GB2516960A

GB2516960A - Multiphase Flowmeter

Info

Publication number: GB2516960A
Application number: GB1314230.2A
Authority: GB
Inventors: David Sirda Shanks; Russell John Simpson
Original assignee: Zenith Oilfield Technology Ltd
Current assignee: Zenith Oilfield Technology Ltd
Priority date: 2013-08-08
Filing date: 2013-08-08
Publication date: 2015-02-11
Also published as: CN106030257A; WO2015019081A1; CA2919769A1; EP3030865A1; GB201314230D0

Abstract

A multiphase flowmeter and method of determining the proportions of two or more fluids flowing in a conduit and also the flow rate of each of the fluids present is disclosed. One or more sensors are mounted in the fluid flow to monitor a sensed area, with each sensor including electrical means in the form of a fluid identifier probe and temperature means in the form of a thermal fluid velocity heat loss sensor. A processor is used to calculate the proportions of fluids present in the sensed area from the sensed electrical property and the flow rate from the sensed temperature differential. Spot measurements are achieved by making the sensed area substantially smaller than a cross-sectional area of the conduit. An array of sensors may be used.

Description

MULTI PHASE FLOWMETER

The present invention relates to a multiphase flowmeter for use in the oil and gas industry and in particular, though not exclusively, the invention relates to a meter which determines the proportions of two or more fluids flowing in a surface pipeline and also the flow rate of each of the fluids present.

In the oil and gas industry it is advantageous to include a metering device at a variety of sites to establish the amount of fluid flowing and also the constituents of that fluid flow. Typical constituents may be oil, gas, brine and air. Metering could be down hole, at surface or within a processing plant.

Conventionally, there are a number of methods of measuring fluid flow rate. For example, there are simple turbine meters that have moving parts. However these moving parts often reduce the accuracy and sensitivity of the meter to small flow rates, and in addition reduce the expected lifetime of the meter.

Other examples include non-intrusive methods such as electromagnetic meters that only operate in conductive fluids, and ultrasonic meters the use of which is limited to fluids containing known constituents, and very little or no free gas. A further disadvantage of both electromagnetic and ultrasonic meters is that the electronics required to obtain measurements from these meters tend to be fairly complex.

A prior art multiphase flowmeter is described in GB 2354329, assigned to the present Applicants. A flow meter is used to determine the flow rate of fluid and a ratio tool, described in GB 2386691 and also assigned to the present Applicants, is used to determine the nature and quantities of the fluids passing therethrough. The flowmeter comprises a restriction or choke in the

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path of the fluid with strain gauges located at the choke to measure the force on the choke. The ratio tool has a plurality of fluid identifier sensors which comprise pairs of plates or bars located across the choke and extending over the length of the meter body for measuring electrical properties of the fluid, in particular, the impedance or both resistance and capacitance. GB 2354329 and GB 2386691 are incorporated herein by reference.

The main disadvantage of this multiphase flowmeter, in common with many prior art multiphase flowmeters, is that it only allows a bulk measurement of flow to be established. Consequently, the different fluids which typically flow at different average velocities through a pipe due to the variation in their densities, produce a slip velocity which the prior art multiphase flowmeters cannot account for as they can't determine the individual velocities. Additionally, the prior art multiphase flowmeters cannot cope with the presence of bubble suspensions. To overcome these disadvantages, some prior art multiphase flowmeters will include a mixing unit ahead of the flowmeter to condition the fluids and create a uniform blend of fluids, breaking up any bubble suspensions and creating a steady single flow rate for measurement. This gives a bulk measurement also. Additionally such mixing units are invasive and prone to failure due to the requirement to have moving parts.

A further disadvantage of this multiphase flowmeter is in the requirement of a choke. This artificially varies the flow rate of the fluids and prevents the multiphase flowmeter from being used as a non-invasive measurement device.

A yet further disadvantage of this multiphase flowmeter is in the way it determines the component fluids. A free oscillating circuit is used. Such a circuit is not sensitive enough to obtain Q for multiphase fluid mixtures used in the oil and gas industry. The salt water (brine) and indeed any water appears to have no resonance as there are orders of magnitude difference between the oil/gas and the water.

A still further disadvantage of this multiphase flowmeter is that the load cells which measure flow rate are located at a different position on the body to the fluid identifier sensors, one being upstream of the other. Thus it must be assumed that the flow rate and the ratio of component fluids must be uniform along the length of the body between the different positions. Those skilled in the art will appreciate that this does not occur in real multiphase flow through a conduit.

It is therefore an object of at least one embodiment of the present invention to provide a multiphase flowmeter which mitigates at least some of the disadvantages of the prior art multiphase flowmeters.

It is a further object of at least one embodiment of the present invention to provide a multiphase flowmeter and a method of determining the proportions of two or more fluids flowing in a conduit and also the flow rate of each of the fluids present.

According to a first aspect of the invention there is provided a multiphase flowmeter for determining the proportions of fluids present and their respective flow rates in a conduit, comprising: a sensor, the sensor being mounted in the conduit in contact with fluid flow therethrough, the sensor including electrical means to measure an electrical property of a fluid over a sensed area of the conduit and temperature means to measure a temperature differential indicative of a cooling effect of fluid flow substantially at the sensed area; and a processor to calculate the proportions of fluids present in the sensed area from the electrical property and the flow rate from the temperature differential.

In this way, a multiphase flowmeter is provided in which the flow rate and fluid composition can be determined at substantially the same position in the conduit.

Preferably, the sensed area is substantially smaller than a cross-sectional area of the conduit. As the sensed area is substantially smaller than the cross-sectional area of the conduit, a spot measurement can be made in the conduit and the fluid can flow around the body of the sensor.

Preferably there is a plurality of sensors located in an array in the conduit and each sensed area is distinct. By making more than one measurement, variable fluid compositions and flow rates can be determined at a cross-section of the conduit. As each of the sensed areas do not overlap a bulk measurement is avoided.

Advantageously, a cross-sectional 2-D image of fluid composition and flow rate can be provided for the conduit.

Preferably the electrical means comprises a fluid identifier probe, the probe being arranged in the sensed area. In this way, the fluid identifier probe is used to form an electrical contact with the fluid in the sensed area acting as a complex electrical impedance. This electrical contact can be by direct conductive DC contact, by a capacitive contact through a small insulating film, or by both. The complex impedance provides capacitive and resistive elements between the fluid, one or more portions of the sensor and/or an earthed metal element.

Preferably the temperature means is a fluid velocity heat loss sensor. Such sensors are known in the art for determining fluid velocity by measuring thermal heat loss. Each fluid velocity heat loss sensor may comprise one or more temperature sensors and a heater element.

Preferably, the temperature means comprises a fluid temperature probe, a heater and at least one fluid temperature probe temperature sensor. By using a heated probe an anemometer is formed. In an embodiment the fluid identifier probe and the temperature probe are formed together as a single probe. In this way, the sensor can be made relatively small as compared to the prior art arrangements. Additionally, there may be at least one fluid temperature sensor. In this way, a temperature difference profile across the sensed area can be established.

Additionally, as the fluid velocity sensor can be small relative to the cross-sectional area of the conduit, the flowmeter may consist of several individual sensors in different parts of the fluid flow providing a profile of fluid velocity in different points in the conduit, providing parts of a velocity profile, whose completeness is Is dependent on the number of sensors deployed. In this way the flow accuracy and ability to deal with complex flowing regimes can be dealt with by use of sensor arrays.

Preferably the multiphase flow meter includes an electronic circuit.

In this way, signal conditioning and measurement electronics are supplied. Preferably, the electronic circuit forms at least one resonant circuit with the fluid identifier probe. In this way, analysis of the resonant circuit(s) response can be used to determine the type(s) and proportions of fluid flow in the conduit to give a fluid composition volume fraction measurement.

Preferably the multiphase flowmeter includes a DC power supply.

In this way, by applying DC power a measurement of electrolytic or battery response can be made. This allows measurement of an electrolyte fluid mixture such as a mineral laden salt water mixture as found in well bores. Additionally, use of DC power will also provide an electrical impedance measurement giving additional confirmation of whether the fluid is conductive and to what extent.

Preferably the processor includes a database of historical data for comparison to the measurements from the electrical means. More preferably, the historical data comprises complex impedance values for known fluids and fluid mixtures.

In an embodiment, the multiphase flowmeter comprises a sensing module including a plurality of sensors for location in the conduit, an electronics module including the electronics circuit and a remote data logger including a display unit on which to view the determined proportions of fluids present and their respective flow rates in the conduit. The processor may be located in the electronics module or the data logger.

According to a second aspect of the present invention there is IS provided a method of determining the proportions of fluids present and their respective flow rates in a multiphase flow through a conduit, comprising the steps: a) providing a multiphase flowmeter according to the first aspect; b) locating an array of sensors over a cross-sectional area of the conduit; c) measuring an electrical property of sensed areas of the fluid from the sensors; d) measuring a temperature differential between a temperature of the fluid and a temperature of a heated surface over the sensed areas from the sensors; e) using the electrical property to determine the proportions of and fluids present in each area; and f) using the temperature differential to determine the flow rates of the fluids present.

In this way, the proportions of fluids present and their respective flow rates can be determined for sensed areas which may be considered as spot measurements. These spot measurements can be plotted as a 2-D array for a cross-sectional area of the conduit.

In an embodiment, a plurality of identical arrays are constructed and positioned at separate locations along the conduit. The method may then include the step of using time correlation between consecutive arrays to match flowing and fluid mixture patterns to confirm both measured velocities and flowing regime stability.

Preferably, step (c) comprises measuring amplitude, Q and side band gain around a main resonant frequency. This measurement may be from a resonant circuit comprising a resistor, capacitor and an inductor in an active circuit, and a complex impedance formed by a fluid identifier probe in the sensor, an earthed metal element and the fluid in the conduit. Preferably, the earthed metal element is a portion of the sensor body.

Preferably step (c) comprises making measurements around several resonant frequencies and using knowledge of the low frequency and high frequency behaviour of oil and gas and salt water to further refine the ability to determine what proportion of each constituent is present, by comparing the reactive and real parts of each measurement, at different frequencies.

Preferably, step (e) comprises utilising a difference in high frequency versus low frequency behaviour to determine the fluid composition present in the flow. For example, low frequency may indicate a composition primarily of brine with some oil as opposed to high frequency behaviour which occurs for a composition of mainly oil with some brine in the flow. Optionally, step (c) further comprises utilising the complex frequency behaviour of brine in the a fluid volume fraction determination.

Preferably, step (e) comprises utilising an amplitude of a resonant peak of the circuit as a measure of salt water present. If the fluid flow is continuous brine then the amplitude is low with little or no discernible resonant peak, whereas oil and gas have distinct reactive electrical properties creating distinct frequency behaviour, and a measurable resonant peak.

Preferably, step (f) comprises maintaining a constant power on the fluid temperature probe such that an actual instantaneous temperature rise of the heated surface of the sensor above the fluid temperature, is only affected by fluid cooling which is directly proportional to fluid velocity, and the fluid thermal conductivity.

Preferably, step (f) comprises determining the presence of air in the fluid composition. When air is present, as the fluid temperature probe is heated it will reach a much greater temperature in air than when immersed in liquids such as brine and oil. More preferably, the method includes the step of determining a proportion of gas present by measuring heat rise of the fluid temperature probe.

Preferably, the method includes the step of using a DC measurement of electrolytic behaviour to determine the proportion of salt present. This assists in the determination of brine in the fluid composition. In an embodiment, the determination of salt present, being the salinity of the water present is by both volume fraction measurement and DC resistance measurement.

Preferably, steps (e) and (f) are performed in a processor wherein signal analysis may be performed. The analysis may be iterative. In this way, initial course measurements of frequency response and resistance and electrolyte action can be made and then, using the processor, alterations may be made to the measurement electronics to focus the measurement on the area of interest, or adjust the measurement to the fluid conditions observed in the coarse measurement.

Preferably, the signal analysis may include comparing data to stored historical data. In this way, complex impedances for known fluids and fluid mixtures can be determined in a controlled environment and the measured data compared to this historical data to provide the fluid composition volume fraction for the sensed area measured in the conduit being metered of the change in property of brine in DC current over time to assist in identifying the presence of brine.

In the description that follows, the drawings are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results.

Accordingly, the drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as "including," "comprising," "having," "containing," or "involving," and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps.

Likewise, the term "comprising" is considered synonymous with the terms "including" or "containing" for applicable legal purposes.

All numerical values in this disclosure are understood as being modified by "about". All singular forms of elements, or any other components described herein including (without limitations) components of the apparatus are understood to include plural forms thereof.

These and other aspects of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which: Figure 1 is a schematic illustration of a multiphase flowmeter located in a conduit according to an embodiment of the present invention; Figures 2(a) to 2(d) are schematic illustrations of sensors of a multiphase flowmeter according to embodiments of the present invention; Figure 3 is a schematic diagram of a resonant circuit of the multiphase flowmeter of Figure 1; Figure 4 is a schematic diagram of a circuit for use in a multiphase flowmeter of the present invention; Figure 5 is a schematic diagram of a circuit for use in a multiphase flowmeter of the present invention; Figures 6(a)-(c) are each a schematic diagram of arrangements of a sensor, a processor and a data logger in a multiphase flowmeter according to embodiments of the present invention; Figure 7 is a schematic illustration of a linear array of sensors in a multiphase flowmeter located in a pipe according to an embodiment of the present invention; Figure 8 is a schematic illustration of a circumferential or radial array of sensors in a multiphase flowmeter located in a pipe according to an embodiment of the present invention; and Figure 9 is a schematic illustration of an array of sensors mounted around a rod in a multiphase flowmeter located in a pipe according to an embodiment of the present invention.

Reference is initially made to Figure 1 of the drawings which illustrates a multiphase flowmeter, generally indicated by reference numeral 10, for determining the proportions of fluids 12 present and their respective flow rates in a conduit, being a pipeline 14.

Pipeline 14 is shown in cross-section and the direction of fluid flow is through the drawing.

Flowmeter 10 comprises a sensor 16 which is mounted via a rod 18, to lie in a plane, being the surface of the page, which is perpendicular to the direction of fluid flow. Sensor 16 is arranged so that fluid 12 may flow around the sensor body 20. The outer dimensions of the sensor body 20 may define an area, referred to as the sensed area 22, over which measurements of the fluid 12 are made. It will be appreciated that the sensed area 22 is appreciably smaller than the cross-sectional area of the pipeline 14. Indeed, the sensor 16 can be dimensioned so that for an appropriately sized pipeline 14, the sensed area 22 is effectively a spot. In this way, sensor 16 may make a spot measurement'. When more than one sensor is arranged in the plane, the sensors can collectively be referred to as a sensing module.

Also within the flowmeter 10, is a processor 24. In the embodiment shown, the processor 24 is connected to the sensor 16 via a wire 26 and an electronic circuit 28. The wire 26 is arranged to pass inside the rod 18. The processor 24 and the electronic circuit 28 may be considered as an electronics module 30. Additionally, a remote data logger 32 and a visual display 34 are included for a user to store and view the results.

A cross-sectional view through the rod 18 and sensor 16 of the flowmeter 10 is illustrated in Figure 2(a). Sensor 16 includes electrical means, generally indicated by reference numeral 36, located at the centre of the body 20 and temperature means, generally indicated by reference numeral 38, located across the surface 40 of the sensor 16. The co-location of electrical means 36 and temperature means 38 enable the flow rate and fluid composition of the fluid 12 flowing within the pipe 14 to be determined at the same point of the pipe 14.

The electrical means 36 comprises a fluid identifier probe 42 located in the body 20 and isolated from it by an annular thermal insulator 44. Typically, the sensor body 20 and fluid identifier probe 42 are machined from a material such as stainless steel or other such suitable material which is renowned for properties able to ensure resilient performance in harsh environments. The insulators 44a and 44b may be machined from a material such as PEEK which is also known for its high standard of performance in harsh environments.

The temperature means 38 is a fluid velocity heat loss sensor. In the embodiment shown in Figure 2 (a), two temperature probe temperature sensors 46a,b are spaced from a heater unit 48. The body 20 is machined with recesses or slots suitable for the temperature probe temperature sensors 46 and the heater unit 48.

The portion of the body 20 between the insulators 44 acts as the temperature probe 52, being heated by the heater unit 48. Mounted separately from the temperature probe 52, are fluid temperature sensors 50. The fluid temperature probes 50 require to be thermally detached from the temperature probe 52, so that the heater 48 does not affect the fluid temperature measurement. An ideal arrangement is illustrated in Figure 2(b) where an identical mechanical assembly as that provided with the heater 48, is arranged with the fluid temperature sensor 50, absent the heater 48, to provide a reference. However, any arrangement to measure the fluid temperature can be used as long as it is not affected by ambient conditions and measures the fluid itself.

The common fluid identifier probe 42 and temperature probe 52, are both insulated from the sensor body 20 by insulator 44. Figure 2(c) is a side view which illustrates the arrangement wherein the probes 42,52 and insulators 44a,44b are discs arranged coaxial with the cylindrical body 20 of the sensor 16. Alternatively, as illustrated in the side view of Figure 2(d), the probes 42,52 may be arranged to provide a circular face perpendicular to the longitudinal axis of the body 20. The insulator 44 is then an annular face around the circular face of the probes 42,52.

Using the fluid identifier probe 42, measurement of the fluid composition volume fraction is made by the creation of a resonant circuit with the electronic circuit 28. With reference to Figure 3, there is shown a resonant circuit 54 which enables the resonant frequency, and thus fluid composition, to be established. The resonant circuit 54 comprises a resistor 56, an inductor 58 and complex impedance 60. The resistor 56 and inductor 58 are fixed value components which can be either in the electronic circuit 28 of the electronics module 30 or embedded in the body 20 of flowmeter 10. The complex impedance in this resonant circuit 54 is formed by the sensor body 20, the fluid identifier probe 42 and the fluid 12 in the pipe 14. The body 20 and the fluid identifier probe 42 are electrically isolated by insulator 44. A complex impedance may also exist between the probe 42, the fluid 12 and any earthed metal, such as the inner surface of the conduit 14. In this way, the distances can be optimised to give ideal responses in a wide range of fluid conditions.

In use, as the values of the other resistor 56 and inductor 58 of the resonant circuit 54 are known, the complex impedance of the fluid 12 can be determined using circuit analysis. By obtaining a swept frequency response, for example by having varied the resistor 56 and inductor 58 values, the oscillating circuit is able to resonate across the spectrum of frequencies which enables detection of resonant responses from those at low frequencies created by water or brine, to those at high frequencies created by fluids such as oil and gas. The output responses detected from the circuit 54 can be analysed against known or historical data to indicate the type and ratio of constituent fluids in fluid 12.

Measurements can be made around several resonant frequencies.

Using knowledge of the low frequency and high frequency behaviour of oil gas and salt water and by comparing the reactive and real parts of each measurement, at the different frequencies, we can further refine the ability to determine what proportion of each constituent is present.

In Figure 4, a block diagram representation of a circuit 62 operable to generate and apply a swept sine wave to the resonant circuit 54 of Figure 3 is shown. Circuit 62 comprises a generator unit, in this case a microcontroller 64 which is used to generate a sequence of digital values. The digital value sequence is output from microcontroller 64 and fed to digital-to-analog converter (DAC) 66.

The digital values output by the microcontroller 64 represent codes that when converted to an analog output by the DAC 66 are samples of a sine wave. The analog output from DAC 66 is fed to an amplifier circuit 68 to further condition the voltage out. This voltage is then output from the circuit 62 and fed to the input of the resonant circuit 54. In use, the microcontroller 64 can alter the time period of one cycle of the output sine wave and also sequence a series of different time period cycles thus creating a swept sine wave being output from circuit 62 and that output being applied as input to the resonant circuit 54. Circuit 62 is located in the electronics module 30.

Referring now to Figure 5, there is shown a block diagram of a Is circuit 70 operable to measure the response from the output of the resonant circuit 54. In circuit 70, the amplifier 72 conditions the output from the resonant circuit 54 before an analog-to-digital converter (ADC) 74 samples the conditioned signal to provide a digital code that can be read by microcontroller 76. In this way, sensitivity to the response can be increased to pick-up the small resonant peaks which represent water and brine while sensitivity can be decreased to pick-up the larger resonant peaks of oil which would otherwise swamp the signal and cause the water peaks to be

undetectable.

Referring to Figure 2, in sensor 16 the fluid identifier probe 42 may also operate as described in the prior art documents GB 2354329 and GB 2386691 to provide the fluid composition volume fraction with the plates being represented as the probe 42 and any earthed metal surface such as the sensor body 20. GB 2354329 and GB 2386691 are incorporated herein by reference.

To determine the fluid velocity, the temperature probe temperature sensors 46a,b record the temperature at the heated probe 52. This is fed back to the processor 24. As fluid 12 passes probe 52, heat will be convected away by the fluid 12 and the temperature will drop. This temperature drop is proportional to fluid velocity and its thermal conductivity, so for a fluid with known thermal conductivity the velocity can be directly measured. Alternatively a feedback loop where the processor 24 increases power to the heater 48, to maintain a constant temperature at the probe 52 can be used. The power required to maintain the temperature indicates the temperature differential caused by the cooling effect of the fluid 12 passing the probe 52. Using constant power allows a wider range of flowing velocities to be measured, but provides very small temperature differences to be measured at high flow rates. The fluid temperature sensors 50 will record the temperature of the fluid 12 away from the heated temperature probe 52 so that a temperature differential can also be measured. By having a plurality of fluid temperature sensors 50, a temperature difference profile across the sensed area can be determined. The heat lost can be converted into a measure of fluid velocity in accordance with standard convective theory.

Electric circuits are present to measure temperature and operate the heater and the feedback mechanism. A potential divider made up of a precision resistor and two or more PRT5 46 (platinum resistor thermometers) is provided. A precision voltage reference acts as the power supply for the potential divider network. The voltage across each resistive element is measured by a multichannel ADC. The microcontroller in the processor 24 executes firmware that periodically reads' the voltage across each resistive element, converts to a resistance value and from a well known performance relationship between resistance and temperature for the PRTs derives the temperature sensed by each PRT. The microcontroller, under user control, can vary the voltage applied across a heater 48. An ADC senses the voltage across the heater and feeds back to the microcontroller so that minor adjustments to the applied voltage can be made and also acts as a safeguard against component failure.

The multiphase flowmeter 10 also comprises a DC battery 25, illustrated in Figure 1. Use of a DC power signal applied across the fluid at the sensor 16 can provide a measurement of electrolytic or battery response which is indicative of the quantity of minerals, in particular salt, present in the fluid 12. This measurement can be done independently of the electrical means 36 or can be used to verify and/or assist in the calculation of composition being a measure of the brine present when considered with the water measurement. Stored data on the change of properties in brine in the presence of DC current over time is also used.

Thus the sensor 16 in the multiphase flowmeter 10 determines the proportions of fluids present and their respective flow rates in a conduit over a sensed area which can be equivalent to a spot measurement. The processor 24 calculates the values from the measured amplitudes and frequencies of the receiver circuit 70 and the temperature measurements of the circuit 80. This can be done as an iterative process whereby a course measurement is initially taken and then sensitivity and frequency ranges varied to collect more precise data. Additionally the measurements can be compared to a database of historical and/or reference values. As the complex impedance and temperature loss can be determined in laboratory conditions for predetermined mixtures of fluids at set flow rates, reference values can be stored which are representative of these known conditions for comparison and to aid in the interpretation of measurements made in the pipe 14. Use of the fact that brine has a complex frequency behaviour can be further used to make the fluid volume fraction determination. The values can be transmitted to a remote data logger 32 for storage and/or further processing.

Additionally the values can be displayed on a visual unit 34 for a user.

Alternative embodiments for the arrangements of the sensor 16 or sensing module, processor 24 and data logger 32 of the multiphase flowmeter 10 are shown in Figures 6(a)-(c). In Figure 6(a) the arrangement of Figure 1 is shown wherein the sensor 16 is inserted into a surface pipeline (not shown) and connected to the electronics module 30 via a short length of cable being wire 26. The electronics module will include the circuits of Figures 3 to 5. There will then be a further cable 27 connecting electronics module 30 to a remote logger 32 which in this case may be a PC based system that will receive and transmit data to the electronics module 30 and a visual display unit 34 or touchscreen to allow the display of the flow rates, fluid composition and other useful information.

In Figure 6(b), a block diagram of an alternative system implementation is shown. In this implementation the sensor 16 and electronics module 30 are physically one entity with the sensor body and sensing electronics 30 inserted into the surface pipeline and the conditioning and measuring electronics in the datalogger 32 remaining external to the surface pipeline. In such an embodiment, a source of power for the electronics module is required. This could be AC or DC depending on the electronics within the module. The remote logger 32 and display unit 34 are connected to the electronics module 30 via a communications cable 29.

Communications could be via a number of different protocols, one of which being R5485.

Referring to Figure 6(c) there is shown a block diagram of a second alternative typical system implementation. In this example the sensor 16 is arranged remotely from the sensing electronics 30 with the sensor 16 inserted into the surface pipeline. The electronics module 30 and a data logger 32 Pc with VDU/touchscreen 34 (not shown) are combined into a single enclosure and connected to the sensor 16 via the short wire 26. Power will be supplied to the single enclosure; either AC or DC depending on the design of the logger/electronics internal to the enclosure.

The single sensor 16 described hereinbefore can be substituted for a number of sensors 16 arranged in an array on the same plane in the pipe 14 in a sensing module. The values for each sensor l6gives a spot measurement which can be used to provide a 2D representation of fluid composition and flow rate over a cross-section of the pipe 14.

Sensors 16 can be aligned in a linear array 13 as illustrated in Figure 7. Like parts to those in the earlier figures have been given the same reference numeral to aid clarity. Array 13 comprises three sensors 16 which are equally spaced across the diameter of the pipe 14. The sensors 16 are attached onto one cylindrical rod 18. It will be appreciated that rod 18 can be held within the bore 15 of the pipe 14 by any known method. The sensors 16 are coupled together via wire 26 located within the rod 18 providing protection in what may be a harsh environment of multiphase fluid flow through the bore 15. In this arrangement, three sensed areas 22 are provided for. This is advantageous when the pipe 14 is located horizontally, as heavier constituents such as oil will tend to travel towards the base 17 of the bore 15 whereas the gas and lighter constituents will be above. This will be reflected in the composition volume fraction calculated for each sensed area 22. This arrangement also assists in determining slip velocities due to the multiple measurement points. Equally, though shown in exaggerated form, the sensors 16 can be made very small so that the sensed area 22 is equivalently a point in the plane of the cross-section. Depending on the diameter of the pipeline, a linear array of ten's of sensors could be used to give a linear profile of fluid velocity and fluid composition volume fraction. A bulk measurement for the pipe 14 is therefore avoided. By making the sensors 16 small, the insertion of the rod 18 should not interfere with fluid flow through the bore 15. In this way, a non-invasive measurement technique is presented which can give results in near real-time.

To obtain a 2D representation of fluid velocity and fluid composition volume fraction over the cross-section of the pipe 14, the sensors 16 are located in a 2D array 19. A sensor 16 is located at each co-ordinate within the array 19 for which a measurement is desired. A mesh arrangement may be used which would mount the sensors 16 in a regular square array. Alternatively, a circumferential or radial array 19 as shown in Figure 8 may be used. Multiple rods 18 with any desired number of sensors 16 mounted along their lengths are positioned across the diameter of the pipe 14, with each rod being rotated around the cross-section to equally space the rods 18 in a circumferential array 19. In the array 19 shown, there are four rods with two sensors 16 on each rod 18 and advantageously, one rod 18a, includes a central sensor 16a, so that a central sensed area 22a measurement in the pipeline 14 is also obtained. The sensors 16 can be coupled via wire to a single processor and results displayed as a 2D map representation on a unit for an operator (not shown). The 2D representation is formed by mathematical analysis of the individual spot measurements of fluid type and fluid velocity thanks to the array of small sensors in place which are in direct contact with the fluid flow.

In a further embodiment, several sensors 16 could be mounted radially around each cylindrical rod 18 to provide the arrangement shown in Figure 9. Oppositely arranged sensors 16b are now on the same plane, but sensors 16b,c,d will be on parallel planes. If the rod 18 and sensors are small enough the sensed areas 22 can be approximated to appear on the same plane. Alternatively, they may be dimensioned so that a plurality of cross-sections of the pipe 14 can be measured. This provides a determination of fluid composition and flow rate at points along the pipe 14. Equally, the arrays of Figures 1, 7 and 8 could be mounted at intervals along a pipe to obtain similar 3D measurements.

The principle advantage of the present invention is that it provides a multiphase flowmeter in which the flow rate and fluid composition can be determined at substantially the same position in a conduit.

A further advantage of the present invention is that it provides a multiphase flowmeter in which a spot measurement can be made in the conduit and thus a bulk measurement is avoided.

A yet further advantage of at least one embodiment of the present invention is that it provides a multiphase flowmeter in which, by sweeping the frequency over a resonant circuit, low resonance features representing water can be detected.

It will be appreciated by those skilled in the art that various modifications may be made to the invention herein described without departing from the scope thereof. For example, while the description relates to a surface pipe having a cylindrical bore, the conduit could be of any cross-sectional shape and be found in other environments such as underwater and in a well. Additionally, the sensors could be arranged to provide several non-continuous probes that do not run across the whole diameter of the pipe.

Claims

CLAIMS1. A multiphase flowmeter for determining the proportions of fluids present and their respective flow rates in a conduit, comprising: a sensor, the sensor being mounted in the conduit in contact with fluid flow therethrough, the sensor including electrical means to measure an electrical property of a fluid over a sensed area of the conduit and temperature means to measure a temperature differential indicative of a cooling effect of fluid flow substantially at the sensed area; and a processor to calculate the proportions of fluids present in the sensed area from the electrical property and the flow rate from the temperature differential.
2. A multiphase flowmeter according to claim 1 wherein there is a plurality of sensors located in an array and each sensed area is distinct.
3. A multiphase flowmeter according to claim 1 or claim 2 wherein the electrical means comprises a fluid identifier probe, the probe being arranged in the sensed area.
4. A multiphase flowmeter according to claim 3 wherein the electrical means is arranged to provide a complex impedance between the fluid identifier probe, an earthed metal element and the fluid, and wherein the earthed metal element is selected from a group comprising: a portion of the sensor body, a portion of a mounting of the sensor or a portion of a wall of the conduit.
5. A multiphase flowmeter according to any preceding claim wherein the temperature means is a fluid velocity heat loss sensor.
6. A multiphase flowmeter according to claim S wherein the fluid velocity heat loss sensor comprises a fluid temperature probe, at least one fluid temperature probe temperature sensor and a heater element.
7. A multiphase flowmeter according to claim 6 wherein the fluid identifier probe and the fluid temperature probe are formed together as a single probe.
8. A multiphase flowmeter according to claim 7 wherein the temperature means further comprises one or more fluid temperature sensors.
9. A multiphase flowmeter according to claim 8 wherein there is a plurality of fluid temperature sensors.
10. A multiphase flowmeter according to any one of claims 3 to 9 wherein the multiphase flowmeter includes an electronic circuit, the electronic circuit forming a resonant circuit with the fluid identifier probe.
11. A multiphase flowmeter according to any preceding claim wherein the multiphase flowmeter includes a DC power supply.
12. A multiphase flowmeter according to any preceding claim wherein the processor includes a database of historical data for comparison to the measurements from the electrical means.
13. A multiphase flowmeter according to claim 12 wherein the historical data comprises complex impedance values for known fluids and fluid mixtures.
14. A multiphase flowmeter according to any one of claims 10 to 13 wherein the multiphase flowmeter comprises a sensing module including a plurality of sensors for location in the conduit, an electronics module including the electronics circuit and a remote data logger including a display unit on which to view the determined proportions of fluids present and their respective flow rates in the conduit.
15. A multiphase flowmeter according to claim 14 wherein the processor is in the electronics module.
16. A multiphase flowmeter according to claim 14 wherein the processor is in the data logger.
17. A method of determining the proportions of fluids present and their respective flow rates in a multiphase flow through a conduit, comprising the steps: a) providing a multiphase flowmeter according to the first aspect; b) locating an array of sensors over a cross-sectional area of the conduit; c) measuring an electrical property of sensed areas of the fluid from the sensors; d) measuring a temperature differential between a temperature of the fluid and a temperature of a heated surface over the sensed areas of the sensors; e) using the electrical property to determine the proportions of and fluids present in each area; and f) using the temperature differential to determine the flow rates of the fluids present.
18. A method according to claim 17 wherein step (c) comprises measuring resonant frequency.
19. A method according to claim 18 wherein the resonant frequency measurement is from a resonant circuit comprising a resistor, an inductor and a complex impedance formed by the sensor body, a fluid identifier probe in the sensor and the fluid in the conduit.
20. A method according to any one of claims 17 to 19 wherein step (c) comprises making measurements around several resonant frequencies and comparing the reactive and real parts of each measurement, at different frequencies.
21. A method according to any one of claims 17 to 20 wherein step (e) comprises utilising a difference in high frequency versus low frequency behaviour to determine the fluid composition present in the flow.
22. A method according to any one of claims 18 to 21 wherein step (e) comprises utilising an amplitude of a resonant peak of the circuit as a measure of salt water present.
23. A method according to any one of claims 17 to 22 wherein step (f) comprises utilising the constant differential temperature technique including measuring the difference between a heated fluid temperature probe and the ambient temperature of the fluid composition.
24. A method according to any one of claims 17 to 23 wherein step (f) comprises determining the presence of air in the fluid composition.
25. A method according to any one of claims 17 to 24 wherein the method includes the step of determining a proportion of gas present by measuring heat rise of the fluid temperature probe.
26. A method according to any one of claims 17 to 25 wherein the method includes the step of using a DC measurement of electrolytic behaviour to determine the proportion of salt present.
27. A method according to claim 26 wherein the determination of salt present, being the salinity of the water present, is by both volume fraction measurement and DC resistance measurement.
28. A method according to any one of claims 17 to 27 wherein steps (e) and (f) are performed in a processor wherein signal analysis may be performed.
29. A method according to claim 28 wherein the analysis is iterative.
30. A method according to claim 28 or claim 29 wherein step the signal analysis includes comparing data to stored historical data.