Multiphase flow meter in simplified definition is a device used for measure gas flow rate, water flow rate, and hydrocarbon liquid flow rate in the mixture phase flow rate. Sometime the gas flow rate is dominant rather than liquid flow rate (wet gas). Sometimes also the liquid flow rate is more dominant than gas flow rate (gassy liquid). The intention of using this multiphase flow meter is to replace the conventional test separator vessel (which is huge in size) to conduct a well testing. Well testing itself is very important for production optimization of the oil well or gas well (i.e. to monitoring a gas/water injection effect etc.). At present, there were no standard & code that specify a mandatory measurement method to do such multiphase flow metering. So then what it should be?

The multiphase flow metering is a bit unique compare to a single phase metering that has a lot of option and a well establish standard & code. Every vendor in the single phase flow metering has the same basic design, for example an orifice flow metering, venturi flow metering, coriolis flow metering, etc, all of them are made the same flow element. While in fact the multiphase flow metering isn’t like that. Every multiphase flow metering vendor develops their own technologies. Each other are different and unique. With this fact (a lot of metering technique) the simplest way is we will accept any kind of measurement techniques as long as it complies with the project or company requirements. Otherwise, whatever technologies they used it will be useless.

Before we start to select the correct measurement techniques, firstly we must establish the general parameter that can evaluate vendor offer so that it will be able to apple in the technical evaluation phase. Otherwise, if the vendor really – really couldn’t fulfill the general basic parameter which we established then we can consider them as not recommended just for that specific conditions and or project.

The first general parameter is the operating envelope of the proposed multiphase flow

meter. The operating envelope will be consisting of GVF (Gas Volume Fraction) & WLR (Water in Liquid Ratio). In fact, every multiphase flow meter product has its own limitation for some GVF and WLR requirements. The GVF and WLR are defined as below:

GVF = Qg / (Qg + Ql)

Where,

Qg = Actual gas volume flowing (m3/h or ft3/h)

Ql = Actual liquid volume flowing (m3/h or ft3/h)

*other general parameter is LVF (Liquid Volume Fraction) which is = Ql / Qg * GVF

WLR = Qw / (Qw + Qh)

Where,

Qw = Water volume flow rate

Ql = Hydrocarbon liquid volume flow rate

*other general parameter is Water cut which is water volume flow rate and hydrocarbon liquid volume flow rate at standard condition.

For example we have the following data taken from Heat & Material Balances of the specific project document.

Gas flow rate = 150000 ft3/h

Liquid (water + hydrocarbon liquid) flow rate = 20000 ft3/h

Water flow rate = 8000 ft3/h

Operating pressure = 1100 psig

Operating temperature = 160 F

Then we could get the following data:

GVF = 150000 / (150000+20000) = 0.88 or 88%

WLR = 8000 / 20000 = 0.4 or 40%

Now we already have the first general parameter which is GVF and WLR. We must ensure that the operating envelope of the proposed meter is capable to measure in that GVF and WLR range. For example Vendor A offer a multiphase flow meter with a GVF range 0 to 95% and WLR range 0 to 50%, then we could conclude that Vendor A offer is in compliant in term of its operating envelope. On the other hand, if Vendor B offer a meter with GVF range only up to 80% even though its WLR range is 0 to 100% still Vendor B offer isn’t acceptable.

The second general parameter to evaluate the multiphase flow meter is its accuracy. The expecting measurement output of the meter is a gas flow rate, liquid flow rate, and water flow rate. Each of these flow rates usually have different accuracy depend on the capability of the device. Therefore we must make sure that the accuracy of the proposed device is equal or better than the required accuracy. Until now there is no specific requirement that stated the minimum accuracy level of the multiphase flow meter, but in this case the company will determine the upper limit or threshold of the accuracy that shall not exceeded. Once again it varies from one company to others as per their experience, expectation, and operating standard.

If the above two general parameter is fulfill by the vendor, then in theory we could confidently use that device. But we must ensure that there will be a calibration test to prove what they specified in their data sheet.

After we get preliminary information about how to select the Multiphase Flow Meter then what about wet gas flow meter?

The above procedure is still valid to evaluate the wet gas flow meter product. The only different is just the categorization or naming their device. Some vendor categorizes the wet gas as the gas that has GVF more than 95% while other vendor determine that the wet gas is a multiphase liquid that has Lockhart-Martinelli parameter <0.3 (this parameter is talk about

the wetness of a gas). However all above categorization is just a categorization. As long as the vendor proposed device is capable to measure the specified GVF & WLR and in compliance with the accuracy requirement, then its ok to use multiphase flow meter or wet gas flow meter or whatever vendor named it.

Multiphase Flow Meter Measurement Technique

Just to give a brief description about the various multiphase measurement techniques available in the market, the following short description of measurement technique is given.

1. Wet gas metering system that use venturi tube as flow sensing (using DP transmitter) and De Leeuw Correction algorithm to correct the venturi meter read when the liquid phase is present, and pressure & temperature transmitter for phase properties input. Usually this technique is used in conjunction with a tracer dilution technique to determine the free liquid flow rate.

2. Multiphase flow metering system that use V-Cone as flow sensing (using DP transmitter), capacitance sensor & conductance sensor for composition measurement, and coriolis flow meter as mass flow meter.

3. Multiphase flow metering system that use Venturi tube (using DP transmitter), capacitance sensor & conductance sensor as flow sensing, density measurement by using DP transmitter only with Venturi equation, and pressure & temperature transmitter for phase properties input..

4. Multiphase flow metering system that use Venturi tube as flow sensing, gamma meter as density meter and gas-liquid fraction measurement, dual gamma meter as water cut meter, and pressure & temperature transmitter for phase properties input.

5. Multiphase flow metering system that measure oil, gas, and water fraction by using electrical impedance measurement and gamma ray density measurement. The Dual Velocity cross correlation of the signals is used to measure individual component flow rates.

6. Wet gas flow metering system that use a microwave technology as water cut meter, V-Cone as flow sensing (using DP transmitter), and pressure & temperature transmitter for PVT (Pressure Volume Temperature) phase properties input calculation.

7. Wet gas flow metering system that uses a Dual stream Venturi, Pressure loss ratio measurement, Dual DP Measurement, wet gas correction algorithm and PVT calculation by using Pressure & Temperature transmitter input.

8. Multiphase flow metering system that uses an Isokinetic sampling of the gas-liquid mixture followed by phase separation and metering of the individual phases. It just likes a miniature of the huge test separator.

A multiphase flowmeter (MPFM) installed in offshore Egypt has accurately measured three-phase flow in extremely gassy flow conditions. The meter is completely nonintrusive, with no moving parts, requires no flow mixing before measurement, and has no bypass loop to remove gas before multiphase measurement. Flow regimes observed during the field test of this meter ranged from severe slugging to annular flow caused by the dynamics of gas-lift gas in the production stream. Average gas-volume fraction ranged from 93 to 98% during tests conducted on seven wells.

The meter was installed in the Gulf of Suez on a well protector platform in the Gulf of Suez Petroleum Co. (Gupco) October field, and was placed in series with a test separator located on a nearby production platform. Wells were individually tested with flow conditions ranging from 1,300 to 4,700 B/D fluid, 2.4 to 3.9 MMscf/D of gas), and water cuts from 1 to 52%. The meter is capable of measuring water cuts up to 100%.

Production was routed through both the MPFM and the test separator simultaneously as wells flowed with the assistance of gas-lift gas. The MPFM measured gas and liquid rates to within "10% of test-separator reference measurement flow rates, and accomplished this at gas-volume fractions from 93 to 96%. At higher gas-volume fractions up to 98%, accuracy deteriorated but the meter continued to provide repeatable results.

Introduction

The October field is located in the northern Gulf of Suez of Egypt and was discovered by Gupco in late 1979 with the drilling of the GS195-1 well ( Fig. 1). The Nubia sandstone was found to contain a 27°API, undersaturated oil with an initial solution gas/oil ratio (GOR) of about 300 scf/bbl. By 1986, reservoir pressure had declined to the point that gas lift was installed to maintain production. The Nubia reservoir has a waterdrive recovery mechanism, and by 1986, water cuts had also begun to increase.

Today, October production is characterized by three-phase flow. However because of the presence of gas-lift gas in the flowstream, gas-volume fractions at the surface are approximately 95% of pipeline volume, with the remaining 5% occupied by oil and water. In recent years, October drilling development has out-paced infrastructure development (flowlines and gas-lift compression). This has caused testlines to be used full-time for transporting production.

The number and quality of well tests for a typical October well have declined because of the production-deferral effect of flowing one well through the testline while routing all other wells through the production line. In addition, the test separator at the production platform is used full-time for routine separation of production to minimize backpressure on all of the other platform risers. When a well is switched into the test separator, forcing the remaining field production to be separated in the three production separators, riser pressure at other platforms can increase by an average of 15 psi.

Because of the pressure on the company to maximize production on a daily basis, wells at October field are only tested once every 3 to 6 months. A typical test lasts only 4 to 6 hours and rarely involves producing only one well through the test line. Again, because of the issue

of deferred production, two or more wells (including the well to be tested) are initially placed in the test line to the test separator and their collective rate is established. The following day, the well of interest is shut in and the remaining wells are tested. The decrease in total tested rate is assumed to be from the well that was shut in. This method of testing obviously has several disadvantages and potential errors in assumptions.

Multiphase metering in the October field provides a means of acquiring the frequency and quality of well tests that are needed to manage the Nubia reservoir without deferring production. Other advantages include minimal maintenance, savings on test pipelines, rapid identification of well problems, and improved gas-lift-gas allocation.

Meter Description

The MPFM chosen for installation at the October field was the Fluenta 1900VI. The meter was designed to measure oil, water, and gas phases of a multiphase flow without separation of the well stream. The instruments are completely nonintrusive, with no moving parts, requiring no gas bypass line, having no mixing device, and providing real-time output in standard conditions. The meter measures the phase fractions and velocities, and then determines the flow rates of oil, water, and gas.

The MPFM consists of the following sensors: a capacitance sensor unit, an inductive sensor unit, a gamma-densitometer, a venturi meter, and pressure and temperature transmitters. The sensors are mounted on a portable skid, as shown in Fig. 2. An explosion-proof (Ex-d) capsule mounted on the skid contains all the necessary electronics and computer cards to receive and process the signals from the different sensors. These electronics and computer cards are called the system computer.

The processor card inside the Ex-d capsule is equipped with two communication ports. One of the ports is dedicated to the remote terminal unit (RTU) for transmitting all measurements (such as flow rates, pressure, and temperature) by radio to the October production-complex computer. The other port is used to connect a laptop computer to the meter for servicing and onsite monitoring of readings. The recorded data will be stored in the system computer even if no laptop computer or RTU is connected.

The meter skid weighs approximately 3,300 lbm, and was lifted onto the October H platform using a workboat crane. Space requirements for the meter are minimal, as the meter is about 6 ft wide by 4 ft deep by 8 ft high. The meter is powered by automotive batteries, which are recharged by four solar panels.

Measurement Principle

The MPFM measures the fractions and velocities of the different phases using a capacitance sensor, an inductive sensor, a gamma-densitometer, a venturi meter, and pressure and temperature transmitters.

Teach Me - Multiphase

Flow regime:

The physical geometry exhibited by a multiphase flow in a conduit; for example, liquid occupying the bottom of the conduit with the gas phase flowing above, or a liquid phase with bubbles of gas.

Gas-liquid-ratio (GLR):

The gas volume flow rate, relative to the total liquid volume flow rate (oil and water), all volumes converted to volumes at standard pressure and temperature.

Gas-oil-ratio (GOR):

The gas volume flow rate, relative to the oil volumes flow rate, both converted to volumes at standard pressure and temperature.

Gas volume fraction (GVF):

The gas volume flow rate, relative to the multiphase volume flow rate, at the pressure and temperature prevailing in that section. The GVF is normally expressed as a percentage.

Homogeneous multiphase flow:

A multiphase flow in which all phases are evenly distributed over the cross-section of a closed conduit, ie the composition is the same at all points.

Multiphase flow rate:

The total amount of the two or three phases of a multiphase flow flowing through the cross-section of a conduit in unit time. The multiphase flow rate should be specified as multiphase volume flow rate or multiphase mass flow rate.

Multiphase flow velocity:

The flow velocity of a multiphase flow. It may also be defined by the relationship (Multiphase volume flow rate / Pipe cross-section).

Multiphase meter:

A device for measuring the phase area fractions and flow rates of oil, gas and water of a multiphase flow through a cross-section of a conduit. It is necessary to specify whether the multiphase meter measures volume or mass flow rates.

Oil-continuous multiphase flow:

A multiphase flow of oil/gas/water characterised in that the water is distributed as water droplets surrounded by oil. Electrically, the mixture acts as an insulator.

Phase volume fraction:

The phase volume flow rate of one of the phases of a multiphase flow, relative to the multiphase volume flow rate.

Slip:

Term used to describe the flow conditions that exist when the phases have different velocities at a cross-section of a conduit. The slip may be quantitatively expressed by the phase velocity difference between the phases.

Slip ratio:

The ratio between two phase velocities.

Slip velocity:

The phase velocity difference between two phases.

Superficial phase velocity:

The flow velocity of one phase of a multiphase flow, assuming that the phase occupies the whole conduit by itself. It may also be defined by the relationship (Phase volume flow rate / Pipe cross-section).

Void fraction:

The cross-sectional area locally occupied by the gas phase of a multiphase flow, relative to the cross-sectional area of the conduit at the same local position.

Water-continuous multiphase flow:

A multiphase flow of oil/gas/water characterised in that the oil is distributed as oil droplets surrounded by water. Electrically, the mixture acts as a conductor.

Water cut (WC):

The water volume flow rate, relative to the total liquid volume flow rate (oil and water), both converted to volumes at standard pressure and temperature. The WC is normally expressed as a percentage.

Water-in-liquid ratio (WLR):

The water volumes flow rate, relative to the total liquid volume flow rate (oil and water), at the pressure and temperature prevailing in that section.

As oil companies venture further afield to find oil and gas, the deposits they find are increasingly difficult to develop. Subsea deposits require an investment in highly engineered equipment that can withstand harsh underwater conditions that can reach 30,000 ft (9,144 m) below sea level. Deposits on land tend to hold heavier oil that is difficult to get flowing. But both types can require complex extraction methods such as injecting seawater or high pressure steam into the well to drive oil or gas to the surface. Unfortunately, this compounds one of the most vexing measurement challenges -- multi-phase flow with combinations of water, oil, and gas.

To make matters worse, the output of oil wells can vary significantly over time, impacting the economic justification to continue running them. Older wells with changing conditions require more frequent testing to determine if their output is sufficient. New wells that appear promising may underperform once pumping starts. Operators need real-time well data to optimize production and to ensure accurate measurement of hydrocarbons produced for allocation and custody transfer.

Multi-phase flow measurement has made great advances in recent years, and suppliers have invested heavily in R&D to develop new solutions that offer potential gains in efficiency and profits for users. For example, older technologies such as test separators have been joined by partial separators which separate gas from liquid flows, and multi-phase flowmeters which measure multi-phase flows without fully separating each constituent. Each technology has advantages and disadvantages, and applicability varies based on well condition, location, and output.

Full separation technology

Full separators, also called test separators, are behemoth tanks that hold a large sample of the pumped oil/water/gas mixture. Once the tank is filled, gas vents through the top, water settles to the bottom, and oil rises to the surface of the water. Flowmeters connected to the tank measure the individual volumes of gas, oil, and water.

Full separators offer high accuracy, and enjoy wide acceptance in the industry. However, large footprints limit their use in offshore platforms where space is limited. Also, full separators rely on gravity to separate the various phases, and the process can take several hours or days, depending on how heavy the oil is. As a result, operators can only determine average flow rates for a given period.

Full separators have a high average selling price and carry high operational and maintenance costs since they must be cleaned after every sample is analyzed.

Partial separation technology

Partial separators, also called compact cyclonic degassers or compact cyclone multi-phase meters, get around the problem of multi-phase flow by separating the gas phase from the water and oil phases. When oil is pumped into the device, it enters a cylindrical chamber at an angle, generating a centrifugal force that pushes the oil and water to the outside of the chamber, leaving the gas stage in the center to rise to the top to be measured by a gas flowmeter. The oil and water mixture then passes through a water-cut meter or other multi-phase meter. Coriolis flowmeters commonly are used. Indeed, Coriolis meters are probably the best technology to measure two-phase oil and water flows, making it promising for heavy oil applications.

With partial separators, the process is much quicker than with a full separator, offering near real-time measurements to determine if a well is producing adequately. Partial separators cost less to purchase and have a much smaller footprint than full separators. They can be made small enough to be portable, allowing operators to test older wells that might not have enough output to justify investing in a full separator. Partial separators may not be an ideal choice for measuring heavy oil, which is difficult to separate.

Multi-phase flowmeters

At the cutting edge of multi-phase flow measurement technology are true multi-phase flowmeters that do not require separation to measure the components of three-phase flow. Multi-phase meters use sophisticated technologies and carry a high price tag. The devices can use multiple measurement technologies such as gamma radiation for composition, venturi for flow, and pressure and temperature measurement to determine three-phase flow. One supplier uses three-dimensional tomography (akin to magnetic resonance imaging in medical applications) to identify liquid, gas, and water accurately. While highly accurate, some users are reluctant to embrace meters that use radioactive materials due to permitting costs and environmental considerations. Some end users remain skeptical regarding the general reliability of these units, but this is likely to change as they become more proven in use.

Multi-phase meters are the preferred choice for subsea applications, and are accepted widely in natural gas applications. Because oil wells are uniquely different than gas wells, multi-phase meters are different and are purpose-built for each application. However, only one supplier promises a meter capable of measuring multi-phase oil and wet natural gas streams with the same device. Multi-phase meters are also a good fit for offshore allocation metering applications, where a single platform may be pumping oil from multiple wells for several different customers. Multi-phase meters are also a better technology for heavy oil, because they do not require separation to measure three-phase flow. Due to the price of multi-phase flowmeters, they are suitable only for subsea applications and only then in wells with sufficient output to justify the expense.

No single solution

As described, a number of technologies are available to address the problem of multi-phase flow. However, it may be that no one technology can satisfy all user requirements. Older devices such as full separators offer high accuracy, but by design cannot give users the real-time data they need. Partial separators provide timely data, but may not be the best choice for heavy oil deposits. Multi-phase meters, which carry a high price tag, still strive for widespread acceptance. In oil and gas production, there are no "typical" applications, and operators must carefully evaluate each project to determine which technology to apply.

During the transition to multi-phase meters, ARC expects that many installations will have multiple redundant technologies to validate new multi-phase metering technologies as end users adjust to the paradigm shift.

Description

BACKGROUND OF THE INVENTION Ads by GoogleMultiphase Gas Flow

www.jiskoot.com  Multiphase meter for well test and reservoir management

[0001]The present invention relates to industrial process controlled monitoring systems. More particularly, the particular invention relates to measurement of flow of multiphase in industrial processes.

[0002]Industrial processes are used in the manufacturing and refinement of various fluids or components. Examples include oil refining or distribution, paper pulp facilities, and others. In many instances, it is desirable to measure a flow rate of a process fluid. Various techniques are employed to measure flow rates including differential pressure drop across an orifice plate, vortex sensing techniques, magnetic based techniques and others. However, measurement of flow rate of global multiphase process fluids (process fluids which are not homogenous and may contain multiple different materials in more than one phase such as gas, liquid or solid) has been problematic.

[0003]There is an ongoing need to provide measurement techniques for determining flow rate of a multiphase process fluid.

SUMMARY

[0004]A flow meter for measuring flow rate of a process fluid includes a microwave source configured to generate a microwave signal. A probe tip is coupled to the microwave source and in near field proximity to the process fluid. The probe tip is configured to apply the microwave signal to the process fluid. A microwave detector coupled to the probe tip is configured to detect a near field microwave signal from the process fluid in response to the applied microwave signal. Flow calculation circuitry

determines flow rate and/or composition of the process fluid as a function of the detected microwave signal.

BRIEF DESCRIPTION OF THE DRAWINGS

[0005]FIG. 1 is a simplified diagram showing a system for controlling or monitoring an industrial process including a flow measurement device for measuring the flow rate and composition of a multiphase process fluid.

[0006]FIG. 2 is a simplified diagram showing components of the flow device of FIG. 1.

[0007]FIG. 3 is a simplified flow chart showing steps for use in determining the flow rate and composition of a multiphase process fluid.

DETAILED DESCRIPTION

[0008]Many industrial processes operate with multiphase process fluids. As discussed in the Background section, it is difficult to accurately measure flow rate of multiphase process fluids. One example of a process which utilizes a multiphase process fluid is oil production. In particular, production of oil using advanced recovery techniques may utilize a multiphase fluid. The current trend of raising demand and raising difficulties to increase the output from existing wells has led to the use of water or steam injection as a means to recover oil from wells which have a moderate production capacity.

[0009]Oil production from such wells is characterized by a multiphase mixture of water, oil, natural gas and sand. To monitor the flow rate of such wells there are a number of multiphase flow measurement techniques using gamma ray, IR, microwave and ultrasonic sensors, often in combination with a mechanical separation system that creates a bulky and expensive installation.

[0010]Radioactive sources are frequently not attractive due to their handling in production. Further, disposal at end-of-life creates a potential hazard. Optical/IR methods may suffer from the sensitivity of optical parts to a dirty environment. Ultrasonic sensors, while having attractive resolution properties, may suffer similarly from sand and dirt, leading to high losses. or high power requirements. While each of the methods also has their merits, microwaves may be used more effectively to characterize multiphase flows.

[0011]There are existing efforts to characterize a multiphase flow by dielectric measurements using microwaves. The basis of this method is usually taken as the following "inverse" problem: given the (complex) permittivities .di-elect cons.1,2,3 of the constituents and a shape characteristics of the mixture, how can the volume fractions be calculated from a measurement of the permittivity of the mixture .di-elect cons.mix. The latter is extracted either from a multi port measurement or the frequency shift or quality factor of a resonant mode (see, for example, http://www.agarcorp.com/, EP0495849B1, and WO2007109772A2).

[0012]However, this approach faces a number of problems. One problem is that the

permittivities of the constituents (e.g., water) is dispersive for microwaves and need to be compensated for temperature and minute differences in ionic content (salt, acids) that can be dissolved and which lead to severe losses when frequencies exceed 1 GHz as shown in Table 1:

TABLE-US-00001 TABLE 1 Attentuation distance for 100 dB path loss in water vs. frequency 0.1 GHz 0.1 GHz 0.1 GHz Pure water (NTP) 100 m 1 m 1 cm Sea water (NTP) 10 cm 5 cm 1 cm

[0013]Even more challenging is the shape characteristics. There seem to be approximately as many theoretical expressions for the shape dependence (See, for example, Klaus Kupfer (ed.) Electromagnetic Aquametry", Springer, 2005; J. B. Hasted, "Aqueous Dielectric", Champman and Hall, 1973; and Ari Sihvola, "Electromagnetic mixing formulas and applications", IEE, 1999.) as there are experiments. This may indicate the limits of measurement performance of such a system.

[0014]Instead of attempting to find a suitable multiparameter fit of an ill-defined volumetric measurement, the present invention includes the use of a local statistical measurement to characterize the flow. Near field microwave microscopy can be used to determine the structure of dielectric materials at resolutions comparable to lateral extension of a transmission line (TL) tip that scans a surface area. For liquid applications, such instruments can be achieved with micromachined probe tips to cover a length typical for the minimal feature size in multiphase flow, for example, a few millimeters. Mechanical scanning is not necessary because the fluid flow itself moves thereby providing a "scanning" of the mixture as it moves by the probe. Further, the modulation properties of the reflected microwave signal can be used as a measure and discriminator of the local constituents of the flow, i.e. the passage of a certain droplet volume will induce a modulation of the field typical for size of the droplet. By analyzing the signature and statistics of this modulation (frequency, phase amplitude), the concentration and nature of the embedded features can be measured in approximately the same way as shot noise of an electric current can be used to determine the typical size of the charges that are transported. Thus, statistics of the dynamic changes at a local point are used to estimate volumetric information. With the present invention, a statistical sampling technique is used to determine flow rate by extrapolating a local measurement to thereby infer the flow rate and composition of the total volume of fluid.

[0015]FIG. 1 is a simplified diagram of an industrial process 10 including a flowmeter or process device coupled to process piping 14. Process piping 14 carries a process fluid 16 which flows therethrough in the direction indicated. Flowmeter 12 can be of any particular configuration or design and is configured to measure flow of fluid 16, such as a multiphase fluid, through process piping 14. In the example of FIG. 1, the flowmeter 12 is shown as being coupled to a remote control room 20 by a process control loop 22. The process control loop 22 can be in accordance with any configuration such as a two-wire control loop based upon the HART.RTM. communication protocol, a 4-20 mA process control loop, a FieldBus based protocol, a wireless communication protocol, or others.

[0016]Flowmeter 12 includes a near field microwave probe 30 arranged to interact in

the near field with process fluid 16. As discussed herein, near field microwave measurements are used to determine the flow rate of process fluid 16 through process piping 14.

[0017]FIG. 2 is a simplified block diagram of flow measurement device 12 illustrating one example configuration. In FIG. 2, flow measurement device 12 includes a microwave source 100 which is configured to generate microwave signals provided to directional coupler 102. A coaxial cable 104 couples to a microwave probe tip 30 which is immersed in process fluid 16. Probe 30 interacts with the process fluid 30 in the near field through process fluid 16 in the near field with respect to the frequency of the microwaves generated by microwave source 100. The near field can be defined as measurements occurring within a distance which is much less than the wavelength of the microwaves.

[0018]The microwave near field interaction with process fluid 16 provides a microwave reflection signal back through probe 30, and coaxial cable 104 to directional coupler 102. This reflection signal is related to the size, shape, consistency, permeability, area, volume, and other features of components in a multiphase process fluid such as fluid 16. The "reflected signal" may be an electrical signal carried by probe 30 or may be an electrical characteristic of probe 30 which is measured with appropriate equipment. Directional coupler 102 provides the reflective signal to feedback circuitry 106. Feedback circuitry 106 is used to control microwave source 100 in accordance with known techniques. An output 108 from feedback circuitry 106 is provided to an analog to digital converter 110. The output 108 can comprise, for example, a voltage signal which is related to the near field reflection from the process fluid 16. A microprocessor 112, or other processing device, is configured to analyze the output from the analog to digital converter 110. Microprocessor 112 operates in accordance with instructions stored in a memory 114. The memory 114 can also be used for temporary or permanent storage of other data or information including configuration data.

[0019]Microprocessor 112 performs a statistical analysis on the output from analog to digital converter 112. For example, the frequency of peaks in the signal, the width of peaks in the output signal, the duration of peaks or other variations in the signal can be monitored and statistically analyzed. Statistics include average, median, variance, and spatial and temporal correlation coefficients etc. This data can be correlated with the flow rate of the process fluid 16.

[0020]FIG. 3 is a simplified flowchart showing steps in accordance with the present invention. These steps can be performed, for example, by device 12 shown above. The flowchart 150 begins at start block 152. At block 154, near field based flow data is obtained, for example, using the circuitry illustrated in FIG. 2. At block 156, a statistical parameter is calculated from the near field based flow data. This statistical parameter is then correlated to a flow rate at block 158. As a very simple example, a statistical parameter which identifies the average number of data peaks over a period of time can be used and correlated to a flow rate of the process fluid 16. This correlation can be determined experimentally and can be performed using known techniques such as through a polynomial curve field. Although only a single statistical parameter is discussed above, multiple statistical parameters can be used in the determination of flow rate. The correlation between the statistical parameter and the

flow rate can be determined using modeling or other mathematical techniques, or can be determined empirically by performing tests on a particular type of process fluid. Note that the relationship between a statistical parameter of flow rate may vary depending on the composition of the multiphase process fluid. Control is returned to start block 152 and the measurement procedure is repeated.

[0021]One advantage of a near field probe is the ability to achieve a resolution that is suitable to characterize the features of the multi-phase flow, i.e. the ability to resolve the actual constituents at a given point in time. For some fluids, this cannot be achieved with the centimeter or larger wavelengths using the propagating modes used in current microwave multiphase flow sensors. While the propagating/resonant modes used typically require a certain geometry and/or metallic pipe walls, a near field probe is only dependent on the electromagnetic response in an area comparable to the probe lateral extension. The probe can be shaped to contain the complete circumference of the pipe, or several sensors may be used to obtain more accurate measurements. The local near field can be made significantly larger than the propagating field strength with the power restrictions applicable for industrial sensors. The use of several near field sensors may be used to measure typical relaxation effects that can further be used to characterize the fluid properties (e.g. Doppler of transmitted/reflected field as a function of polarizing field) giving additional information on the fluid at the point of measurement. This idea builds on the polarizability of the natural gas phase (methane), which has a measurable polarizability. An intense, pulsed electric field could therefore induce an electric dipole moment, which then decay and respond/reflect to microwave probing fields in an anisotropic pattern and with a certain Doppler shift, i.e. like a small moving microwave antenna. Electric and magnetic susceptibility is usually quenched in the liquid phase, where the molecular interactions dominate over external electromagnetic field effects.

[0022]Although the present invention has been described with reference to preferred embodiments, workers skilled in the art will recognize that changes may be made in form and detail without departing from the spirit and scope of the invention. In the discussion above, a microwave detector is used to measure the reflected near field signal. In the example of FIG. 2, this detector is formed by the directional coupler 102, feedback circuit 106, analog to digital converter 110. However, the present invention is not limited to this particular type of near field microwave detector and other circuits and configurations may be employed. This embodiment is provided for exemplary purposes only. In the example of FIG. 2, the microprocessor provides a flow calculation circuit for use in determining the flow rate. The microwaves discussed herein can be of a frequency range between about 0.3 GHz and about 3 GHz. Although only a single probe is shown, the invention may be implemented with multiple probes or through other techniques.