WO2018002293A1 - Dispositif de mesure de vitesse d'écoulement et procédé de mesure de vitesse d'écoulement d'un fluide - Google Patents

Dispositif de mesure de vitesse d'écoulement et procédé de mesure de vitesse d'écoulement d'un fluide Download PDF

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Publication number
WO2018002293A1
WO2018002293A1 PCT/EP2017/066246 EP2017066246W WO2018002293A1 WO 2018002293 A1 WO2018002293 A1 WO 2018002293A1 EP 2017066246 W EP2017066246 W EP 2017066246W WO 2018002293 A1 WO2018002293 A1 WO 2018002293A1
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WO
WIPO (PCT)
Prior art keywords
fluid
flow
distributed
flow velocity
disturbing
Prior art date
Application number
PCT/EP2017/066246
Other languages
English (en)
Inventor
Dhruv Arora
Matheus Norbertus Baaijens
Stephen Palmer Hirshblond
Original Assignee
Shell Internationale Research Maatschappij B.V.
Shell Oil Company
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Shell Internationale Research Maatschappij B.V., Shell Oil Company filed Critical Shell Internationale Research Maatschappij B.V.
Priority to CA3027267A priority Critical patent/CA3027267A1/fr
Priority to US16/312,679 priority patent/US10920581B2/en
Publication of WO2018002293A1 publication Critical patent/WO2018002293A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/01—Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/107—Locating fluid leaks, intrusions or movements using acoustic means
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/113—Locating fluid leaks, intrusions or movements using electrical indications; using light radiations
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
    • E21B47/135—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency using light waves, e.g. infrared or ultraviolet waves
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/66—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by measuring frequency, phase shift or propagation time of electromagnetic or other waves, e.g. using ultrasonic flowmeters
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01H—MEASUREMENT OF MECHANICAL VIBRATIONS OR ULTRASONIC, SONIC OR INFRASONIC WAVES
    • G01H9/00—Measuring mechanical vibrations or ultrasonic, sonic or infrasonic waves by using radiation-sensitive means, e.g. optical means

Definitions

  • the present invention relates to a flow velocity meter, for measuring flow of a fluid. In another aspect, the present invention relates to a method of measuring flow velocity of a fluid. In yet another aspect, the present invention relates to a method of producing a fluid from a formation in the earth and in still another aspect the invention relates to a method of injecting a fluid into a formation in the earth.
  • This opto-acoustic flow velocity meter employs acoustic emitters positioned at known locations, which produce acoustic energy as fluid flows through or across the emitters.
  • the acoustic energy is detected with an optical distributed acoustic sensing (DAS) system.
  • DAS optical distributed acoustic sensing
  • the emitters are made with cavities, similar to flutes and/or whistles.
  • US-2014/0338438-A1 discloses a method of verifying a substance interface location during a cementing
  • a method of determining a property of at least one substance flowed in a wellbore can include optically measuring vibrations caused by the substance flowing across structures distributed along a wellbore, the vibrations being caused at each structure, and the structures having different shapes, thereby causing the vibrations at the structures to be different from each other when the substance flows across the differently shaped structures.
  • US-2014/0338438-A1 refers to placement of structures. Herein, vortices will be shed in a periodic manner.
  • the frequency of vibrations detected by an optical waveguide will be directly dependent on the velocity U of the cement composition or substances.
  • a flow velocity meter for measuring flow of a fluid, comprising distributed fluid- contact surface and a distributed acoustic sensor along a longitudinal direction, which distributed acoustic sensor comprises a distributed sensing element that is
  • a method of measuring flow of a fluid comprising providing, in the fluid, a flow velocity meter as defined in the preceding paragraph, and allowing the fluid to flow along and in contact with at least the part of the fluid-contact surface that is provided with the flow-disturbing surface texture, thereby emitting acoustic flow noise which is picked up by the distributed sensing element as a distributed acoustic signal.
  • measuring flow of a fluid as defined in the preceding paragraphs may be employed in methods of producing a fluid from a formation in the earth and/or methods of injecting a fluid into the formation in the earth.
  • a method of producing a fluid from a formation in the earth may comprise allowing the fluid from the formation is to enter into a wellbore at one or more locations, whereby measuring the flow velocity of the fluid flowing in the wellbore with the method of measuring flow of a fluid and/or using the flow velocity meter, as defined in the preceding paragraphs.
  • a method of injecting a fluid into a formation in the earth may comprise forcing the fluid to flow down a wellbore from the wellbore, at one or more locations, into a formation of the earth, whereby measuring the flow velocity of the fluid flowing down the wellbore with the method of measuring flow of a fluid and/or using the flow velocity meter, as defined in the preceding paragraphs.
  • Fig. 1 schematically shows a flow diagram of a method of measuring flow of a fluid
  • Fig. 2 schematically shows a perforated wellbore in the earth provided with an opto-acoustic distributed flow velocity meter according to one group of embodiments
  • Fig. 3 schematically shows a perforated wellbore in the earth provided with an opto-acoustic distributed flow velocity meter according to another group of embodiments;
  • Figs. 4-6 schematically show examples of pre ⁇ determined patterns of surface reliefs;
  • Fig. 7 shows a cross section of a wellbore
  • Fig. 8 shows an embodiment of an embodiment of a flow inducing body of the disclosure
  • Fig. 9 shows an exemplary diagram indicating a relation between sound pressure level (y-axis) versus flow velocity (x-axis) for conventional wellbore systems and embodiments of the disclosure.
  • Fig. 10 shows an exemplary diagram indicating a relation between signal to noise ratio (SNR; y-axis) versus Reynolds number (Re; x-axis) for conventional wellbore systems and embodiments of the disclosure.
  • SNR signal to noise ratio
  • Re Reynolds number
  • the proposed flow velocity meter comprises a distributed acoustic sensor that is acoustically coupled to a distributed fluid-contact surface via a distributed acoustic path.
  • the distributed acoustic sensor comprises a distributed sensing element, capable of picking up acoustic signals in an uninterrupted continuous length interval in a longitudinal direction.
  • the distributed acoustic path extends between the distributed fluid- contact surface and the fiber optic waveguide to achieve a close acoustic coupling between the distributed fluid- contact surface and the distributed sensing element.
  • the distributed acoustic path may fully bypass the fluid that is subject to the measurement of its flow velocity.
  • At least a part of the fluid-contact surface is provided with a flow-disturbing surface texture having a surface relief with a pre-determined pattern in said longitudinal direction.
  • acoustic flow noise is emitted when (1) the fluid flows along and in contact with (2) the flow-disturbing surface texture of a distributed flow-disturbing surface.
  • This acoustic flow noise (3) is caused by the interaction of the fluid with the flow-disturbing surface texture.
  • the emitted acoustic flow noise signal can be (4) picked up by the distributed acoustic sensor.
  • the fluid flow is thus converted to sound, which has a specific acoustic signature that uniquely maps to flow velocity.
  • the acoustic signature may be characterized by (a combination of) frequency spectrum and/or amplitude.
  • the acoustic signature can be picked up by the distributed acoustic sensor, converted to a signal from the distributed sensing element which can be recorded.
  • An advantage of acoustically bypassing the fluid that is subject to the flow velocity measurement is that a more direct and efficient acoustic coupling to the distributed sensing element is achieved. This provides a more consistent acoustic signature.
  • the signal picked up by the distributed sensing element of the distributed acoustic sensor can be dominated by the generated acoustic flow noise compared to acoustic signals caused by other noise sources.
  • the positioning of the distributed sensing element is preferably in close proximity with the flow-disturbing surface texture to enhance the relative dominance of the acoustic flow noise that is purposely generated on the flow-disturbing surface texture over other acoustic noise that is picked up by the distributed acoustic sensor.
  • the acoustic signature can be (5) interpreted to determine the flow of the fluid.
  • the acoustic signature may be calibrated against flow velocity.
  • a parameter is attributed to the acoustic signature such that a unique link can be established between the value of the parameter and the flow velocity.
  • the parameter may for example relate to the flow velocity via a pre-determined relationship (which may be an empirically determined function) .
  • An example wherein air-flow velocity is derived from flow- generated sound, using a wave power parameter, is discussed in an article by Saeed Hosseini and Ali Reza Tahavvor, published in Int. J. of Mechanical, Aerospace, Industrial, Mechantronic and Manufacturing Eng. Vol.
  • the flow-disturbing surface texture forms a distributed source of sound when exposed to the fluid flowing along and in contact with at least the part of the fluid-contact surface that is provided with the flow-disturbing surface texture.
  • distributed in the context of the present
  • a distributed source of sound means that sound is generated along a continuous, uninterrupted stretch along the fluid-contact surface.
  • the fluid flow velocity has at least a component in said longitudinal direction.
  • the acoustic sensor is a distributed acoustic sensor, having a distributed sensing element, which means that the acoustic signals are sensed in a continuously distributed stretch along the length of the sensing element, as opposed to in discrete points.
  • a flow-disturbing surface texture having a surface relief with a pre-determined pattern can be fairly easy to manufacture. For instance, it may be manufactured by knurling the surface.
  • the distributed acoustic sensor comprises a cable in which the distributed sensing element is packaged in such a manner that the cable comprises an external surface facing away from the distributed sensing element.
  • the flow-disturbing surface texture can be provided on a portion of the external surface of the cable.
  • the integrated flow velocity meter can be provided which has both the distributed sensing element and the distributed flow-disturbing surface combined. This can be deployed relatively easily, is versatile in its application, and moreover has a predictable acoustic coupling between the textured surface and the sensing element that picks up the generated sound.
  • the flow-disturbing surface texture can be provided on a portion of a surface of a separate longitudinal body that is external to the distributed acoustic sensor. In that case, the
  • distributed acoustic sensor or at least the cable, can be mechanically adhered to the longitudinal body in touching contact with the longitudinal body via its external body surface. Sound generated at the external body surface is then acoustically coupled to the
  • the distributed sensing element is directly applied to the longitudinal body, without being packaged in a cable. This may involve employing for instance a protective tape which protects the distributed sensing element from direct exposure to the fluid.
  • FIG. 2 A practical implementation of the distributed flow velocity meter is illustrated in Fig. 2, wherein as an example both the distributed fluid-contact surface 12 and the distributed acoustic sensor 8 extend into wellbore 20 in the earth 30 along a longitudinal direction, which is schematically indicated at L.
  • the longitudinal direction does not have to be straight.
  • the distributed acoustic sensor 8 comprises a distributed sensing element 15.
  • the distributed sensing element 15 is packaged in a cable 10.
  • the wellbore 20 may be cased, or open, or partially open.
  • the wellbore 20 is cased, and the casing 21 is perforated with perforations 22 to allow formation fluids to flow from the formation into the wellbore (indicated by arrows 25) or to allow injection fluids to pass from the wellbore into the formation (e.g. for well stimulating operations) .
  • the flow profile may be of relevance there where in a wellbore multiple sidetrack wells and/or pinnate wells come together, causing confluence of fluids that field operators would like to monitor.
  • the wellbore 20 may further be provided with any combination of typical well equipment, including
  • FIG. 2 is very schematic to illustrate how the invention can be applied, and not intended to limit application of the invention to any specific wellbore design in any way.
  • the cable 10 may take any suitable form, preferably cylindrical, with any suitable cross sectional contour.
  • Example contours include circular, oval, faceted, multilateral (such as rectangular or trapezoid) , and concave and/or convex curved.
  • the cable 10 is of a low-profile design to keep any protrusion from the surface on which it is mounted to a minimum. Reference is made to co-pending US application serial No. 15/182,058 for specific examples of a suitable low-profile design.
  • the external surface of the cable which faces away from the distributed sensing element 15, forms the fluid- contact surface 12 of which at least a part 16 is provided with a flow-disturbing surface texture 14.
  • the flow-disturbing surface texture 14 preferably extends essentially uninterrupted for over a certain length interval in the longitudinal direction.
  • the part 16 of the fluid-contact surface 12 that is provided with the flow-disturbing surface texture 14 forms a distributed source of sound (acoustic flow noise) .
  • the flow-disturbing surface texture 14 suitably has a surface relief with a pre-determined pattern in the longitudinal direction. As the pattern is pre-determined, it is expected that the flow-generated acoustic noise has an acoustic signature that can be uniquely mapped to the flow velocity in a given configuration.
  • the pattern suitably is repetitive, at least in the longitudinal direction.
  • the repetitive pattern may be characterized with a periodicity, which is defined as the length in the longitudinal direction of the largest repetitive feature in the pattern.
  • the length interval over which the repetitive pattern extends (without substantial interruption) is suitably at least four times more than the period associated with the pattern, at least in the longitudinal direction.
  • the distributed sensing element 15 is acoustically coupled to the distributed fluid-contact surface 12. To this end, a distributed acoustic path extends between the distributed fluid-contact surface and the distributed sensing element, which fully bypasses the fluid of which the flow velocity is to be determined.
  • the distributed sensing element 15 is packaged in a cable 10, this means that the distributed sensing element 15 can be embedded in one or more materials, such as gel, which may be surrounded by one or more layers of other materials such as reinforcement layers, fluid tight layers, and layers offering protection from mechanical and chemical impact.
  • the external surface of the cable 10 may be formed by a metal jacket.
  • the acoustic flow noise generated by the interaction of the fluid with the flow-disturbing surface texture 14, traverses all of the layers to reach the distributed sensing element 15 and does not need to traverse through the fluid in order to reach the distributed sensing element 15.
  • Fig. 3 schematically shows a group of embodiments wherein the cable 10 is mechanically adhered to the production and/or injection tubing 40, which forms a longitudinal body positioned in the wellbore 20 in longitudinal direction.
  • the distributed fluid contact surface 12 is the body surface of the production and/or injection tubing 40.
  • the cable is in distributed touching contact with the production and/or injection tubing 40 via the body surface.
  • Flow-disturbing surface texture 14 provided on the body surface.
  • the fluid 25 is depicted as an injection fluid which enters the zone below packer 45 through an injection sub represented as openings in the injection tubing 40.
  • the acoustic flow noise generated by the interaction of the fluid with the flow- disturbing surface texture 14, travels through the wall material of the production and/or injection tubing 40, and via the distributed contact between the cable 10 and the body surface into the cable 10, where the acoustic noise traverses all of the layers to reach the
  • the acoustic flow noise does not need to traverse through the fluid 25 in order to reach the distributed sensing element 15.
  • the fluid of which the flow velocity is to be determined is allowed to flow along and in contact with at least the part of the fluid-contact surface that is provided with the flow-disturbing surface texture, so that a distributed sound source is created.
  • the proposed distributed flow velocity meter can be implemented in many other ways.
  • the flow-disturbing surface texture 14 may be provided on the inside surface of the production and/or injection tubing 40 while the distributed acoustic sensor is configured on the outside surface of the production and/or injection tubing 40.
  • the distributed sensing element (regardless of whether it is packaged in a cable or not) may be configured on the inside surface of the longitudinal body such as the inside surface of the production and/or injection tubing 40.
  • the surface relief may be embossed directly into or onto the cable or longitudinal body to which the cable and/or the distributed sensing element is adhered to.
  • the surface relief may be provided via an intermediate body such as bar, a rod, a strip, or a ring, that can be brought in contact with the production and/or injection tubing 40, with the cable 10, and/or with the distributed sensing element 15.
  • These items may, for instance, be strapped, glued, cemented, or screwed to the longitudinal body.
  • the distributed sensing element 15 is represented as a fiber optic waveguide, which can be used for subsurface distributed acoustic sensing.
  • the fiber optic waveguide may be optically coupled to an optical interrogator 17.
  • An optical probe signal can be transmitted from the optical interrogator 17 an emitted into the fiber optic waveguide.
  • the optical probe signal is subject to backscattering (Rayleigh scattering) by random micro-heterogeneities and/or impurities that are naturally present in and inherently distributed throughout the fiber optic waveguide.
  • Changes in the Rayleigh back-scattered pattern occur when distributed acoustic flow noise waves deform the fiber optic waveguide, and these are translated into the distributed acoustic signature of acoustic waves as they are picked up with the fiber optic waveguide. Part of the thus scattered probe signal can thus be used as optical return signal that is emitted from the fiber optic waveguide. The location of any deformation is determined from the known time of flight of the optical signal pulse that sensed it. The distributed signal from the fiber optic waveguide can be subdivided into acoustic channels.
  • Figures 4-6 show examples of surface relief patterns that can be selected.
  • Fig. 4 shows a pattern
  • Fig. 5 shows a pattern characterized by a set of
  • Fig. 6 shows a pattern that consists of a combination of Fig. 5 and Fig. 6, whereby the
  • interspacing in the sets of longitudinal/transverse grooves is larger than the interspacing in the sets of helical grooves.
  • Many more variants can be selected, including more complex patters inspired on, for instance, tire treads.
  • the types of longitudinal bodies as are depicted in Figs. 4-6 can be applied as the outer metal jacket of a cable, or they can be applied as a sleeve over a well tubular.
  • the patterns may also be applied directly on sections of well tubulars .
  • the patterns can be applied on convex (external) surfaces as shown in the Figures, and on concave (internal) surfaces of tubes or the like (not shown) , depending on where the flow velocity is to be determined.
  • the flow-disturbing surface texture may suitably be provided in the form of a knurled surface.
  • the flow velocity meter and/or the method of measuring flow of a fluid as described herein may be employed in methods of producing a fluid from a formation in the earth and/or methods of injecting a fluid into the formation in the earth.
  • Fig. 7 shows other practical embodiments of the distributed flow velocity meter.
  • the distributed acoustic sensor 8 comprises a distributed sensing element
  • the wellbore 20 may be cased, or open, or partially open.
  • the wellbore 20 is provided with casing 21 and liner 23.
  • Tubing 40 is arranged within the casing and liner.
  • the liner 23 is perforated with perforations 22 to allow formation fluids to flow into the wellbore or to allow injection fluids (indicated by arrows 31) to pass from the wellbore into the formation 30 (e.g. for well stimulating operations) .
  • Both casing 21 and liner 23 are provided with a cement shoe 27 and 29 respectively.
  • Packer 45 may be arranged between casing 21 and tubing 40 to allow injection of fluids 31 via injection sub 50.
  • Flow-disturbing elements 52 according to the disclosure may be arranged at one or more of the locations indicated in Figure 7. The elements may for instance be arranged on the tubing 40 (element
  • the flow-disturbing elements 52 may include a surface texture (such as indicated by 14 in Fig. 2) .
  • the flow-disturbing elements 52 may comprise a mechanical element.
  • Fig. 8 indicates a spring element, having an attachment 62 and windings having a certain diameter.
  • the diameter of the windings may vary, for instance increase in a direction away from the attachment 62.
  • diameter 66 at an end of the spring element may exceed the diameter 64 of a winding in the middle of the spring element 60.
  • the spring element may hinge on the attachment, i.e. the attachment may allow the windings to pivot or hinge with respect to the attachment.
  • the attachment can be fixed to another element within the wellbore (as indicated in, for instance, Fig. 7) .
  • the diagram of Fig. 9 indicates the relation of sound pressure level (y-axis; in dB) versus fluid flow rate (x- axis) .
  • the sound pressure level may be measured within a frequency range, for instance between 300 to 1200 Hz.
  • the diagram of Fig. 9 shows measurements 70, 72 and related trend lines 80, 82 relating to measurements without and with the flow-disturbing elements 52 respectively.
  • the sound pressure level has a linear relation with respect to the fluid flow rate. At least within a certain bandwidth of fluid flow, the difference between the trend line 80 (relating to measurements without the flow-disturbing elements 52) and the trend line 82 (relating to measurements with the flow- disturbing elements 52) increases substantially linearly with increasing flow rate.
  • This linear relation may be valid within, for instance, a bandwidth of fluid flow exceeding 7 GPM and/or below 10 or 11 GPM.
  • GPM indicates US gallons per minute (1 US gallon per minute - Il ⁇ ls about 6.31 ⁇ 10 ⁇ 5 m 3 /s) .
  • the sound pressure level is the amplitude of the noise. Thus, the amplitude relates directly to the flow rate.
  • Fig. 10 shows an exemplary diagram indicating a relation between signal to noise ratio (SNR;
  • trendline 90 relates to measurements without the flow-disturbing elements 52 and the trend line 92 relates to measurements with the flow-disturbing elements 52.
  • a method of producing a fluid from a formation in the earth may comprise allowing the fluid from the formation is to enter into a wellbore at one or more locations, whereby measuring the flow velocity of the fluid flowing in the wellbore with the method of measuring flow of a fluid and/or using the flow velocity meter, as described herein .
  • a method of injecting a fluid into a formation in the earth may comprise forcing the fluid to flow down a wellbore from the wellbore, at one or more locations, into a formation of the earth, whereby measuring the flow velocity of the fluid flowing down the wellbore with the method of measuring flow of a fluid and/or using the flow velocity meter, as described herein.
  • the method and system of the present disclosure provide an alternative to listening to or interpreting noise made by perforations.
  • the flow disturbing elements bring the source of the noise closer to the fiber 15, thus increasing accuracy of measurements.
  • the system and method have potential to greatly reduce the cost and complexity of fiber optic deployment.
  • the method and system of the disclosure provide benefits, such as a relatively simple design; a controlled source of noise; and improved coupling of the noise to the fiber optic measurement device.
  • Options for application of the method and system of the disclosure include, for instance, single phase flow (flow of oil, water, or mixtures of oil and water) .
  • the method is suitable for injection conformance.
  • Normalization of measurements may be done per reference band, for instance about 2kHz.
  • Excitations i.e. measured noise, may range up to frequencies in the order of 1500 Hz for smooth pipe, and up to 1700 Hz for pipe provided with flow disturbing elements.
  • the flow disturbing elements 52 induce about 10 times more flow noise the flow without these elements.
  • the sound intensity scales substantially linearly with the flow rate.
  • the signal to noise ratio (SNR) scales substantially linearly with the Reynolds number, when the SNR is plotted on a logarithmical scale.
  • the system and method of the disclosure allow surfaces or patterns for flow disturbance that can be placed close to the fiber. This improves accuracy.
  • Prior art refers to frequency of vortex shedding as primary source of acoustic signal.
  • the method and system of the disclosure relies on an increase in amplitude of the noise in relation to flow rate.

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  • Physics & Mathematics (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Geophysics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Remote Sensing (AREA)
  • Electromagnetism (AREA)
  • General Physics & Mathematics (AREA)
  • Acoustics & Sound (AREA)
  • Measuring Volume Flow (AREA)

Abstract

L'invention concerne un dispositif de mesure de vitesse d'écoulement, pour mesurer la vitesse d'écoulement d'un fluide, qui comprend un capteur acoustique distribué le long d'une direction longitudinale, qui a un élément de détection distribué. L'élément de détection distribué est couplé de manière acoustique à une surface de contact de fluide distribuée par l'intermédiaire d'un trajet acoustique distribué s'étendant entre la surface de contact de fluide distribuée et l'élément de détection distribué. De plus, le trajet acoustique distribué contourne entièrement le fluide. Au moins une partie de la surface de contact de fluide comprend une texture de surface de perturbation d'écoulement ayant un relief de surface avec un motif prédéterminé dans ladite direction longitudinale. Un bruit d'écoulement acoustique, émis en conséquence du fluide s'écoulant le long de la texture de surface de perturbation d'écoulement et en contact avec cette dernière, est capté par l'élément de détection distribué sous forme de signal acoustique distribué.
PCT/EP2017/066246 2016-06-30 2017-06-30 Dispositif de mesure de vitesse d'écoulement et procédé de mesure de vitesse d'écoulement d'un fluide WO2018002293A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
CA3027267A CA3027267A1 (fr) 2016-06-30 2017-06-30 Dispositif de mesure de vitesse d'ecoulement et procede de mesure de vitesse d'ecoulement d'un fluide
US16/312,679 US10920581B2 (en) 2016-06-30 2017-06-30 Flow velocity meter and method of measuring flow velocity of a fluid

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US201662356887P 2016-06-30 2016-06-30
US62/356887 2016-06-30
EP16178309.7 2016-07-07
EP16178309 2016-07-07

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Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2019166809A1 (fr) 2018-02-28 2019-09-06 Craley Group Limited Améliorations apportées ou se rapportant à la surveillance de tuyaux de fluide
CN111757973A (zh) * 2018-01-08 2020-10-09 沙特阿拉伯石油公司 定向敏感的光纤线缆井眼系统

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