WO2014116427A1 - Transducteurs acoustiques optiques de fond de trou - Google Patents

Transducteurs acoustiques optiques de fond de trou Download PDF

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Publication number
WO2014116427A1
WO2014116427A1 PCT/US2014/010717 US2014010717W WO2014116427A1 WO 2014116427 A1 WO2014116427 A1 WO 2014116427A1 US 2014010717 W US2014010717 W US 2014010717W WO 2014116427 A1 WO2014116427 A1 WO 2014116427A1
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WO
WIPO (PCT)
Prior art keywords
optical
energy
transducer
acoustic
well
Prior art date
Application number
PCT/US2014/010717
Other languages
English (en)
Inventor
Neal G. Skinner
Etienne M. Samson
Jr. John L. MAIDA
Christopher L. STOKELY
David A. Barfoot
Original Assignee
Halliburton Energy Services, Inc.
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 Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to AU2014209780A priority Critical patent/AU2014209780A1/en
Priority to CA2896109A priority patent/CA2896109A1/fr
Priority to MX2015007546A priority patent/MX2015007546A/es
Priority to EP14742955.9A priority patent/EP2948626A4/fr
Publication of WO2014116427A1 publication Critical patent/WO2014116427A1/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
    • E21B47/12—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
    • E21B47/14—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 using acoustic waves
    • 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
    • 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
    • G01H9/004—Measuring mechanical vibrations or ultrasonic, sonic or infrasonic waves by using radiation-sensitive means, e.g. optical means using fibre optic sensors
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/22—Transmitting seismic signals to recording or processing apparatus
    • G01V1/226—Optoseismic systems
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01D—MEASURING NOT SPECIALLY ADAPTED FOR A SPECIFIC VARIABLE; ARRANGEMENTS FOR MEASURING TWO OR MORE VARIABLES NOT COVERED IN A SINGLE OTHER SUBCLASS; TARIFF METERING APPARATUS; MEASURING OR TESTING NOT OTHERWISE PROVIDED FOR
    • G01D5/00—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable
    • G01D5/48—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable using wave or particle radiation means
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/10—Aspects of acoustic signal generation or detection
    • G01V2210/14—Signal detection
    • G01V2210/142—Receiver location
    • G01V2210/1429—Subsurface, e.g. in borehole or below weathering layer or mud line

Definitions

  • This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in examples described below, more particularly provides downhole optical acoustic transducers and
  • Acoustic energy may be used for various purposes in a well.
  • a distributed acoustic sensing (DAS) system can be used to "listen” to acoustic signals in a well.
  • DAS distributed acoustic sensing
  • FIG. 1 is a representative partially cross-sectional view of a well system and associated method which can embody principles of this disclosure.
  • FIG. 2 is a representative partially cross-sectional view of the system and method, wherein a well logging assembly is displaced in a wellbore by a conveyance.
  • FIGS. 3-11 are representative schematic views of an optical acoustic transducer which may be used in the system and method of FIGS. 1 & 2, and which can embody the
  • FIG. 12 is a representative partially cross-sectional view of another example of the system and method.
  • FIG. 13 is a representative schematic view of another optical acoustic transducer which may be used in the system and method, and which can embody the principles of this disclosure .
  • FIGS. 14 & 15 are representative view of photodiode arrangements which may be used in the system and method.
  • FIG. 1 Representatively illustrated in FIG. 1 is a system 10 for use with a well, and an associated method, which system and method can embody principles of this disclosure.
  • a well logging assembly 12 is conveyed into a wellbore 14 by a conveyance 16.
  • the wellbore 14 is lined with casing 18 and cement 20. Perforations 22 formed through the casing 18 and cement 20 allow fluid 24a, b to flow into the wellbore 14 from respective formation zones 26a,b penetrated by the wellbore.
  • the well logging assembly 12 may include conventional logging tools, such as, a casing collar locator 28, a gamma ray tool 30 and sensors 32 (for example, a pressure sensor and a temperature sensor) .
  • the well logging assembly 12 includes a signal generator 34 for generating one or more acoustic signals 36a in the well.
  • the signals 36a could be generated by striking the conveyance 16, casing 18 or other structure.
  • a mechanism could, for example, deliver a hammer impact driven by differential pressure, an electromagnetic solenoid, or other mechanical actuator.
  • the signals 36a could be generated by detonating a series of explosive or other exothermic devices in the well.
  • the scope of this disclosure is not limited to any particular manner of generating the signals 36a.
  • the signals 36a are preferably reflected in the well, for example, at a fluid/air or fluid/metal interface or any interface in the well with an abrupt change in acoustic impedance. Reflected signals 36b travel in the wellbore 14 in a direction opposite to that of the signals 36a generated by the signal generator 34.
  • FIG. 1 depicts the signals 36a travelling upwardly from the signal generator 34, and the reflected signals 36b travelling downwardly in the wellbore 14.
  • the signals 36a would travel in both directions through the wellbore 14 from the signal generator 34, and the reflected signals 36b also travel in both directions, and can be reflected from any surface or other impedance change.
  • Acoustic signals 36a can be generated, for example, by impacting one component against another, by energizing one or more piezoelectric elements, etc.
  • the scope of this disclosure is not limited to any particular way of
  • the conveyance 16 is used to convey the well logging assembly 12 into the well.
  • the conveyance 16 also includes a component of the assembly 12, in the form of an optical waveguide 38 (such as, a single and/or multi-mode optical fiber or optical ribbon) .
  • optical waveguide 38 Although only one optical waveguide 38 is depicted in FIG. 1, any number of optical waveguides may be used, as desired.
  • conveyance 16 could include various other types of lines, such as, electrical conductors and fluid conduits. The scope of this disclosure is not limited to any particular number, combination, configuration or arrangement of lines in the conveyance 16.
  • the conveyance 16 may be in the form of a cable with suitable strength, temperature resistance, chemical
  • the cable could comprise stranded cable or cable made from small diameter (e.g., 3 ⁇ 4 in. diameter) metal tubing or control line, with the optical waveguide 38 inside the line.
  • the conveyance 16 could be in the form of a coiled tubing (e.g., a substantially continuous tubular string, typically stored on a reel), with the optical waveguide 38 positioned inside, in a wall of, and/or exterior to, the coiled tubing.
  • a coiled tubing e.g., a substantially continuous tubular string, typically stored on a reel
  • the scope of this disclosure is not limited to any particular form of the conveyance 16, or to any particular position of the optical waveguide 38 with respect to the conveyance.
  • the interrogator 40 is coupled to the optical waveguide 38.
  • the interrogator 40 includes a light source 42 (such as, an infrared laser) and an optical detector 44 (such as, a photodiode or other photo-detector).
  • the interrogator 40 is used to determine at least one parameter as distributed along the optical waveguide 38. This is accomplished by launching light from the source 42 into the optical waveguide 38 and detecting light
  • DAS distributed acoustic sensing
  • the distributed along the optical waveguide 38 can be measured by detecting coherent Rayleigh backscattering in the
  • reflections 36b can be effectively tracked as they travel along the waveguide 38 in the well.
  • an array of weak fiber Bragg gratings or other artificially introduced reflectors can be used with the optical waveguide 38 to detect acoustic signals along the waveguide.
  • Velocities of the signals 36a and their reflections 36b can be readily determined using the DAS interrogator 40, for example, by dividing displacement of the signals by elapsed time. Using this information, with the system 10 configured as depicted in FIG. 1, an acoustic velocity in the
  • commingled fluids 24a, b can be determined, as well as a velocity of the commingled fluids through the wellbore 14.
  • V w is the velocity of a signal traveling with the flow of fluid (in the FIG. 1 example, the generated signal 36a)
  • V 0 is the velocity of a signal traveling opposite the flow of fluid (in the FIG. 1 example, the reflected signal 36b)
  • V a is the acoustic velocity in the commingled fluids 24a, b
  • V f is the velocity of the fluids through the wellbore 14.
  • V a (V w + V 0 )/2 (3) and, thus, the acoustic velocity V a is simply the average of the velocities of the generated signal 36a and the reflected signal 36b in the FIG. 1 example.
  • V a (V w + V 0 )/2 (3)
  • Volumetric flow rate equals fluid velocity times cross-sectional area, so the flow rate of the fluids 24a, b can also be readily determined. If Equation 4 yields a negative number for the velocity V f , this is an indication that the fluid is flowing in an opposite direction to that assumed when applying values to the variables in Equations 1-4.
  • the principles of this disclosure are applicable no matter whether a fluid flows with or in an opposite direction to a signal 36a generated by the signal generator 34, and no matter whether a fluid flows with or in an opposite direction to a reflected signal 36b.
  • the interrogator 40 can be connected to a control system 46 (including, for example, a processor 48, memory 50, software, etc.) for controlling operation of the control system 46 (including, for example, a processor 48, memory 50, software, etc.) for controlling operation of the control system 46 (including, for example, a processor 48, memory 50, software, etc.) for controlling operation of the control system 46 (including, for example, a processor 48, memory 50, software, etc.) for controlling operation of the
  • the system 10 can be used to determine the flow rate of the commingled fluids 24a, b, as well as characteristics (e.g., pressure, temperature, acoustic velocity, etc.) of the commingled fluids in the wellbore 14.
  • characteristics e.g., pressure, temperature, acoustic velocity, etc.
  • flow rates of each of the fluids 24a, b can be readily determined. This is so, because the system 10 is capable of detecting the velocities of the signals 36a and their reflections 36b as distributed along the optical waveguide 38 in the wellbore 14.
  • reflections 36b will be the same and, according to Equation (3) above, will equal the acoustic velocity V a in the fluid present in that section of the wellbore.
  • the velocity of the fluid 24a and the acoustic velocity in that fluid can be readily determined.
  • the velocity of the commingled fluids and the acoustic velocity in those fluids can be readily determined, as described above. Knowing the volumetric flow rate from the lower set of perforations 22, and the combined flow rate of the fluids 24a, b, one can readily determine a contribution to flow from the upper set of perforations via subtraction .
  • the assembly 12 can simply be positioned so that the optical waveguide 38 traverses all of the sections of the wellbore 14 of interest, the signal generator 34 can be operated to produce the signals 36a (and, consequently, their reflections 36b), and the interrogator 40 can quickly be used to measure acoustic energy along the optical waveguide. This consumes much less time as compared to conventional well logging techniques and, thus, is much more economical in practice.
  • the acoustic velocity V a in a fluid composition depends on the fluids in the composition and the compliance of the pipe walls or conduit walls containing the fluid. Because the pipe walls or conduit walls are not infinitely stiff, the speed of sound in the system is reduced in a quantifiable way. (see Robert McKee and Eugene “Buddy” Broerman, "Acoustics in Pumping Systems", 25 th International Pump User Symposium (2009)).
  • the fluids in the composition (for example, an oil/water ratio) can be readily estimated.
  • the pipe In order to infer the composition of the fluid (oil, water, or the fractions of oil and water), the pipe
  • Pipe compliance is very important. Pipe compliance can reduce the speed of sound in the pipe by as little as few percent all the way up to 50 percent or more.
  • Pipe compliance of a steel pipe is caused by not having infinitely stiff walls. It causes the acoustic wave
  • FIGS. 3-8 illustrate various examples of how, in a downhole environment (e.g., in the well of FIG. 1, in another wellbore, etc.), optical energy can be converted to electrical energy, which can be stored and controllably released, to generate the acoustic signals 36a.
  • a downhole environment e.g., in the well of FIG. 1, in another wellbore, etc.
  • optical energy can be converted to electrical energy, which can be stored and controllably released, to generate the acoustic signals 36a.
  • electrical energy which can be stored and controllably released
  • the optical energy could be converted to thermal energy (e.g., by directing light transmitted via the optical waveguide 34 onto a black body, which is thereby heated, etc.), and the thermal energy could be used to generate the acoustic signals 36a (e.g., using a heat engine, such as a Stirling engine).
  • a heat engine such as a Stirling engine
  • FIG. 3 depicts a representative circuit diagram for the transducer 34 .
  • a photodiode 52 is connected to a step up transformer 54 .
  • the photodiode 52 is illuminated with pulsed light 56 carried downhole over the optical waveguide 38 .
  • incident light 56 is input into the transformer 54 , where it may be stepped up or merely isolated from the photodiode.
  • CI, C2, Dl and D2 make up a well-known alternating current to direct current (AC to DC) voltage doubler 58 .
  • DC voltage Vout across at an output of the voltage doubler 58 will be roughly twice an AC amplitude output from the transformer 54 . If higher voltage is required, the turns-ratio of the transformer 54 can be altered and/or additional stages of voltage doublers 58 may be used.
  • An oscillator 60 is connected to the voltage doubler 58 .
  • the oscillator 60 is used to produce a desired acoustic wave form (amplitude, frequency, etc.) from an electrical to acoustic transducer 62 .
  • the acoustic signals 36 are
  • a suitable electrical to acoustic transducer could comprise one or more piezoelectric elements, a solenoid which drives a mass to strike another structure, etc.
  • the scope of this disclosure is not limited to use of any particular type of electrical to acoustic transducer.
  • FIG. 4 another example of the optical to acoustic transducer 34 is depicted.
  • two voltage doublers 58 (effectively a voltage quadrupler) are used. Note that, if a sufficient number of voltage doublers 58 is used, the step up transformer 54 may not be required.
  • transformer 54 and the voltage doubler 58 are only two examples of voltage increasers 64 (see FIGS. 6- 9 ) which may be used to increase a voltage output by the photodiode 52.
  • the scope of this disclosure is not limited to use of any particular type of voltage increaser.
  • FIG. 5 depicts an example of the transducer 34 which provides security against accidental operation, and/or allows for multiplexing.
  • an optical filter 66 is
  • the filter 66 passes only a narrow range of wavelengths. Only when the specific range of wavelengths that match the pass band of the filter 66 are transmitted from the light source 42 will the circuit produce Vout.
  • the photodiode 52 may be selected so that it generates current only in response to a certain range of wavelengths.
  • the scope of this disclosure is not limited to any particular way of preventing the circuit from producing Vout when certain preselected wavelengths of light 56 are not transmitted.
  • FIG. 5 also depicts an additional capacitor, Cf in series with a primary winding of the transformer 54, forming an LC filter with resonance frequency equal to — radians/second where L is the effective inductance of the transformer. This filter prevents the flow of current into the transformer 54 when the pulses illuminating the
  • photodiode 52 are not at the resonant frequency.
  • Other types of electric filters and filter topologies may be used to determine a light 56 pulse repetition rate required to activate a particular electrical power converter.
  • wavelength division multiplexing and/or pulse frequency multiplexing can be added with only minor changes to the circuit.
  • the wavelength or pulse frequency selective circuits described here may serve as a safety feature. For example, if one desired to use optical power to trigger an explosive device in a well (such as, a perforating gun, a seismic charge, etc.), one could combine features described here, so that the device would not be detonated, unless light with a specified wavelength is modulated with a specified frequency for a specified time period via an optical fiber in the well .
  • pulsed optical power is
  • the electrical to acoustic transducer 62 could instead be operated with short, high power electrical pulses. In order to generate
  • the circuit can be modified as shown in FIG. 6.
  • a voltage increaser 64 is depicted as representing any type of voltage increaser.
  • Vout is the voltage across Cout, controlled by the output voltage of the photodiode 52, and the configuration of the voltage increaser 64.
  • the transducer 62 to be supplied with electrical power is connected across Cout through a gas discharge tube (GDT) 68, a device that acts as an open switch until it reaches a threshold voltage differential, at which time it acts as a closed switch, dumping the electrical energy stored in Cout to the transducer 62 (and optionally via the oscillator 60, as in the FIGS. 3-5 examples).
  • GDT gas discharge tube
  • the circuit depicted in FIG. 6 will rapidly deliver the electrical power stored in Cout to the transducer 62 whenever the voltage across the GDT 68 reaches its threshold.
  • the time to buildup a given threshold voltage across the GDT 68 will depend on the amplitude and frequency of the incident pulses of light 56, the size of capacitor Cout and internal leakage and efficiency of the circuit components. This can make timing of the delivery of electrical power through the GDT 68 to the transducer 62 difficult to predict.
  • the GDC 68 is replaced by, for example, a thyristor or SCR which are semiconductor devices which can be thought of as a
  • An SCR is a diode with an additional gate. When the current flows into the gate, the diode acts normally, conducting only in the forward biased direction, however, when current is not injected into the gate, the diode does not conduct in either direction.
  • a brief pulse of triggering light 72 illuminates a trigger photodiode 74.
  • the trigger photodiode 74 generates a brief pulse of current that causes the SCR (or switchable diode 70) to dump the energy stored in Cout to the transducer 62.
  • the operating characteristics of an SCR are such that, even if the trigger pulse light 72 is turned off, the SCR will conduct until all the energy stored in Cout is dumped to the transducer 62 (and optionally via the oscillator 60, as in the FIGS. 3-5 examples).
  • triggering light 72 can be controlled or filtered via similar optical and/or electrical filtering techniques described above for controlling when voltage is supplied to the transformer 54 from the photodiode 52.
  • the scope of this disclosure is not limited to any particular way of
  • the SCR is replaced by a three lead neon tube 76 which can be
  • the triggering photodiode 74 is connected such that its output is used to trigger a gas discharge through the neon tube 76, whereby electrical power is provided to the transducer 62 (and optionally via the oscillator 60, as in the FIGS. 3-5 examples).
  • FIG. 9 another example of the optical acoustic transducer 34 is representatively illustrated.
  • the light 56 illuminates an optical to electrical transducer 78.
  • Voltage produced by the transducer 78 is input to the voltage increaser 64.
  • Increased voltage from the voltage increaser 64 is input to the electrical to acoustic transducer 62 via the oscillator 60.
  • any of the trigger circuits depicted in FIGS. 6-8 may be used to control when energy stored in Cout is dumped to the transducer 62.
  • the optical to electrical transducer 78 may be any type of transducer capable of converting optical energy to electrical energy.
  • the photodiode 52 is one example of a suitable optical to electrical transducer 78.
  • the optical to electrical transducer 78 of FIG. 9 is replaced by an optical to heat transducer 80 and a thermal to electrical transducer 82. Voltage output by the transducer 82 is input to the voltage increaser 64.
  • the optical to thermal transducer 80 may be any type of transducer capable of converting optical energy to thermal energy.
  • the light 56 could illuminate a black body, thereby generating thermal energy.
  • the thermal to electrical transducer 82 may be any type of transducer capable of converting heat energy to
  • thermopile, thermocouple or other heat to electrical transducer 82 can receive the heat generated by the transducer 80 and convert that heat to electrical energy for input to the voltage increaser 64.
  • heat generated by the optical to thermal transducer 80 is input to a thermal to mechanical transducer 84.
  • Mechanical energy is input to a mechanical to acoustic transducer 86 to generate the signals 36.
  • the thermal to mechanical transducer 84 may be any type of transducer capable of converting heat energy to
  • the mechanical to acoustic transducer 86 may be any type of transducer capable of utilizing mechanical energy to generate the acoustic signals 36.
  • mechanical energy could be used to strike one component against another component and thereby generate stress waves in structures in the well, pressure pulses could be generated with pistons or membranes displaced via mechanical energy, etc.
  • the acoustic signals 36 could be generated by
  • the charges could be detonated electrically, for example, or they could be detonated by direct heating as a result of focusing laser energy from the optical waveguide onto an explosive, such as a detonator in close proximity to a main charge, etc.
  • the acoustic signals 36 could be generated by releasing compressed fluid, or by opening a series of low pressure chambers downhole.
  • optical to acoustic transducer 34 can be constructed in a variety of different configurations, and those configurations are not limited to the examples depicted in FIGS. 3-11. It should also be appreciated that a wide variety of different
  • FIGS. 1 & 2 example of the system 10.
  • FIG. 12 another example of the system 10 is
  • the tubular string 88 could be, for example, a production tubing string, a coiled tubing string, a completion string, a stimulation string, an injection string, a work string, a liner, etc.
  • the transducer 34 and/or waveguide 38 could be internal to, or positioned in a wall of, the tubular string 88 .
  • the transducer 34 and/or waveguide 38 could be internal to, external to, or positioned in a wall of the casing 18 , or in the cement 20 , etc.
  • the scope of this disclosure is not limited to any particular location of the transducer 34 and/or waveguide 38 .
  • the transducer 34 generates the signals 36 , which propagate in opposite directions away from the transducer.
  • the signals 36 can travel through various structures and fluids in the well.
  • the optical waveguide 38 can be used, as described above, to track the signals 36 , and thereby determine properties of fluid 24 in the well.
  • the scope of this disclosure is not limited to use of the optical
  • acoustic transducer 34 for determining properties of fluids.
  • transducer 34 may be located in any position with respect to the conveyance 16 or tubular string 88 in the above examples.
  • the transducer 34 could be at any location along the conveyance 16 or tubular string 88 , and multiple transducers can be spaced apart along the
  • the photodiode 52 is part of a photovoltaic converter 90 .
  • a suitable photovoltaic converter is available from JDSU (e.g., model PPC-XE) of Milpitas, California USA.
  • the voltage increaser 64 in this example can comprise a DC to DC converter.
  • a suitable DC to DC converter is
  • the electrical acoustic transducer 62 in this example can comprise a piezoelectric actuator.
  • a suitable piezoelectric actuator A suitable piezoelectric actuator.
  • piezoelectric actuator is available from MIDE Engineering (e.g., model QP20W) of Medford, Massachusetts USA.
  • a spark gap 92 may be used to control voltage across the transducer 62.
  • a 150v spark gap is
  • Bourns, Inc. e.g., model 652-2027-1S-SN-LF ) of Riverside, California USA.
  • FIGS. 14 & 15 techniques for increasing a voltage or current output of the photodiode 52 in the transducer 34 are representatively illustrated.
  • multiple photodiodes 52 are connected in series, in order to increase a voltage output
  • multiple photodiodes are connected in parallel, in order to increase a current output, to the voltage increaser 64.
  • An optical coupler 94 can be used to direct the light
  • photodiodes 52 each of the photodiodes 52 in the FIGS. 14 & 15 examples.
  • Any number or arrangement of photodiodes 52 may be used (e.g., singles, multiples, in series and/or in
  • an optical acoustic transducer 34 is used to convert optical energy to acoustic energy, for generating acoustic signals 36 in a well.
  • a method of generating an acoustic signal 36 in a subterranean well is provided to the art by the above disclosure. In one example, the method can comprise:
  • the downhole environment may include structures (such as casing 18, cement 20, tubular string 88, etc.) and/or fluids 24 in the well.
  • the converting step can include converting the optical energy to electrical energy downhole.
  • the converting step can further include illuminating an optical to electrical transducer 78 with light transmitted via an optical
  • the converting step can further include converting the electrical energy to the acoustic energy downhole.
  • the converting can also comprise converting the electrical energy to mechanical energy downhole (for example, a
  • solenoid striker or a motor could convert electrical to mechanical energy downhole).
  • the method may include storing the electrical energy downhole.
  • the method can further include triggering a release of the electrical energy downhole.
  • the converting step can include converting the optical energy to thermal energy downhole.
  • the converting step can further include converting the thermal energy to the
  • the converting can include converting the thermal energy to mechanical energy downhole.
  • the converting step can further include converting the mechanical energy to the acoustic energy downhole.
  • a well system 10 is also described above.
  • the system 10 can include an optical acoustic transducer 34 disposed in the well and coupled to an optical waveguide 38 in the well.
  • the transducer 34 converts optical energy transmitted via the optical waveguide 38 to acoustic energy.
  • the optical acoustic transducer 34 may comprise an optical electrical transducer 78 which converts the optical energy to electrical energy in the well.
  • electrical transducer 78 can be illuminated with light 56 transmitted via the optical waveguide 38 in the well.
  • the optical acoustic transducer 34 may comprise an electrical acoustic transducer 62 which converts the
  • the electrical transducer 78 may be stored in the well.
  • the optical acoustic transducer 34 can release the stored electrical energy in the well.
  • the optical acoustic transducer 34 may comprise an optical thermal transducer 80 which converts the optical energy to thermal energy in the well.
  • the optical acoustic transducer 34 may further comprise a thermal acoustic transducer which converts the thermal energy to the acoustic energy in the well.
  • the optical acoustic transducer 34 may comprise a thermal mechanical transducer 84 which converts the thermal energy to mechanical energy in the well.
  • acoustic transducer 34 may comprise a mechanical acoustic transducer 86 which converts the mechanical energy to the acoustic energy in the well.
  • the combined thermal mechanical transducer 84 and mechanical acoustic transducer 86 may be considered a thermal acoustic transducer.
  • the optical acoustic transducer 34 includes a means for converting optical energy transmitted via an optical
  • the converting means may comprise an optical electrical transducer 78 which converts the optical energy to
  • the optical electrical transducer 78 can be illuminated with light 56 transmitted via the optical waveguide 38 in the well.
  • the converting means may comprise an electrical
  • acoustic transducer 62 which converts the electrical energy to the acoustic energy in the well.
  • the electrical transducer 78 may be stored in the well.
  • the converting means can release the stored electrical energy in the well.
  • the converting means may comprise an optical thermal transducer 80 which converts the optical energy to thermal energy in the well.
  • the converting means may further comprise
  • thermo acoustic transducer which converts the thermal energy to the acoustic energy in the well.
  • the converting means may comprise a thermal mechanical transducer 84 which converts the thermal energy to
  • the converting means may comprise a mechanical acoustic transducer 86 which converts the mechanical energy to the acoustic energy in the well.
  • structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa.

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  • Remote Sensing (AREA)
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  • Mining & Mineral Resources (AREA)
  • Geophysics (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
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  • Acoustics & Sound (AREA)
  • Geochemistry & Mineralogy (AREA)
  • General Physics & Mathematics (AREA)
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  • Geophysics And Detection Of Objects (AREA)

Abstract

Selon la présente invention, un procédé de génération d'un signal acoustique dans un puits souterrain peut comprendre la conversion d'une énergie optique en énergie acoustique en fond de trou, transmettant ainsi le signal acoustique à travers un environnement de fond de trou. Un système de puis peut comprendre un transducteur acoustique optique disposé dans le puits et couplé au guide d'ondes optique dans le puits, ainsi le transducteur convertit une énergie optique transmise par l'intermédiaire du guide d'ondes optique en énergie acoustique. Un transducteur acoustique optique pour une utilisation dans un puits souterrain peut comprendre différents moyens de conversion d'énergie optique transmise par l'intermédiaire d'un guide d'ondes optique en énergie acoustique dans le puits.
PCT/US2014/010717 2013-01-24 2014-01-08 Transducteurs acoustiques optiques de fond de trou WO2014116427A1 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
AU2014209780A AU2014209780A1 (en) 2013-01-24 2014-01-08 Downhole optical acoustic transducers
CA2896109A CA2896109A1 (fr) 2013-01-24 2014-01-08 Transducteurs acoustiques optiques de fond de trou
MX2015007546A MX2015007546A (es) 2013-01-24 2014-01-08 Transductores acusticos opticos del fondo de pozo.
EP14742955.9A EP2948626A4 (fr) 2013-01-24 2014-01-08 Transducteurs acoustiques optiques de fond de trou

Applications Claiming Priority (2)

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US13/748,764 US20140204712A1 (en) 2013-01-24 2013-01-24 Downhole optical acoustic transducers
US13/748,764 2013-01-24

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WO2014116427A1 true WO2014116427A1 (fr) 2014-07-31

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US (1) US20140204712A1 (fr)
EP (1) EP2948626A4 (fr)
AU (1) AU2014209780A1 (fr)
CA (1) CA2896109A1 (fr)
MX (1) MX2015007546A (fr)
WO (1) WO2014116427A1 (fr)

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Also Published As

Publication number Publication date
CA2896109A1 (fr) 2014-07-31
US20140204712A1 (en) 2014-07-24
EP2948626A1 (fr) 2015-12-02
EP2948626A4 (fr) 2016-09-07
AU2014209780A1 (en) 2015-06-11
MX2015007546A (es) 2016-03-01

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