WO2021025667A1 - Outil de fond de trou qui surveille et commande la venue d'un fluide produit sur la base de mesures de composition de fluide utilisant un dispositif de transducteur acoustique électromagnétique (emat) - Google Patents

Outil de fond de trou qui surveille et commande la venue d'un fluide produit sur la base de mesures de composition de fluide utilisant un dispositif de transducteur acoustique électromagnétique (emat) Download PDF

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Publication number
WO2021025667A1
WO2021025667A1 PCT/US2019/044892 US2019044892W WO2021025667A1 WO 2021025667 A1 WO2021025667 A1 WO 2021025667A1 US 2019044892 W US2019044892 W US 2019044892W WO 2021025667 A1 WO2021025667 A1 WO 2021025667A1
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WO
WIPO (PCT)
Prior art keywords
flowline
downhole tool
flow
produced fluids
emat
Prior art date
Application number
PCT/US2019/044892
Other languages
English (en)
Inventor
Mohammed Badri
Reza Taherian
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
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 Schlumberger Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V. filed Critical Schlumberger Technology Corporation
Priority to PCT/US2019/044892 priority Critical patent/WO2021025667A1/fr
Publication of WO2021025667A1 publication Critical patent/WO2021025667A1/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
    • E21B47/10—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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • 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
    • 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
    • G01F1/05—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 using mechanical effects
    • G01F1/34—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 using mechanical effects by measuring pressure or differential pressure
    • G01F1/36—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 using mechanical effects by measuring pressure or differential pressure the pressure or differential pressure being created by the use of flow constriction
    • G01F1/40—Details of construction of the flow constriction devices
    • G01F1/44—Venturi tubes

Definitions

  • the present disclosure relates to systems and methods of monitoring and controlling the inflow of produced fluids into a wellbore.
  • wellbores In order to effectively recover hydrocarbons from some subterranean formations, wellbores can be drilled with highly deviated or horizontal portions that extend through a number of separate hydrocarbon-bearing production zones.
  • the reservoir fluid (produced fluids) produced from each one of these separate production zones may have distinct characteristics such as pressure, porosity and water content. In some instances, these characteristics can contribute to undesirable production patterns. For example, if not properly managed, a first production zone with a higher pressure may deplete earlier than a second, adjacent production zone with a lower pressure. Since nearly depleted production zones often produce unwanted water that can impede the recovery of hydrocarbon containing fluids, permitting the first production zone to deplete earlier than the second production zone may inhibit production from the second production zone and impair the overall recovery of hydrocarbons from the wellbore.
  • ICVs inflow control valves
  • ICDs inflow control devices
  • ICVs generally require produced fluid to first pass through a flow channel of a size and shape that is adjustable from the surface.
  • An ICD is a generally passive tool that is provided to increase the resistance to flow at a particular downhole location.
  • a helix type ICD requires produced fluids flowing into production tubing to first pass through a helical flow channel within the ICD. Friction associated with flow through the helical flow channel induces a desired flow rate.
  • nozzle-type ICDs require produced fluid to first pass through a tapered passage to induce a desired flow rate.
  • a desired flow distribution along a length of production tubing may be achieved by installing an appropriate number and type of the downhole tools to the production tubing.
  • ICDs can be sensitive to uncertain variations in the properties of the reservoir fluids, which can lead to the undesirable restriction of the inflow of wanted reservoir fluids (oil) or the undesirable inflow of unwanted reservoir fluids such as water.
  • a downhole tool is provided that is operably disposed in a wellbore and used to regulate fluid flow through the wellbore.
  • the downhole tool can include a housing that includes a flowline, a valve that is operable to regulate flow of produced fluids through the flowline, and an electromagnetic acoustic transducer (EMAT) device supported by the housing.
  • the EMAT device can be operable to perform measurements that are used to characterize water- cut of produced fluids that flow through the flowline for selective control of the valve.
  • a system for regulating fluid flow through the wellbore can include a downhole tool operable to be disposed in the wellbore, the downhole tool including a housing that includes a flowline, a valve that is operable to regulate flow of produced fluids through the flowline, and an EMAT device supported by the housing, wherein the EMAT device is operable to perform measurements that are communicated to a processor, wherein the processor is configured to characterize water-cut of produced fluids that flow through the flowline based on the measurements performed by the EMAT device for selective control of the valve of the downhole tool.
  • FIG. 1 is a schematic cross-sectional view of a wellbore extending through a hydrocarbon-bearing formation with a plurality of downhole tools installed therein as part of a completion in accordance with the present disclosure
  • FIG. 2 is an enlarged schematic cross-sectional view of one of the downhole tools of FIG. 1;
  • FIG. 3 is a schematic cross-sectional view of a flow control unit that is part of the downhole tools of FIGS. 1 and 2 in accordance with the present disclosure
  • FIG. 4A is a schematic illustration of an Electromagnetic Acoustic Transducer (EMAT) device
  • FIG. 4B is a schematic illustration of an EMAT device that can be part of the flow control unit of FIG. 3 for characterizing water-cut of produced fluids that flow through the flow control unit;
  • FIG. 5 is a schematic illustration of another EMAT device that can be part of the flow control unit of FIG. 3 for characterizing water-cut of produced fluids that flow through the flow control unit;
  • FIG. 6 is a functional block diagram illustrating interfaces between a processor/actuator and components of the flow control unit in accordance with the present disclosure
  • FIG. 7 is a flow chart illustrating operations of the processor/actuator of FIG. 6 in accordance with the present disclosure.
  • FIG. 8 is a schematic diagram of an example computer system that can be used to implement the processor/actuator of FIG. 6 in accordance with the present disclosure.
  • horizontal wellbore or “horizontal wellbore portion” refers generally to a wellbore or portion thereof that departs from vertical by an angle that can exceed about 80 degrees. Note that some horizontal wellbores are designed such that after reaching a true horizontal orientation (90 degrees from vertical), the wellbore may actually extend upward or downward. Because a horizontal wellbore typically penetrates a greater length of the reservoir, it can offer significant production improvement over a vertical wellbore.
  • the term “completion” refers to an assembly of downhole tubulars (or production tubing) and other supporting equipment that provides safe and efficient production of reservoir fluids (such as oil, gas and possibly connate water and/or reservoir water) from a wellbore that traverses a hydrocarbon bearing subterranean formation.
  • reservoir fluids such as oil, gas and possibly connate water and/or reservoir water
  • the production tubing can be set across the open wellbore to carry reservoir fluids produced from the formation to the surface.
  • a production casing string (sections of steel pipe cemented in place) can be set across an interval of wellbore and perforated to allow communication between the formation and the wellbore.
  • the production casing performs several functions, including supporting the surrounding formation under production conditions, enabling control of fluid production through selective perforation(s) and allowing subsequent or remedial isolation by packers, plugs or special treatments.
  • the production tubing can be set across the production casing to carry reservoir fluids produced from the formation to the surface.
  • Completions can also employ a perforated liner, which is a wellbore tubular having slots or holes. The production tubing can be set across the perforated liner to carry reservoir fluids produced from the formation to the surface.
  • the supporting equipment can include isolation members or packers for zonal isolation, systems such as mechanical filtering elements (e.g., screens) and/or gravel pack outside of perforated pipe for sand control, automated measurement and control devices (an "intelligent" completion), and other suitable equipment.
  • isolation members or packers for zonal isolation systems such as mechanical filtering elements (e.g., screens) and/or gravel pack outside of perforated pipe for sand control, automated measurement and control devices (an "intelligent" completion), and other suitable equipment.
  • FIG. 1 shows a horizontal wellbore 100 drilled such that it extends through a hydrocarbon bearing subterranean formation 102.
  • the wellbore 100 includes a substantially vertical wellbore portion that extends from a surface location S to a substantially horizontal wellbore portion that intersects the formation 102.
  • the formation 102 contains reservoir fluids such as oil and/or natural gas and possibly other hydrocarbon containing fluids.
  • the reservoir fluids can also include other fluids, such as connate water and/or formation water.
  • the reservoir fluids can include other fluids that are injected into the formation 102 to promote production.
  • one or more nearby wellbores can be equipped to permit injection of water or chemicals or gas into the formation 102 to promote production for enhanced oil recovery (EOR).
  • EOR enhanced oil recovery
  • the wellbore 100 can have another orientation, such as entirely substantially vertical, or deviated to less than horizontal.
  • the surface location S includes a wellhead 104 that connects to a production tubing string 106 that is part of the completion of the wellbore 100.
  • the wellhead 104 is accessible by operators for monitoring and controlling equipment installed within wellbore 100.
  • the surface location S can be on land for onshore wells or on a sea-bed for offshore wells.
  • the completion of the wellbore 100 includes isolation members, for example, three shown as 108 A, 108B, 108C for purposes of description. The isolation members are operable to isolate adjacent zones of the wellbore 100 from one another.
  • the isolation members 108 A, 108B, 108C can be swellable packers that extend around the exterior of production tubing 106 and engage the annular wall of wellbore 100.
  • the isolation members 108 A, 108B, 108C serve to isolate adjacent zones of the wellbore 100 from one another such that the reservoir fluids originating from the formation 102 adjacent respective zones of the wellbore 100 can flow into the respective wellbore zones for production.
  • the reservoir fluids that flow into the respective zones are referred to herein as produced fluids.
  • a plurality of downhole tools (for example, two shown as 120 A and 120B and referred to collectively as 120) are installed along the lower end of the production tubing 106 between respective isolation members.
  • the downhole tools 120 are located within corresponding wellbore zones and operate to control the inflow of the produced fluids within the corresponding wellbore zones into the production tubing 106 that extends to the surface location S.
  • downhole tool 120A is installed between isolation members 108 A and 108B and operates to control the inflow of the produced fluids within the corresponding wellbore zone between the isolation members 108 A and 108B into the production tubing 106 that extends to the surface location S
  • downhole tool 120B is installed between isolation members 108B and 108C and operates to control the inflow of the produced fluids within the corresponding wellbore zone between the isolation members 108B and 108C into the production tubing 106 that extends to the surface location S.
  • Each one of the downhole tools 120 includes a flow control unit with one or more apertures or holes that leads to a flowline which has an outlet that leads to the production tubing 106 (or production conduit) which extends to the surface location S.
  • the flow control unit also includes measurement devices and a control valve. The measurement devices operate to provide measurements that can be used to characterize the produced fluids that flows through the flowline of the flow control unit, such as flow rate or fluid composition or component fractions.
  • the results of such measurements can be used by a processor or controller to activate and/or adjust the control valve as needed in order to regulate the flow of the produced fluids through the flowline of the flow control unit.
  • the processor can be located remotely from the flow control unit (such as at the surface location S) and operably coupled to the flow control unit by one or more control lines.
  • the control lines can be integrated as part of the production tubing 106 or installed on the exterior of the production tubing 106.
  • the control lines can include electric lines that carry electrical power from the surface location S to the flow control unit and/or communicate data (such as commands and measurement data) between the surface location S and the flow control unit.
  • the control valve can be electrically-controlled, and the electric lines can be used to control the electrically-controlled control valve.
  • control valve can be hydraulically-controlled, and the control lines can include hydraulic lines that are used to control the hydraulically-controlled control valve.
  • the control lines can also include one or more fiber optic cables for data communication between the processor and the flow control unit.
  • wireless data communication technology can be used for data communication between the processor and the flow control unit.
  • the processor can possibly be located downhole in the wellbore 100, for example as part of the flow control unit itself.
  • the measurement devices of the flow control unit of each downhole tool can include an Electromagnetic Acoustic Transducer (EMAT) device that is configured to perform measurements that are used to characterize water-cut of the produced fluid that flows through the flowline of the flow control unit of the downhole tool.
  • EMAT Electromagnetic Acoustic Transducer
  • water-cut is the ratio of the volume of water in the produced fluid relative to the volume of total liquids in the produced fluid.
  • the EMAT device can employ a coil that surrounds the exterior surface of the annular wall of a metal pipe that forms the flowline (or portion thereof) of the flow control unit.
  • the coil can be configured to carry an AC current at a frequency f such that eddy currents are induced in the near surface region of the conductive material of the metal pipe wall.
  • a static magnetic field provided by a DC magnet
  • the eddy currents experience Lorentz forces causing the metallic pipe wall to move in a direction perpendicular to the DC magnetic field.
  • the motion of eddy currents also vibrates at the same frequency.
  • the vibrating pipe wall acts as an acoustic transducer launching acoustic waves along a length of the pipe as well as in the fluid flowing inside the pipe.
  • both the pipe wall and the fluid oscillate at the acoustic frequency.
  • the acoustic frequency can be chosen to be in the ultrasonic range for a smaller size pipe.
  • the combination of the coil (source of the time-varying electromagnetic field E) and DC magnet (source of the static magnetic field M) generates acoustic waves along the length of pipe that is part of the flowline of the flow control unit.
  • This combination is a transducer called an EMAT.
  • the EMAT can also operate as a receiver capable of receiving acoustic waves that have interacted with the produced fluids flowing in the flowline and return back to the location of the receiver EMAT generating an acoustic response signal (electrical signal) representative of the received acoustic waves.
  • the EMAT device of the present disclosure can include one or more EMATs (i.e., one or more coil and DC magnet combinations) that function as an acoustic transmitter or as an acoustic receiver, or both.
  • EMATs i.e., one or more coil and DC magnet combinations
  • the interaction of the acoustic waves with the produced fluids flowing in the flowline results in certain characteristics of the propagating acoustic waves (including amplitude and velocity) encoding information about the nature and the composition of the produced fluids flowing in the flowline.
  • the composition of the fluid affects the speed of the wave propagation as the compressibility of oil, water, and gas are different.
  • the EMAT device can measure and record the acoustic response signal that results from the interaction of acoustic waves with the produced fluids flowing in the flowline.
  • the acoustic response signal can encode useful information (such as sound velocity and wave attenuation) that can be related to elastic properties that characterize the composition of the fluid.
  • useful information such as sound velocity and wave attenuation
  • a calibration curve can be measured by having known compositions of the fluid in the flowline (or similar flowline) and measuring the acoustic response signal. Any unknown mixture causes a particular acoustic response signal that can be converted to data characterizing the composition of the fluid using the calibration curve.
  • FIG. 2 An embodiment of the downhole tool 120 is shown in FIG. 2, which includes a housing 121 that supports or accommodates a flow control unit 130.
  • the housing 121 includes opposed ends with connections (not shown) to the production tubing 106.
  • connections can be realized by threaded pipe-to-pipe interfaces or fittings as is well known.
  • the flow control unit 130 includes an aperture or center hole 125 that acts as a conduit for produced fluid.
  • the center hole 125 is in line with the remainder of completion.
  • the center hole 125 leads to a flowline 131 which has an outlet that leads to the production tubing 106 (or production conduit) which extends to the surface location S.
  • the production tubing 106 or production conduit
  • the flow control unit 130 also includes measurement devices (not shown) and a control valve. The measurement devices operate to provide measurements that can be used to characterize the produced fluids that flows through the flowline 131, such as flow rate or fluid composition or component fractions.
  • the results of such measurements can be used by a processor or controller (not shown) to activate and/or adjust the control valve as needed in order to regulate the flow of the produced fluids through the flowline 131.
  • the processor or controller can be located remotely from the flow control unit 130 (such as at the surface location S) and operably coupled to the flow control unit 130 by one or more control lines. In other embodiments, the processor or controller can possibly be located at a downhole location in the wellbore, such as part of the flow control unit 130 itself.
  • a flow control unit 130 is shown in FIG. 3.
  • the direction of the flow of produced fluid in the flowline 131 is from right to left.
  • the flow of produced fluid enters the end 270 of the flowline 121 and is directed to a sensor for measuring flow speed, such as a venture 220.
  • the diameter of the flowline 131 is reduced in the venture 220, forcing a larger volume of fluid to rush through the restriction which causes fluid pressure to change.
  • Pressure sensors 210, 230, and 240 measure pressure along the venture 220 and provide information about the flow rate as is well known in the art. Since the produced fluid is almost always a multi-phase flow (water, oil, and perhaps gas), a measurement of the quantity of one of these fluids, usually water, is needed.
  • the flow control unit 130 includes a water-cut measuring unit 250 that is configured for this purpose.
  • the net result of these measurements up to this point is the water content and fluid flow rate.
  • This information constitutes an input parameter that can be used to decide whether to control or regulate the flow rate or in some cases, where the fraction of water is high enough to make the fluid uneconomical, to completely stop the flow of produced fluid through the flowline 131 and into the production tubing 106.
  • the flow control can be achieved by the valve 260.
  • the water-cut measurement unit 250 provides important information for making the proper production decision. Different measurement techniques have been used for measuring water-cut. These include, for example, a capacitive sensor, which works well for oil to water ratios of 0-30%, when the fluid is oil continuous. Above this ratio the mixture becomes water continuous, leading to finite DC conductivity that interferes with the capacitive measurement.
  • the water-cut measurement unit 250 employs an EMAT device for measuring water-cut of the produced fluids that flow through the flowline 131.
  • FIG. 4A shows the components of an EMAT device.
  • a conductive plate 310 is positioned in contact with a current carrying coil 320.
  • the current in coil 320 induces an eddy current 360 in the conductive plate 310 close to the interface with the coil 320.
  • the current in the coil 320 is equivalent to a magnetic dipole 340.
  • the EMAT device also includes a magnet 330 that induces a static magnetic field similar to 350. Noting that the dipoles 320 and 340 are perpendicular to each other, following Lorentz force law they cause the conductive material to move in a direction perpendicular to both 320 and 340; i.e., in the direction in and out of the plane of FIG. 4A.
  • This material movement will be oscillatory since the current in the coil 320 is AC.
  • the frequency of this oscillation is the same as the frequency of the AC current used to excite the coil 320.
  • the device is capable of generating ultrasonic acoustic waves.
  • the oscillation causes an electric current to be induced in the coil 320.
  • the intensity of the induced current is proportional to the amplitude of the oscillations and its frequency is the same as the frequency of oscillations.
  • an EMAT device can be part of the water-cut measurement unit 250 of the flow control unit 130.
  • the EMAT device can be configured to emit and/or receive acoustic waves that propagate inside a pipe that is part of the flowline 131 of the flow control unit 130.
  • An embodiment of one such EMAT device is shown in FIG. 4B.
  • the pipe 410 is made of a suitable conductive material and has a wall thickness to support the fluid pressure.
  • a series of coils 420 are placed on the outside wall of the pipe spanning around the pipe. The number of coils 420 can be varied to control the magnitude of the acoustic waves that can be generated.
  • Each coil produces an oscillating electromagnetic dipole 460 that is perpendicular to the surface of the pipe 410.
  • Each DC magnet 430 produces a static magnetic field 440 that is perpendicular to the oscillating magnetic dipole 460. This arrangement causes the material in the pipe wall to oscillate in direction 450 and launch an acoustic wave that propagates along the length of the pipe 410.
  • the DC magnets 430 can be designed to have a ring shape and are capable of producing the static magnetic field along the circumference of the pipe.
  • the coils 420 can be replaced with a single coil wound around the circumference of the pipe wall.
  • any combinations of the two that lead to magnetic fields that Eire perpendicular to each other and can cause the pipe wall to oscillate and generate an acoustic wave are possible.
  • the acoustic wave is in the pipe direction. However, other directions are also possible and can serve to measure the flow composition.
  • FIG. 5 shows a portion 550 of an embodiment of the water-cut measurement unit 250 wherein two sets of EMAT coil/magnet combinations 520 and 530 are placed around the pipe 410 and spatially separated by a distance d.
  • EMAT coil/magnet combination 520 for example, can be used to generate the EMAT signal (acoustic waves) that propagate in the pipe 410 and EMAT coil/magnet combination 530 can be used to receive the EMAT response signal (acoustic response signal) that results from the propagating acoustic waves interacting with the flow of produced fluid in the pipe 410 as part of the flowline 131.
  • EMAT coil/magnet combination 520 for example, can be used to generate the EMAT signal (acoustic waves) that propagate in the pipe 410 and EMAT coil/magnet combination 530 can be used to receive the EMAT response signal (acoustic response signal) that results from the propagating acoustic waves interacting with the flow of produced fluid in the pipe 410 as part of the flowline 131
  • the frequency at which the EMAT coil/magnet combinations 520, 530 operate can be selected based on the diameter of the pipe 410. For example, if the pipe 410/flowline 131 has a pipe diameter of about a few centimeters, the acoustic frequency can be set high enough (ultrasonic) so that the pipe diameter and the acoustic wavelength are comparable. The acoustic frequency is also related to the distance d. This distance d can be chosen to be larger as the wavelength becomes longer. [0035] In another embodiment, the transmitter and the receiver EMAT coil/magnet combinations 520, 530 can be disposed at substantially the same location along the length of the housing.
  • Two or more rows of acoustic devices can be disposed radially with respect to the axis of the housing, wherein the acoustic devices include at least one magnetic coupling transmitter and at least one receiver.
  • these rows can be staggered or can be substantially helically arranged.
  • any magnet/coil pair may serve as both a transmitter and a receiver at different times during the data acquisition or measurement process.
  • the acoustic waves can be detected at some suitable distance ( d) from the source 520 using the same arrangement of coil 530 leading to an EMAT response signal (acoustic response signal).
  • the coil 530 can be used to measure and record the EMAT response signal that results from the interaction of the acoustic waves with the produced fluids flowing in the pipe 410.
  • the EMAT response signal can encode useful information (such as sound velocity and wave attenuation) that can be related to elastic properties that characterize the composition of the fluid.
  • a calibration curve can be measured by having known compositions of the fluid in the pipe 410 (or similar pipe) and measuring the EMAT response signal. Any unknown mixture causes a particular EMAT response signal that can be converted to data that characterizes the composition of the fluid using the calibration curve.
  • a calibration curve can be measured for compositions of known water-cut in the pipe 410 (or similar pipe), and such calibration curve can be used to translate the EMAT response signal (which results from interaction of the acoustic waves with the produced fluids flowing in the pipe 410) to a measure water-cut of the produced fluid that flows through the pipe 410 that is part of the flowline 131 of the flow control unit 130.
  • US Patents 3,850,028; 4,048,847; and 4,127,035 provide information about EMAT devices.
  • US Patent 4296486 discloses other EMAT design configurations and points out the fact that EMAT sensors are non-contact.
  • Non-contact sensors are ideal, especially for fluid flow applications since if the sensor comes in contact with the fluid, even if it is not intrusive, it changes the nature of the pipe wall which in turn changes the surface friction between the fluid and the wall.
  • the surface friction is an important parameter in multiphase flow and its variation can change the flow mode (laminar, chum, etc.) which in turn can change the very flow rate that one is trying to measure.
  • FIG. 6 is a functional block diagram illustrating components of the flow control unit 130 of FIG. 3 as well as a processor/actuator 601 that interfaces thereto.
  • the flow control unit 130 includes pressure sensors 210, 230, 240 as well as an EMAT device as part of the water-cut measurement unit 250.
  • the pressure sensors 210, 230, 240 as well as the EMAT device operate to provide measurements that can be used to characterize the produced fluids that flows through the flowline 131 of the flow control unit 130, such as flow rate or fluid composition or component fractions including water-cut.
  • the pressure sensors 210, 230, 240 and the EMAT device interface to the processor/actuator 610 by a communication system that carries data representing such measurements from the flow control unit 130 to the processor/actuator 601.
  • the processor/actuator 610 can process such data to characterize the produced fluids that flows through the flowline 131 of the flow control unit 130, such as characterize the flow rate or fluid composition or component fractions including water-cut.
  • the processor/actuator 601 can evaluate the results of such fluid characterization (such as flow rate or fluid composition or component fractions including water-cut) and use the results of such evaluation as one or more input parameters for activating and/or adjusting the control valve 260 of the flow control unit 130 as needed in order to regulate the flow of the produced fluids through the flowline 131 of the flow control unit 130.
  • the results of such fluid characterization can be used to control the valve 260 to completely stop the flow of produced fluid through the flowline 131 and into the production tubing 106.
  • the processor/actuator 601 can be located remotely from the flow control unit 130 (such as at the surface location S in FIG. 1) and operably coupled to the flow control unit 130 by one or more control lines that provide for control and actuation of the control valve 260.
  • the control lines can be integrated as part of the production tubing 106 or installed on the exterior of the production tubing 106.
  • the control lines can include electric lines that carry electrical power from the surface location S to the flow control unit 130 and/or communicate data (such as commands and measurement data) between the surface location S and the flow control unit 130.
  • the control valve 260 can be electrically-controlled, and the electric lines can be used to control and actuate the electrically-controlled control valve.
  • control valve 260 can also be hydraulically-controlled, and the control lines can include hydraulic lines that are used to control and actuate the hydraulically-controlled control valve.
  • the control lines can also include one or more fiber optic cables for data communication between the processor/actuator 601 and the flow control unit 130.
  • wireless data communication technology can be used for data communication between the processor/actuator 601 and the flow control unit 130.
  • the processor/actuator 601 can interface to a plurality of flow control units 130 of the respective downhole tool for controlling the control valves of the respective flow control units based on the input provided by the respective flow control units.
  • the processor/actuator 601 can possibly be located downhole, for example as part of the flow control unit 130 itself. In this configuration, separate processor/actuators 601 can be provided as part of the respective downhole tools.
  • FIG. 7 is a flowchart illustrating exemplary operations of the components of FIG. 6.
  • the operations begin in block 701 where the processor/actuator 601 controls the EMAT device 250 to generate ultrasonic waves that propagate in the flowline 131 of the flow control unit 130 and interact with produced fluid flowing in the flowline 131, and to receive ultrasonic waves after interaction with the produced fluid flowing in the flowline 131 and generate an EMAT response signal (electrical acoustic response signal) representative of the received ultrasonic waves.
  • EMAT response signal electrical acoustic response signal
  • the processor/actuator 601 receives and processes the EMAT response signal generated by the EMAT device 250 to generate data characterizing composition (water- cut) of the produced fluid flowing in the flowline 131 of the flow control unit 130. Details of such processing are set forth above.
  • the processor/actuator 601 evaluates the data of block 703 to determine whether the composition of the produced fluid flowing in the flowline 131 of the flow control unit 130 exceeds a water-cut threshold.
  • the water-cut threshold can correspond to the case where the produced fluid is uneconomical.
  • the processor/actuator 601 checks whether the evaluation of block 705 determines that the composition of the produced fluid flowing in the flowline 131 of the flow control unit 130 exceeds the water-cut threshold (e.g., which can correspond to the case where the produced fluid is uneconomical). If so, the operations continue to block 709. Otherwise, the operations end.
  • the water-cut threshold e.g., which can correspond to the case where the produced fluid is uneconomical
  • the processor/actuator 601 can control and actuate the valve 260 of the flow control unit 130 to block the flow of produced fluid through the flowline 131 of the flow control unit 131.
  • the processor/actuator 601 can selectively control and actuate the valve 260 of the flow control unit 130 to block the flow of produced fluid through the flowline 131 of the flow control unit 131 in the event that the water-cut of the produced fluid flowing in the flowline 131 of the flow control unit 130 exceeds the water-cut threshold (e.g., which can correspond to the case where the produced fluid is uneconomical).
  • processors or controllers can be performed by a processor or controller.
  • the term “processor” or “controller” should not be construed to limit the embodiments disclosed herein to any particular device type or system.
  • the processor or controller may include a computer system.
  • the computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general-purpose computer) for executing any of the methods and processes described above.
  • the computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD- ROM), a PC card (e.g., PCMCIA card), or other memory device.
  • a semiconductor memory device e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM
  • a magnetic memory device e.g., a diskette or fixed disk
  • an optical memory device e.g., a CD- ROM
  • PC card e.g., PCMCIA card
  • the computer program logic may be embodied in various forms, including a source code form or a computer executable form.
  • Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as C, C++, or JAVA).
  • Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor.
  • the computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).
  • a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).
  • a communication system e.g., the Internet or World Wide Web
  • the processor may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)). Any of the methods and processes described above can be implemented using such logic devices.
  • ASIC Application Specific Integrated Circuits
  • FPGA Field Programmable Gate Arrays
  • FIG. 8 illustrates an example device 2500, with a processor 2502 and memory 2504 that can be configured to implement various parts of the operations discussed in this disclosure, such as the operations carried out by the processor/actuator that interfaces to the respective flow control units of the downhole tools.
  • Memory 2504 can also host one or more databases and can include one or more forms of volatile data storage media such as random-access memory (RAM), and/or one or more forms of nonvolatile storage media (such as read-only memory (ROM), flash memory, and so forth).
  • RAM random-access memory
  • ROM read-only memory
  • flash memory and so forth.
  • Device 2500 is one example of a computing device or programmable device and is not intended to suggest any limitation as to scope of use or functionality of device 2500 and/or its possible architectures.
  • device 2500 can comprise one or more computing devices, programmable logic controllers (PLCs), etc.
  • PLCs programmable logic controllers
  • device 2500 should not be interpreted as having any dependency relating to one or a combination of components illustrated in device 2500.
  • device 2500 may include one or more of computers, such as a laptop computer, a desktop computer, a mainframe computer, etc., or any combination or accumulation thereof.
  • Device 2500 can also include a bus 2508 configured to allow various components and devices, such as processors 2502, memory 2504, and local data storage 2510, among other components, to communicate with each other.
  • bus 2508 configured to allow various components and devices, such as processors 2502, memory 2504, and local data storage 2510, among other components, to communicate with each other.
  • Bus 2508 can include one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. Bus 2508 can also include wired and/or wireless buses.
  • Local data storage 2510 can include fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a flash memory drive, a removable hard drive, optical disks, magnetic disks, and so forth).
  • fixed media e.g., RAM, ROM, a fixed hard drive, etc.
  • removable media e.g., a flash memory drive, a removable hard drive, optical disks, magnetic disks, and so forth.
  • One or more input/output (I/O) device(s) 2512 may also communicate via a user interface (UI) controller 2514, which may connect with I/O device(s) 2512 either directly or through bus 2508.
  • UI user interface
  • a network interface 2516 may communicate outside of device 2500 via a connected network.
  • a media drive/interface 2518 can accept removable tangible media 2520, such as flash drives, optical disks, removable hard drives, software products, etc.
  • removable tangible media 2520 such as flash drives, optical disks, removable hard drives, software products, etc.
  • logic, computing instructions, and/or software programs comprising elements of module 2506 may reside on removable media 2520 readable by media drive/interface 2518.
  • input/output device(s) 2512 can allow a user to enter commands and information to device 2500 and allow information to be presented to the user and/or other components or devices.
  • Examples of input device(s) 2512 include, for example, sensors, a keyboard, a cursor control device (e.g., a mouse), a microphone, a scanner, and any other input devices known in the art.
  • Examples of output devices include a display device (e.g., a monitor or projector), speakers, a printer, a network card, and so on.
  • Computer-readable media can be any available data storage medium or media that is tangible and can be accessed by a computing device. Computer readable media may thus comprise computer storage media. “Computer storage media” designates tangible media, and includes volatile and non-volatile, removable and non-removable tangible media implemented for storage of information such as computer readable instructions, data structures, program modules, or other data.
  • Computer memory includes, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, computer storage media or any other tangible medium which can be used to store the desired information and data structures of the methods and workflows as described herein, and which can be accessed by a computer executing the operations of the methods and workflows as described herein.

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

Abstract

L'invention concerne un outil de fond de trou qui est placé fonctionnellement dans un puits de forage et sert à réguler l'écoulement d'un fluide dans le puits de forage. L'outil de fond de trou peut comprendre un logement qui comprend une conduite d'écoulement, une vanne pouvant être actionnée pour réguler l'écoulement de fluides produits dans la conduite d'écoulement, et un dispositif EMAT supporté par le logement. Le dispositif EMAT peut servir à effectuer des mesures utilisées pour caractériser la proportion d'eau de fluides produits qui s'écoulent dans la conduite d'écoulement en vue d'une commande sélective de la vanne.
PCT/US2019/044892 2019-08-02 2019-08-02 Outil de fond de trou qui surveille et commande la venue d'un fluide produit sur la base de mesures de composition de fluide utilisant un dispositif de transducteur acoustique électromagnétique (emat) WO2021025667A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
PCT/US2019/044892 WO2021025667A1 (fr) 2019-08-02 2019-08-02 Outil de fond de trou qui surveille et commande la venue d'un fluide produit sur la base de mesures de composition de fluide utilisant un dispositif de transducteur acoustique électromagnétique (emat)

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2019/044892 WO2021025667A1 (fr) 2019-08-02 2019-08-02 Outil de fond de trou qui surveille et commande la venue d'un fluide produit sur la base de mesures de composition de fluide utilisant un dispositif de transducteur acoustique électromagnétique (emat)

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Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US11746627B1 (en) 2022-05-20 2023-09-05 Halliburton Energy Services, Inc. Downhole flow sensing with power harvesting and flow control
US11905800B2 (en) 2022-05-20 2024-02-20 Halliburton Energy Services, Inc. Downhole flow sensing with power harvesting

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5283768A (en) * 1991-06-14 1994-02-01 Baker Hughes Incorporated Borehole liquid acoustic wave transducer
WO1997005469A2 (fr) * 1995-07-27 1997-02-13 The Babcock & Wilcox Company Transducteur electromagnetique acoustique (emat) pour l'inspection par ultra-sons de liquides dans des recipients
US20090084185A1 (en) * 2007-09-27 2009-04-02 Baker Hughes Incorporated Electromagnetic acoustic transducer with cross-talk elimination
US20180058209A1 (en) * 2016-08-30 2018-03-01 Limin Song Downhole Multiphase Flow Sensing Methods
US20180100387A1 (en) * 2016-10-07 2018-04-12 Baker Hughes Incorporated Downhole electromagnetic acoustic transducer sensors

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5283768A (en) * 1991-06-14 1994-02-01 Baker Hughes Incorporated Borehole liquid acoustic wave transducer
WO1997005469A2 (fr) * 1995-07-27 1997-02-13 The Babcock & Wilcox Company Transducteur electromagnetique acoustique (emat) pour l'inspection par ultra-sons de liquides dans des recipients
US20090084185A1 (en) * 2007-09-27 2009-04-02 Baker Hughes Incorporated Electromagnetic acoustic transducer with cross-talk elimination
US20180058209A1 (en) * 2016-08-30 2018-03-01 Limin Song Downhole Multiphase Flow Sensing Methods
US20180100387A1 (en) * 2016-10-07 2018-04-12 Baker Hughes Incorporated Downhole electromagnetic acoustic transducer sensors

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US11746627B1 (en) 2022-05-20 2023-09-05 Halliburton Energy Services, Inc. Downhole flow sensing with power harvesting and flow control
WO2023224639A1 (fr) * 2022-05-20 2023-11-23 Halliburton Energy Services, Inc Détection d'écoulement de fond de trou avec collecte d'énergie et régulation d'écoulement
US11905800B2 (en) 2022-05-20 2024-02-20 Halliburton Energy Services, Inc. Downhole flow sensing with power harvesting

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