Abstract:
A method of measuring multiphase flow of components in a wellbore fluid mixture by selectively heating components (e.g. oil and water) in the flow with electromagnetic energy, and detecting the heated components at a known distance downstream. The flow and velocity of components in the flow stream can be estimated with the present method. Example types of electromagnetic waves include infrared, microwaves, and radio waves. The different components can be heated simultaneously or at different times. The heated components can be detected with one or more temperature probes, and oil wet or water wet probes can be used to improve thermal contact to the corresponding components in the fluid stream.

Description:
BACKGROUND 
     1. Field of Invention 
     The invention relates generally to a flowmeter for measuring multiphase flow of wellbore fluids in a tubular. More specifically, the present invention relates to a flowmeter that heats a particular constituent in the flow stream electromagnetically and then measures the time delay until a temperature response is detected at some known distance downstream of the heating so as to estimate a flow velocity of that constituent. 
     2. Description of Prior Art 
     Flowmeters are often used for measuring flow of fluid produced from hydrocarbon producing wellbores. Flowmeters may be deployed downhole within a producing wellbore, a jumper or caisson used in conjunction with a subsea wellbore, or a production transmission line used in distributing the produced fluids. Monitoring fluid produced from a wellbore is useful in wellbore evaluation and to project production life of a well. In some instances transmission lines may include fluid produced from wells having different owners. Therefore proper accounting requires a flow measuring device that monitors the flow contribution from each owner. 
     The produced fluid may include water and/or gas mixed with liquid hydrocarbon. Knowing the water fraction is desirable to ensure adequate means are available for separating the water from the produced fluid. Additionally, the amount and presence of gas is another indicator of wellbore performance, and vapor mass flow impacts transmission requirements. Flowmeters can be employed that provide information regarding total flow, water cut amount, and gas fractions. However, these often require periodic analysis of the fluid entering the flowmeter. This may involve deploying a sample probe upstream of the flowmeter; which can produce inaccuracy, and may interrupt or temporarily halt fluid production. 
     SUMMARY OF THE INVENTION 
     The present disclosure includes a method and apparatus for measuring a flow of wellbore fluid by heating a fluid constituent with a wave of electromagnetic energy, and then detecting when the heated fluid reaches a location downstream at a known distance from where the fluid was heated. In an example embodiment, a method of measuring flow of a component of a wellbore fluid stream is disclosed that includes heating the component with an electromagnetic wave of a wavelength that the component absorbs. The temperature of the fluid stream downstream of where the fluid stream is being irradiated is monitored to detect when the temperature of the fluid stream increases due to heating with the electromagnetic wave. The velocity of the component is estimated based on the distance between where the fluid stream is being irradiated and where the temperature is being measured, and the time between when the fluid is heated and when the fluid stream temperature increases. In an example, the component is a first component and the fluid stream includes a second component, the second component is heated by irradiating the fluid stream with an electromagnetic wave having a wavelength that is absorbed by the second component. The velocity of the second component is estimated in a same way as for the first component. In an example embodiment, the first component can be a hydrocarbon. In an alternative, the wavelength of the electromagnetic wave can be about 1740 nanometers, which is a near infrared absorption peak for oil. Optionally, the frequency of the electromagnetic wave can have a value of about 15 MHz or about 5 MHz, which are microwave regions where crude oils preferentially absorb. In an example embodiment, the first component comprises water. In an alternative, the wavelength of the electromagnetic wave is about 1450 nanometers, which is a near infrared absorption peak for water. Optionally, the wavelength of the electromagnetic wave is about 1930 nanometers, which is another near infrared absorption peak for water. In an example, the frequency of the electromagnetic wave is about 18 GHz, which is a microwave region at which water preferentially absorbs. Other electromagnetic wavelengths at which the absorption of water and oil are very different may also be used. 
     Also disclosed herein is a method of measuring a flow of a wellbore fluid that in an example embodiment includes heating oil in the flow of wellbore fluid by directing infrared radiation into the flow, detecting a temperature change in the fluid downstream of where the infrared radiation is directed into the flow that is caused by the infrared radiation heating the oil, estimating a velocity of the oil in the flow that is based on a time difference between when the oil is heated by the infrared radiation and when the temperature change in the fluid is sensed that is caused by the infrared radiation heating the oil. The method further includes heating water in the flow of wellbore fluid by directing infrared radiation into the flow, detecting a temperature change in the fluid downstream of where the infrared radiation is directed into the flow that is caused by the infrared radiation heating the water, and estimating a velocity of the water in the flow that is based on a time difference between when the water is heated by the infrared radiation and when the temperature change in the fluid is sensed that is caused by the infrared radiation heating the water. In an example embodiment of the method, the infrared radiation for heating the oil has a wavelength of around 1740 nanometers. In an example embodiment of the method, the infrared radiation for heating the water, the wavelength is about 1450 nanometers or about 1930 nanometers. 
     In another example method, flow of one or more fluid components flowing in a stream of a wellbore fluid is evaluated. In an example embodiment of this method the stream of wellbore fluid is irradiated by a microwave with a frequency that is absorbed by the fluid component thereby heating the fluid component, a temperature of the stream of wellbore fluid is monitored at a location downstream of where the microwave is directed into the stream, a change in temperature of the stream of wellbore fluid is detected downstream of where the microwave is directed into the stream that is caused by directing the microwave into the stream of wellbore fluid. A velocity of the component is estimated based on a time difference between when the microwave is directed into the stream and when the change in temperature is detected, and a distance difference between where the microwave is directed into the stream and where the change in temperature is detected. Optionally, the component is oil. In an example when the component is oil, the frequency of the microwave can be about 5 MHz or about 15 MHz. In an alternate embodiment the component is water. In an example when the component is water the frequency of the microwave is about 18 GHz. In an example embodiment, the fluid includes oil and water components, and microwaves are directed into the fluid to heat both water and oil, and oil wet temperature probe and a water wet temperature probes, which should have better thermal contact with their corresponding components, are disposed downstream for monitoring temperature changes. Thus the oil and water components can be heated at substantially the same time and the heating of the oil and water components can be detected at substantially the same time. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
       Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which: 
         FIG. 1  is a side perspective view of an example embodiment of a flowmeter coupled with a tubular in accordance with the present invention. 
         FIG. 2  is a side partial sectional view of an embodiment of the flowmeter of  FIG. 1  disposed in production tubing. 
         FIGS. 3-6  are side sectional views of embodiments of the flowmeter of  FIG. 1  at operational sequences. 
         FIG. 7  is a side partial sectional view of an embodiment of the flowmeter of  FIG. 1  disposed in a downhole tool. 
         FIG. 8  is a side partial sectional view of an alternate embodiment of a temperature probe for use with a flowmeter in accordance with the present invention. 
     
    
    
     While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims. 
     DETAILED DESCRIPTION OF INVENTION 
     The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. 
     It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation. Accordingly, the improvements herein described are therefore to be limited only by the scope of the appended claims. 
     An example embodiment of a flowmeter assembly  20  is shown in a side perspective view in  FIG. 1 . The flowmeter assembly  20  of  FIG. 1  is coupled with a tubular  22  in which a flow of fluid travels axially through the tubular  22 . Included with the flowmeter assembly  20  is an electromagnetic source  24  that in the schematic example of  FIG. 1  circumscribes the outer periphery of the tubular  22 . However, other examples exist wherein the electromagnetic source  24  projects along only a portion of the tubular  22  outer circumference. Further illustrated in the example embodiment of  FIG. 1  is an aperture  25  provided through the wall of the tubular  22 , and in a segment of the region where the tubular  22  is circumscribed by the electromagnetic source  24 . An electromagnetic wave  26  is illustrated being directed into the fluid flow in the tubular  22  from the electromagnetic source  24 . In an example embodiment, an optional window  27  may be set in the aperture  25 , wherein the window  27  is designed to allow passage of electromagnetic waves that are within a designated range, such as the near infrared range or microwave range. The flowmeter assembly  20  of  FIG. 1  also includes a temperature probe  28  depicted set within the tubular  22 . In the embodiment of  FIG. 1 , the temperature probe  28  is at a location downstream of where the electromagnetic source  24  is located and at a distance X from the point where the electromagnetic waves  26  enter the tubular  22 . Lines  30 ,  31  are connected respectively to the probe  28  and electromagnetic source  24  on one end and that connect to a monitor  32  on the other end. The monitor  32  may be at a location remote from the electromagnetic source  24 . 
       FIG. 2  is a side partial sectional view of an alternate embodiment of the flowmeter assembly  20 A wherein the tubular  22 A is a modular section coaxially set in production tubing  33 . The production tubing  33  is disposed within a wellbore  34  and is for flowing fluid extracted from a formation  36  up the wellbore  34  and to a wellhead assembly  38  set on an upper end of the wellbore  34 . The tubular  22 A of  FIG. 2  can be formed from material that can be penetrated by an electromagnetic wave  26  of the chosen wavelengths. Examples of material for the tubular  22 A of  FIG. 2  include pure near-infrared-transparent materials such as perfluorocyclobutyl copolymers for near infrared or microwaves. For microwaves, material for the tubular  22 A can be composites, either molded or wound, of epoxy, Kevlar®, glass, aramid, a polymer matrix, an epoxy resin, and combinations thereof. Also in the example of  FIG. 2 , the monitor  32  is set on surface above the opening of the wellbore  34  so that flow through the flowmeter assembly  20  can be remotely measured and recorded. 
       FIG. 3  illustrates a side sectional view of an example of operation of the flowmeter assembly  20 . In the example of  FIG. 3 , fluid flow within the tubular  22  includes a first fluid  40  and second fluid  42 . In an example embodiment, the first fluid  40  can be a hydrocarbon extracted from a subterranean formation, such as oil, and the second fluid  42  comprises water produced along with the hydrocarbon. As provided in  FIG. 1 , and represented by the dashed line traversing the tubular  22  of  FIG. 3 , a source line L S  illustrates the location in the tubular  22  where electromagnetic waves  26   1  are directed into the tubular  22 . In the example of  FIG. 3 , the electromagnetic waves  26   1  are designed to be absorbed by the first fluid  40  and thereby heat the fluid downstream of line L S . To illustrate the heated effect, first fluid  40 A is shown in a shaded view and downstream of line L S . The electromagnetic waves  26   1  are chosen because their wavelength is absorbed by a particular fluid to heat that fluid, which in the example of  FIG. 3  is the first fluid  40 . As such, the second fluid  42 , does not absorb the particular electromagnetic waves  26   1 , is not heated by the electromagnetic waves  26   1 , and thereby stays at substantially the same temperature downstream of line L S  as it was upstream of line L S . 
     Referring now to  FIG. 4 , the heated first fluid  40 A flows downstream of line L S  and proximate to the probe  28 . The temperature of the stream downstream of line L S  changes in response to the heated first fluid  40 A, the stream temperature change can be detected by monitoring stream temperature with the probe  28 . Thus, in one example, the time between when the electromagnetic waves  26   1  are directed into the flowstream along line L S  and when the temperature difference in the fluid stream is detected by the temperature probe  28  is measured. The velocity of the heated first fluid  40 A can be estimated by dividing the measured time by the known distance X, which is the distance traveled by the heated first fluid  40 A after being heated and then being detected. 
     Similarly, as shown in  FIG. 5 , velocity of the second fluid  42  can be estimated by directing an electromagnetic wave  26   2  into the fluid flow to form a heated second fluid  42 A, then calculating the velocity of the second fluid by dividing the traveled time by the traveled distance as is described above in relation to  FIG. 4 . The amplitude of the temperature response can be correlated to the volume fraction of that constituent in the flow stream. The flow quantity of that constituent can be estimated as the product of the flow velocity, cross-sectional area of the tubular, and volume fraction of that constituent. The flow quantity can be in terms of a volumetric flow rate or a mass flow rate. 
     In an alternate example provided in  FIG. 6 , a pulse of electromagnetic waves  26   1  heats a plug of heated first fluid  40 A in the flow shown flowing within the tubular  22  and across the probe  28 . A series of pulses of electromagnetic waves  26   1 , accompanied by continuously monitoring the temperature difference in the temperature probe  28 , can provide a continuous real-time measurement of flow within the tubular  22 . To avoid aliasing, the pulses can be separated in time by more than the fluid travel time between heating and detection. Optionally, a second probe  44  may be included within the tubular  22 , wherein one of the probes  28 ,  44  is coated with an oil wet or water wet substance so that either only water or oil is sensed by the particular probe. In an example embodiment having both the oil wet and water wet probes, electromagnetic waves may be directed into the tubular for heating both water and oil simultaneously that may then be detected by the corresponding water or oil wet probe downstream in the fluid flow. 
     Referring now to  FIG. 7 , a side partial sectional view is shown of an example where the flowmeter assembly  20 A is disposed within an elongated downhole tool or sonde  46 . In this example, the sonde  46  is inserted within production tubing  22  and into a fluid flow as shown by the arrows. An entrance (not shown) formed through a housing of sonde  46  enables the fluid flow to enter into the sonde  46  and make its way through the flowmeter assembly  20 A. A conveyance means  48 , which can be a wireline, slick line, or coiled tubing, can be used to deploy the sonde  46  and flowmeter assembly  20 A within the tubing  22 . Communication from the flowmeter assembly  20 A can be provided to surface through the conveyance means  48  and up into the wellhead assembly  38 . The conveyance means  48  couples with a wire  50  inside the wellhead assembly  38  that then extends from the wellhead assembly  38  into the monitor  32  for relaying signals to and from the flowmeter assembly  20 A and also enables control signals to be directed back into the wellbore  34  from the surface. 
     For contact temperature measurement, an alternate embodiment of a probe  28 A is illustrated in  FIG. 8  that includes an array  52  of probes. The array  52  of  FIG. 8  includes thermocouples  54  suspended in the flow stream disposed strategically throughout the cross section of the tubular  22 . Providing multiple thermocouples  54  as shown allows measuring a temperature distribution throughout the cross sectional area of the tubular  22 . A matrix  56  of thin elongate members provides a mounting surface for the thermocouples  54 . Leads  58  between the thermocouples  54  and line  30 A provide discrete communication to individual thermocouples  54  so the location in the tubular  22  where a signal is recorded can be correlated with the value of the signal. To improve thermal contact with the corresponding phase, selective thermocouples  54 , such as every other thermocouple  54 , could be coated with either an oil wet or water wet coating. Alternatively, probe  28  could be a non-contact sensor such as a pyroelectric detector. 
     In one example, the electromagnetic wave(s) is made up of an infrared wave and having a wave length of about 1,450 nanometers. Optionally, the wave length of the electromagnetic wave can be about 1,930 nanometers. When in this range, the electromagnetic wave is useful for heating water within the fluid stream. In situations when it is desired to heat oil within the stream, an infrared wave having a wave length of about 1,740 nanometers can be used. Optionally, microwaves can be used that in one example embodiment have frequencies that are about 15 MHz, and in another embodiment have a frequency of around 5 MHz. In this example, the heated fluid would be oil. For a microwave useful for heating water, the microwave has a frequency of about 18 GHz. 
     The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.