tested in several oil fields [14], [15]–[17]. Their principle is to emit one or several waves to determine the fractions of each individual flow composing the mixed fluid. Thus, by knowing the total flow rate of this fluid using the venturi meter, the individual flow rates of oil, water, and gas can be determined. However, these meters are radioactive and, thus, are not safe to be deployed in hazardous oil fields. In addition, their accuracy greatly decreases with the presence of gas (e. g., more than 20% error for more than 90% gas). The reason is that the online gas–liquid separator embedded in these meters may not entirely separate the gas phase from the liquid phase, inducing substantial errors to the water-cut meter, which is connected to the liquid outlet of the separator. To remedy the errors introduced by the online separator, other MPFMs do not use any separator but instead mix the flow using mechanical mixers in such a way that the slip velocity between all the three phases of the fluid become negligible, making the individual velocities approximately equal [4], [5]. However, this concept might be valid only if all components of the fluid are in the liquid phase since the liquid flow rate is usually substantially different from the gas flow rate in normal multiphase transportation because of density difference [6]. MPFMs using this approach [14] have achieved more than 20% error in the experiments since the used equations ignored any interaction between the gas and the liquid phases. Other nonradioactive commercially available meters, which rely on the electrical properties of the mixed fluid, use the capacitance and conductance readings to determine oil, gas, and water fractions [18], [19]. In addition, they use pressure sensors, a temperature sensor, and cross correlation for liquid flow rate measurement. These MPFMs have the advantage of being safe. However, their accuracy is weak in the water-cut range of 40%–60%. The reason is that within this range, the mixed fluid is neither totally conductive nor an isolator, thus leading to almost the same sensor outputs within this range. In addition, these meters are inaccurate for the water-cut range greater than 90%. Another solution proposed in [20] uses a water-cut meter and a volumetric flow-meter for measuring the gas and liquid phases. This invention is complicated
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Canadian Journal on Scientific and Industrial Research Vol. 2, No. 8, November 2011 because it requires a positive displacement instrument so it can avoid the problem of slip between the gas and liquid phases. In addition, this system does not appear to be effective for liquid fractions below about 10%. Another field programmable-gate-array-based device addressed in [10] has been presented to compute the total mass flow rate of the fluid passing through it. The device has no moving mechanical parts to wear out; therefore, its theoretical lifespan is almost infinite. However, the device cannot deliver the flow rates of each individual phase constituting the fluid and becomes inaccurate with the presence of the gas phase. Other embedded and processor-based devices for the measurement of the quantity of the fuel in the engine have been proposed in [11] and [12], and their accuracy is claimed to be high and independent of the fluid properties (e.g., viscosity, temperature, and density). However, these devices are only dedicated for one single phase and do not seem to be applicable for the gas phase.
IV. OVERVIEW OF COMMERCIAL MULTIPHASE FLOW METERS In this section we describe some of the available MPFM’s [9], [21]: A. Agar MPFM-301
The flowmeter contains a rotary positive displacement flowmeter, modified for multiphase use, and two venturis in series in a vertically upward flow. The water content of the flow is derived from the power absorbed by the process fluid from an in-line microwave monitor. The continuous liquid phase is detected by the phase shift between the transmitter and two differentially spaced aerials. The measurement of the liquid phase water cut can then be derived from the gas fraction and the microwave monitor output, individual oil, water and gas flow rates are then computed from these variables. B. CSIROMFM
This flowmeter uses the attenuation of gamma rays at two different energies to derive the oil, water and gas phase fractions. The mass absorption coefficients of oil and water vary as a function of gamma photon energy and the difference between the coefficients for oil and water is also a function of the photon energy. These differences can be utilized to measure the phase fractions. To maximize the transmission of the lower energy gamma rays the sources and detectors are arranged around a GRP pipe section. Velocity measurement is by cross-correlation of multiphase flow features, slugs and bubbles for example. C. Fluenta MPFM 1900VI This meter uses several different sensors in combination. Capacitance and inductance sensors are used to measure bulk electrical properties of the flowing mixture in oil and water continuous flows respectively, and derive water cut from these measurements. A single energy gamma densitometer measures the average bulk density by attenuation of gamma photons. The phase fractions can then be extracted from this information. Velocity measurement is by a combination of cross-correlation of capacitance signals and venturi
differential pressure in oil continuous flow and from the venturi differential pressure in water continuous flow. Velocity and phase fraction measurements are then combined to give phase flow rate information. D. Framo MPFM
A mixer is utilized to pre-condition the flow entering a venturimeter. The mixer consists of a large plenum chamber and piccolo tube. The piccolo tube penetrates the base of the plenum chamber and conducts the flow to the venturimeter, the aim being to draw the gas and liquid into the venturi at equal velocity. The differential pressure across the venturimeter is proportional to the total volume flow rate. A dual-energy gamma densitometer is mounted at the throat of the venturi and is used to derive phase fractions. The phase flow rates are then calculated from these and from the total flow rate. E. Haimo MPFM
The Haimo MPFM consists of cross correlation meter (two single gamma sensors), venture meter, dual gamma source sensor, gas conditioning cyclone, vortex meter and a static flow conditioner. It also includes two pressure transmitters, DP transmitter, temperature transmitter, an electric controlled control valve and a data acquisition and analysis system. Basically, phase fractions are derived from two separate independent measurements, i.e. water cut in the liquid and gas fraction of the entire flow. Gas and liquid velocities are determined based n the cross correlation measurement and a slip relation included in the software model with an assumption that the difference between oil and water velocities could be neglected. Temperature and pressure are also measured and assumed equal in all phases. The system obtains the phase flow rates by determining the cross correlation areas occupied by each phase, and multiplying each area by the velocity of the corresponding phase. The gas conditioning cyclone reduces the amount of gas in the mixture by separating some of the gas away from the total flow. The separated gas is measured separately using the vortex flow meter. In the case of low GVF, the venturi meter is used instead for measuring the total flow rate. F. Halliburton FlowSys MPFM
The meter comprises a Venturi (with the standard differential pressure, pressure and temperature sensors). In the throat of the Venturi an array of permittivity and conductivity sensors are used to measure both the liquid and the gas velocities by means of cross correlation. Hence, the velocity (flow rate) measurements are not done by the Venturi; instead the Venturi is used to measure the fluid density which is an indication for the GVF. The permittivity and conductivity measurements are used to split the liquid into water and oil. G. ICC Mixmeter
The Mixmeter makes use of two separate radioactive sources to measure both the phase fractions of the multiphase mixture and the mixture velocity. An integral part of the flowmeter is a static mixer homogenizer which conditions the mixture so that an even distribution of the phases is maintained at the measurement cross-section. The phase fractions are 292
Canadian Journal on Scientific and Industrial Research Vol. 2, No. 8, November 2011
Multiphase Flow Meters Principles and Applications: Applications: A Review Samir Teniou and Mahmoud Meribout — The needs of the chemical, petrochemical, gas and oil pipeline stimulate rapid developments in instrumentation applicable to two and three-phase flow measurement. In this paper, the basic concepts and principles of multiphase flow metering (MPFM) and its applications for the oil and gas industry are introduced. We present a review of key techniques suitable to measure the flow rates of gas, oil and water in a three-phase flow and we discuss a variety of instruments and measurement techniques that have appeared in the recent literature. Some available MPFM technologies, their advantages and limitations are also described.
Abstract
Index Terms—Flow rate, fraction measurements, multiphase
flow, separators, velocity measurement.
I. INTRODUCTION Traditionally, the flow rates of well fluids have been measured by separating the phases by separators and measuring the outputs of the separated fluids by conventional single-phase techniques, e.g., orifice plates for gas and turbine meters for oil. There are some problems with the required three-phase separators: their bulk, high installation cost and considerable maintenance. In addition operation conditions sometimes prevent complete separation of the fluid phases. These conditions cause errors in separator instruments, which are designed to measure streams of single phase gas, oil or water. Moreover, obtaining reliable measurements from test separators require relatively stable conditions, which can take much time. Therefore, it is highly attractive to have a relatively simple suitable instrument, called a multiphase flow meter (MPFM), which is capable of measuring the flow rate of each component directly, without separation.
Within the oil and gas industry, it is generally recognized that MPFM’s could lead to great benefits in terms of: reservoir management, layout of production facilities, well testing, production allocation and monitoring [1]-[3]. For example, in offshore production consisting of several nearby wells (Fig. 1), flow data gathered along a pipeline section of a given well can help in identifying how this well contributes to the aggregate flow and, hence, may help in locating a production anomaly, such as a water or gas breakthrough in the actual well. This allows an easier localization of well stimulation or other well treatments, such as enhanced oil recovery, to be performed to increase the well productivity. In another application, a downhole monitoring of the multiphase flow allows well engineers to control more effectively the propagation of the oil from the actual well by adequately controlling the array of valves in that well (e.g., switching off the valve surrounded by high water cut fluid).
II. BASIC CONCEPTS Unfortunately there is no single instrument, which will measure the flow rates of the different phases directly and it is necessary to combine several devices in an instrument package and to calculate the specific flow rates from the combined readings. There are many possible combinations, and the number of instruments required depends upon whether or not the three components can be mixed together upstream of the instrumentation (homogeneous flow). To compute the flow rates of each phase, the basic parameters of phase velocities and phase fractions (or quantities that can be unequivocally related to these) are measured.
Fig. 1. Example of application of the MPFM in oil fields. 290
