US20140219056A1 - Fiberoptic systems and methods for acoustic telemetry - Google Patents

Fiberoptic systems and methods for acoustic telemetry Download PDF

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US20140219056A1
US20140219056A1 US13/758,465 US201313758465A US2014219056A1 US 20140219056 A1 US20140219056 A1 US 20140219056A1 US 201313758465 A US201313758465 A US 201313758465A US 2014219056 A1 US2014219056 A1 US 2014219056A1
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acoustic
signal
optical
downhole
system
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US13/758,465
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Etienne M. SAMSON
David P. Sharp
John L. Maida
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Halliburton Energy Services Inc
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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/12Means 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
    • E21B47/14Means 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
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/12Means 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
    • E21B47/122Means 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
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/12Means 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
    • E21B47/122Means 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
    • E21B47/123Means 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

Abstract

A disclosed acoustic telemetry system includes a downhole acoustic telemetry module that generates an acoustic uplink signal such as a pulsed fluid flow or compressional waves in a tubing string wall. An optical waveguide transports an optical signal representing the acoustic uplink signal to the surface interface. A related telemetry method includes acquiring measurements downhole, transmitting the measurements in the form of an acoustic signal, and sensing the acoustic signal via an optical waveguide.

Description

    BACKGROUND
  • Modern oil field operators demand access to a great quantity of information regarding the parameters and conditions encountered downhole. Such information typically includes characteristics of the earth formations traversed by the borehole and data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole, which commonly is referred to as “logging,” can be performed by several methods including wireline logging and “logging while drilling” (LWD). A closely related information collection technique is “permanent monitoring”.
  • In wireline logging, a sonde is lowered into the borehole after some or all of the well has been drilled. The sonde hangs at the end of a long wireline cable that provides mechanical support to the sonde and also provides an electrical connection between the sonde and electrical equipment located at the surface of the well. In accordance with existing logging techniques, various parameters of the earth's formations are measured and correlated with the position of the sonde in the borehole as the sonde is pulled uphole.
  • In LWD, the drilling assembly includes sensing instruments that measure various parameters as the formation is being penetrated, thereby enabling measurements of the formation while it is less affected by fluid invasion. In permanent monitoring, sensing instruments are installed in a borehole for long-term monitoring of the downhole conditions. Telemetry can be a challenge for both LWD and permanent monitoring environments. One commonly proposed solution is the use of mud pulse telemetry, a telemetry technique in which a flow of fluid along the well is modulated to create pressure fluctuations representing telemetry data. While this telemetry technique is robust and proven, its range and rate are severely limited by the dissipative properties of the fluid flow. Other acoustic telemetry techniques have been proposed to overcome these limitations by generating acoustic waves that propagate along the walls of a tubing string and/or borehole casing, but have thus far met with limited success.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • Accordingly, there are disclosed herein various fiberoptic systems and methods for facilitating acoustic telemetry. In the drawings:
  • FIG. 1A shows an illustrative logging environment with a tubing-conveyed sonde.
  • FIGS. 1B-1D are tubing cross-sections shows illustrative cable dispositions relative to a tubing string.
  • FIG. 1E shows an illustrative logging environment with cable disposed behind casing.
  • FIG. 2 shows an illustrative fiberoptic system for acoustic telemetry.
  • FIGS. 3A-3C show illustrative acoustic-to-optical transducers.
  • FIG. 4 shows an illustrative optical-to-acoustic transducer.
  • FIG. 5 shows an illustrative fiberoptic-facilitated acoustic telemetry method.
  • It should be understood, however, that the specific embodiments given in the drawings and detailed description below do not limit the disclosure. On the contrary, they provide the foundation for one of ordinary skill to discern the alternative forms, equivalents, and other modifications that are encompassed in the scope of the appended claims.
  • DETAILED DESCRIPTION
  • The following disclosure presents the use of fiberoptic sensing for acoustic telemetry in a downhole environment. One or more fiberoptic sensors detect an acoustic telemetry signal near where the acoustic telemetry signal is generated, permitting the acoustic telemetry signal to be optically conveyed between the downhole environment and the surface logging equipment. The signal thus avoids nearly all of the dissipative effects of the fluid stream, thereby permitting significantly greater range and communications bandwidth to be achieved with existing telemetry tools.
  • The disclosed systems, devices and methods are suitable for use in any context where acoustic telemetry (including mud pulse telemetry) might be employed. Selected contexts are now discussed in detail, but they are not exhaustive. FIG. 1A shows an illustrative environment for coiled-tubing conveyed logging. Coiled tubing 54 is drawn from a tubing reel 52 by an injector 56 that straightens the tubing and feeds it through a packer 58 into the well. The packer 58 is attached to the borehole casing 62 by a tree 60 of gates, valves, feedthroughs, outlets, and other elements that enable controlled access to the well. At the distal end of tubing 54 is a bottomhole assembly having a telemetry module 64, one or more logging instruments 65, and any other potentially desirable components such as a drill bit coupled to a drilling motor and any tractors, collars, stabilizers, and/or steering mechanisms that may be employed to extend the borehole.
  • Fluid can be circulated through the tubing 54 and the annular space around tubing 54 during the logging (and optionally drilling) operations via a hub in reel 52 and an outlet from tree 60. Circulation clears debris from the borehole and reduces friction between the tubing and the borehole wall. Further coupled to the hub is a rotary connector that provides a communication link between cable 78 and a communication pathway along the tubing 54. As discussed further below, the communication pathway includes an optical fiber. In some embodiments, the rotary connector optically couples the optical fiber to cable 78. In some alternative embodiments, electronics mounted to reel 52 convert between optical signals transported on the optical fiber and electrical signals coupled to the cable 78 via the rotary connector. In still other embodiments, cable 78 is replaced by a wireless connection that obviates any requirement for a rotary connector.
  • A surface interface 67 accepts the optical, electrical, or wireless signals from the reel 52 and converts them to digital data for transmission a computer system 66. The surface interface 67 may further accept digital data from computer system 66 and convert it to signals for transmission to reel 52 for communication downhole via the communication pathway. Computer system 66 can take many forms ranging from a personal digital assistant (PDA), mobile phone, tablet, laptop or desktop computer in the field to a workstation or large data processing facility at a remote location. Computer system 66 includes a user interface that in FIG. 1A takes the form of a display monitor 68 and keyboard 70. Software on information storage media 72 configures the computer system 66 to process the received signals to extract the acoustic telemetry data for storage and analysis. The software may further display the data and/or analysis results to the user and accept input. Automatically or in response to user input, the software may further configure the computer 66 to generate commands to be communicated downhole and translated into acoustic signals for communication to the telemetry module 64.
  • As mentioned above, a communications pathway is provided along the coiled tubing 54. FIG. 1B shows a first illustrative embodiment in which the communications pathway is a fiberoptic cable 80 suspended within the coiled tubing. FIG. 1C shows a second illustrative embodiment in which the communications pathway is a fiberoptic cable 80 attached to the outside of tubing 54 with a protective molding 82. Alternatively, the fiberoptic cable 80 can be strapped to the tubing 54 and/or wound helically on the tubing 54 to provide the communications pathway. FIG. 1D shows a third illustrative embodiment in which the communications pathway is an optical waveguide or fiber 84 embedded in the wall of tubing 54.
  • It is not required that the communications pathway be attached to the tubing 54. For example, FIG. 1E shows an illustrative embodiment in which the communications pathway is a fiberoptic cable 86 positioned in an annular space outside casing 62 and attached to the casing with straps 88. Cement may be pumped into the annular space to secure the casing and improve acoustic coupling between the casing and the fiberoptic cable. In this embodiment, the portion of the communications pathway that is proximate to the bottomhole assembly (and hence to telemetry module 64) may change as the bottomhole assembly progresses along the borehole. Moreover, there may be some distance that accumulates between the communication pathway and the bottomhole assembly, particularly if the bottomhole assembly moves beyond the cased portion of the borehole and into an uncased zone of the borehole. In such a case, the acoustic signal traverses that distance before it is detected and converted to an optical form. Some system embodiments may employ acoustic signal repeaters to assure that an adequate signal-to-noise ratio is preserved as the acoustic signal traverses this distance. While the exact limits will depend on circumstances, it is expected that sensing within 100 meters of the acoustic transmitter will yield a robust telemetry channel, and greater distances can be tolerated with data rate adjustments to account for dispersion in the acoustic channel.
  • FIG. 2 shows an illustrative acoustic telemetry system configuration in which a light source 202 is coupled to an optical circulator 204 which in turn is coupled to a receiver 206. The circulator directs light from the source 202 to the communication path 208 and directs light received from the communication path to the receiver 206. The communication path 208 supports bidirectional transport of optical signals. As explained further below, the communication path 208 may be terminated near a telemetry module 210 by an acoustic sensor and/or an optical-to-acoustic transducer. However, this is not necessarily the case and there are also disclosed certain embodiments where the communication path 208 terminates with a reflector or dissipation configuration.
  • An acoustic coupling 212 is provided between the communication path 208 and an acoustic signal transmitter 214. In the illustrated example, acoustic signal transmitter 214 includes a stack 216 of piezoelectric washers positioned between a transmitter mount 218 and a reaction mass 220. A controller 224 drives the piezoelectric stack 216 (via an electrical connection 222) to transmit an acoustic signal. In at least some embodiments, the controller 224 transmits measurement data as specially shaped acoustic busts having frequencies adapted to the characteristics of a fluid filled coiled tubing string. The transmitter mount 218 couples the acoustic signal into the walls of the coiled tubing where it propagates towards the surface. Alternative embodiments of acoustic signal transmitter may generate pressure fluctuations in fluid flow along the coiled tubing string, or generate torsional waves and/or shear waves.
  • Some acoustic telemetry system embodiments employ distributed acoustic sensing (DAS) techniques, sometimes called distributed vibration sensing (DVS), to detect the acoustic signal from transmitter 214. Although various DAS techniques exist, they generally rely on monitoring the scattering of light pulses from imperfections in the fiber. Some particular implementations employ pairs of light pulses that scatter light with a phase difference that varies with acoustic wave-associated strain. In any case, the DAS systems enable detection of acoustic signals at each point along the length of the communications path.
  • As mentioned previously, at least some embodiments have the communication path 208 terminated by a sensor that detects the acoustic signal and converts it into a modulated optical signal. Certain illustrative sensor embodiments are shown in FIGS. 3A-3C. FIG. 3A shows communication path 208 as an optical fiber that terminates in a sensor 302. The sensor accepts an incident light beam 304 and provides a return light beam 306. The sensor includes a cantilevered mass 308 on a support 312 over a substrate 314. Vibration of substrate 314 (e.g., in response to an acoustic signal from transmitter 214) causes mass 308 to transition between an equilibrium position and a deflected position 316. A reflective surface 310 is provided on mass 308 such that in the equilibrium position, incident light beam 304 is reflected to form return light beam 306. In the deflected position 316, the reflective surface 310 directs at least some of the light away from communication path 208, causing the return light beam 306 to be attenuated relative to incident light beam 304. The vibration of substrate 314 is thereby translated into amplitude modulation of the return light beam 306.
  • FIG. 3B shows an alternative sensor configuration having an optical fiber 208 with a residual length represented by a coil 320, and reflective end 322. The sensor includes a mounting surface 324 that experiences vibration associated with the acoustic signal, e.g., the coiled tubing wall. Between the mounting surface 324 and a reaction mass 326, the sensor includes mating plates 328A, 328B having ridges 329 to induce bending in the optical fiber 208. As vibrations cause the plates 328A, 328B to move together and apart, the bending of the optical fiber causes varying amounts of light loss, attenuating the incident light beam 304 and the return light beam 306 reflected from end 322. The return light beam 306 is thereby provided with amplitude modulation representing the acoustic signal.
  • FIG. 3C provides an illustrative sensor 330 having a piezoelectric element 332 between the mounting surface 324 and the reaction mass 326. Vibration of the mounting surface 324 produces compression and expansion of the piezoelectric element 332, resulting in a signal voltage across resistor 334. At input nodes 341-342, the bridge rectifier formed from diodes 337, 338, 339, 340 accepts the signal voltage together with a bias voltage from a battery 336 or other power source, and produces a rectified signal voltage between output nodes 344, 346. A light-emitting diode (LED) or other light source 348 converts the rectified signal voltage into light. A lens 350 directs the light along communication path 208 as light beam 306. As the emitted light varies in accordance with the rectified signal voltage, beam 306 represents the envelope of the acoustic signal.
  • Additional functionality can be provided for sensor 330 by including one or more other signal sources 352 in series or parallel with resistor 334 and bias voltage 336. One illustrative example is a coil for casing collar location such as that disclosed in co-pending U.S. applications Ser. Nos. 13/226,578 and 13/432,206, each titled “Optical Casing Collar Locator Systems and Methods”. Alternative embodiments of the casing collar location system may configured the coil to be sensitive to acoustic signals in addition to being sensitive to casing collars. Such embodiments may soft-mount the coil on silicone rubber that enables the coil to act as a reaction mass when the tool body (and static magnets) vibrates in response to the acoustic signal. Other examples of added functionality include temperature sensors, pressure sensors, and flow sensors. In any event, the information from signal source(s) 352 is preferably provided in a separate frequency band than the acoustic signal band. We note here that in some embodiments, the response of the LED itself can be employed as a measure of temperature, e.g., by monitoring the turn-on and turn-off rates associated with light pulses.
  • Due to the use of a downhole light source, sensor 330 does not require the presence of a surface light source 202 (FIG. 2) to provide light for modulation. The surface light source 202 may nevertheless be employed in acoustic telemetry systems designed to support bi-directional communication. In addition to the measurement data being communicated from the bottomhole assembly to the surface, commands may be communicated from the surface to the bottomhole assembly. A beam splitter or downhole circulator separates the up-going light beam 306 (FIG. 3C) from a down-going light signal 304 from the surface light source 202 (FIG. 4).
  • FIG. 4 shows an optical-to-acoustic transducer that converts an optical downlink signal into an acoustic downlink signal. A lens 402 focuses the down-going light signal 304 onto a photodetector 404. An amplifier 406 with a feedback impedance 408 amplifies and filters the signal from the photodetector 404 to drive an acoustic generator 410. The acoustic generator 410 may take the form of a piezoelectric driver that generates compressional, shear, or torsional waves in the coiled tubing walls, or a valve or siren that generates pressure modulation of the fluid flow. The acoustic generation technique is chosen to match the downlink sensing design of the bottomhole assembly. Illustrative acoustic modulation techniques include frequency shift keying, amplitude shift keying, phase shift keying, quadrature modulation, and orthogonal frequency division multiplexing. Store-and-forwarding techniques, alone or combined with caching, compression, and expanded signal constellations, can be employed to increase bandwidth utilization by the acoustic signal and/or the optical signal.
  • Alternative system embodiments replace the acoustic generator 410 with an electromagnetic signal generator to support an electromagnetic telemetry downlink. The signal generator generates low frequency or radio frequency signals to communicate the downlink information to the bottomhole assembly. One suitable RF frequency is 455 kHz, for which existing intermediate frequency (IF) components can be used to amplify and transmit the signal detected by the photodetector. This signal frequency will readily penetrate the borehole fluid for several meters to enable ‘out of band’ communications to the various tool string components.
  • The short travel of the acoustic signals from the bottomhole assembly to the optical communication path (and for downlink signals, from the optical-to-acoustic transducer to the bottomhole assembly) means that the signals are not subject to any significant signal-to-noise ratio (SNR) losses such as those attributable to attenuation, internal reflections, Doppler shifts, dispersion, or environmental noise. As the signal conversion between acoustic and optical regimes is expected to support signal bandwidths of at least hundreds of kilohertz, the acoustic transmitter and receiver in the bottomhole assembly can be configured to support much higher data rates than the typical tens of bits per second, even when driven at much lower power to extend operating life. Indeed, transmission rate of at least tens of thousands of bits per second are expected to be achievable with only minor changes to existing acoustic telemetry modules.
  • The use of the optical communications link greatly reduces signal losses, enabling communication over a greater range than that achievable by electrical conductor or direct acoustic communication, perhaps extending to between 30 and 50 km, or even more. Another potentially advantageous feature of at least some system embodiments is the protection against electrical damage to the bottomhole assembly provided by the wireless (acoustic) link, and the intrinsically safe surface system configuration achievable due to the optical form of the telemetry signal at the surface.
  • FIG. 5 is a flowchart illustrating a method that can be implemented by one or more of the acoustic telemetry systems disclosed herein. In block 502, a tool or bottomhole assembly equipped with an acoustic telemetry module is deployed in a borehole. Either separately or as part of the deployed assembly, an optical fiber is also provided as a communication pathway from the surface to the vicinity of the tool. In block 504, the tool acquires measurement data and transmits the data in the form of an acoustic signal. In block 506, the system converts the acoustic signal into an optical signal. In some system embodiments, this conversion is performed by a discrete sensor coupled to the optical fiber. In other embodiments, this conversion is performed using distributed acoustic sensing with the fiber itself. In block 508, the optical signal is received at the surface and demodulated to extract the measurement data.
  • In block 510, the system sends a command in the form of an optical signal. This downlink signal may be multiplexed with the uplink signal, e.g., using frequency division multiplexing, wave division multiplexing, spin division multiplexing, time division multiplexing, or sent on a separate optical fiber. In block 512, the system converts the downlink optical signal into a downhole acoustic signal in the vicinity of the downhole tool. In block 514, the tool receives the acoustic signal and demodulates it to extract the command.
  • Though various examples of acoustic-to-optical sensors have been described above, these examples are not limiting. Other suitable sensors include fiber Bragg grating (FBG) sensors integrated into the fiber and acoustically ballasted to detect the acoustic signals from the tool. Single-point accelerometers, hydrophones, dynamic pressure, or acoustic sensors of all suitable types can be employed to convert the acoustic signal into optical form. A fast pressure sensor configured to measure dynamic pressure signals may be particularly well suited for coupling the borehole fluid signals to the communication pathway. The sensors may be entirely optical, optionally employing interferometric sensing, electrical, or hybrid in design. Interferometric optical sensors may illustratively be based on Fabry-Perot, Michelson, Mach-Zehnder, Sagnac, or resonant optical cavity configurations.
  • Hybrid sensor designs may employ a piezoelectric crystal stack to convert mechanical vibrations into electrical signals which are then used to modulate the light passing through the optical fiber, e.g., with a second piezoelectric element coupled to a FBG. Suitably configured FBGs are available from Ibsen Photonics under the ‘I-MON’ brand name, offering bandwidths of several tens of kilohertz. Micron Optics offers a similar sensor module “sm690” having a signal bandwidth of 350 kHz. Some alternative tool designs may even bypass the first piezoelectric crystal stack, instead employing a directly-wired electrical conductor to couple the electrical drive signal for the acoustic transmitter to an FBG modulator of the light passing through the optical fiber. Another potentially suitable electrical-to-optical conversion technique is disclosed in U.S. Pat. No. 6,313,056 titled “Fiber optic sensor system and method”. Still another potentially suitable electrical-to-optical conversion method employs an NRL magnetometer configuration such as that disclosed by Koo and Sigel, “Characteristics of fiber-optic magnetic-field sensors employing metallic glasses”, Optics Letters v7(7) p334-336, July 1982.
  • The foregoing telemetry systems and methods are suitable for use in logging while drilling (LWD) environments, reservoir monitoring and production logging environments, tubing-conveyed logging environments, and potentially even in wireline logging environments. Those embodiments employing point sensors rather than distributed sensing may configure the point sensors in series, in parallel, or in a combination of both configurations, using time division and/or frequency division multiplexing to separate the readings of the multiple sensors. Having multiple sensors provides the system with redundancy and may further improve performance by having readings from multiple sensor positions which can be combined to improve signal to noise ratio.
  • Numerous other variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such variations and modifications.

Claims (19)

What is claimed is:
1. A downhole telemetry method that comprises:
acquiring measurements downhole;
transmitting downhole measurements in the form of an acoustic signal; and
sensing the acoustic signal downhole via an optical waveguide.
2. The method of claim 1, wherein the optical waveguide comprises an optical fiber and said sensing comprises distributed acoustic sensing along said optical fiber.
3. The method of claim 1, wherein the optical waveguide comprises an optical fiber and said sensing includes transducing motion or pressure associated with the acoustic signal into applied stress or deformation of the optical fiber to modulate passing light.
4. The method of claim 1, wherein said sending includes converting motion or pressure associated with the acoustic signal into a modulated optical signal for transmission via the optical waveguide.
5. The method of claim 4, wherein said converting includes modulating an optical signal received via said optical waveguide.
6. The method of claim 4, wherein said converting includes obtaining an electrical response to said motion or pressure and applying the electrical response to a downhole light emitter that transmits said modulated optical signal.
7. The method of claim 4, wherein said converting includes obtaining an electrical response to said motion or pressure and applying the electrical response to a transducer that deforms or applies stress to the optical fiber to modulate passing light.
8. The method of claim 1, further comprising:
transmitting one or more commands via the optical waveguide to a downhole transducer; and
generating an acoustic downlink signal representing said one or more commands.
9. An acoustic telemetry system that comprises:
a downhole acoustic telemetry module that generates an acoustic uplink signal; and
an optical waveguide that transports an optical signal representing the acoustic uplink signal to a surface interface.
10. The system of claim 9, further comprising one or more downhole sensors coupled to the optical waveguide, wherein the one or more sensors convert the acoustic uplink signal into said optical signal.
11. The system of claim 9, wherein the optical waveguide comprises an optical fiber that converts the acoustic signal into modulation of light provided by distributed acoustic sensing electronics coupled to the surface interface.
12. The system of claim 9, wherein the acoustic signal comprises modulation of a fluid flow.
13. The system of claim 12, wherein the fluid flow comprises a circulated fluid.
14. The system of claim 12, wherein the fluid flow comprises a produced fluid.
15. The system of claim 9, wherein the acoustic signal comprises at least one of compressional, shear, or torsional waves in a tubing string wall.
16. The system of claim 15, wherein the tubing string comprises coiled tubing.
17. The system of claim 15, wherein the tubing string comprises production tubing or a casing string.
18. The system of claim 9, further comprising a downhole optical-to-acoustic transducer that converts an optical downlink signal into an acoustic downlink signal.
19. The system of claim 18, wherein the optical waveguide also transports the optical downlink signal from the surface interface to the downhole transducer.
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