BI-DIRECTIONAL ACOUSTIC TELEMETRY SYSTEM

Abstract

A bi-directional telemetry system for use in a wellbore environment is provided. The bi-directional telemetry system includes a first acoustic telemetry component and a second acoustic telemetry component that is separate from the first acoustic telemetry component. The first acoustic telemetry component comprises a downhole acoustic transmitter disposed in a wellbore and operable to transmit the first acoustic signal and an uphole acoustic receiver. The second acoustic telemetry component comprises an uphole acoustic transmitter operable to transmit the second acoustic signal and a downhole acoustic receiver.

Description

TECHNICAL FIELD

The present disclosure relates generally to acoustic telemetry systems. In at least one example, the present disclosure relates to bi-directional acoustic telemetry systems for use in a wellbore.

BACKGROUND

Wellbores are drilled into the earth for a variety of purposes including accessing hydrocarbon bearing formations. A variety of downhole tools may be used within a wellbore in connection with accessing and extracting such hydrocarbons. Such downhole tools often include a number of components such as electronic equipment, sensors, or other modules used for various purposes. The downhole tools may require instructions and/or may need to pass along data obtained by sensors of the downhole tool. Telemetry is often performed via an electrical cable or fiber optic cable disposed inside a conduit, for example, within coiled tubing. In the absence of such a wired telemetry system, downhole tools may need to be set via a timing mechanism, or triggered by a mechanical event from the surface.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other advantages and features of the disclosure can be obtained, a more particular description of the principles briefly described above will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only exemplary embodiments of the disclosure and are not therefore to be considered to be limiting of its scope, the principles herein are described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 is a diagram illustrating an exemplary environment for a bi-directional acoustic telemetry system, in accordance with various aspects of the subject technology;

FIG. 2 is a diagram of a controller of a bi-directional acoustic telemetry system, in accordance with various aspects of the subject technology;

FIG. 3A is a diagram illustrating an exemplary acoustic receiver, in accordance with various aspects of the subject technology;

FIG. 3B is a diagram illustrating another example of an acoustic receiver with multiple optical vibrometers, in accordance with various aspects of the subject technology; and

FIG. 4 is an example method for transmitting and receiving different acoustic signals in a wellbore system, in accordance with various aspects of the subject technology.

DETAILED DESCRIPTION

It will be appreciated that for simplicity and clarity of illustration, where appropriate, reference numerals have been repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the examples described herein. However, not all of the details may be necessary to practice the disclosed examples. In other instances, methods, procedures and components have been described so as not to obscure the related relevant feature being described. Also, the description is not to be considered as limiting the scope of the examples described herein. The drawings are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate details and features.

Disclosed herein is a bi-directional acoustic telemetry system for use in a wellbore system. The acoustic telemetry system includes a first acoustic telemetry component and a second acoustic telemetry component. The first acoustic telemetry component may include a downhole acoustic transmitter configured to transmit a first acoustic signal from a downhole tool disposed in a wellbore to a surface, and an uphole acoustic receiver to receive signals conveyed by the downhole acoustic transmitter. The second acoustic telemetry component may include an uphole acoustic transmitter configured to transmit a second acoustic signal from the surface to the downhole tool disposed in the wellbore, and a downhole acoustic receiver to receive signals conveyed by the uphole acoustic transmitter. The downhole and uphole acoustic transmitters can each be operable to convey acoustic signals to their corresponding acoustic receiver by inducing vibrations on a conduit/wellbore and/or by interrupting a flow of a fluid such that longitudinal, compressional, torsional, rotational, and/or flexural waves are propagated through the conduit/wellbore and/or fluid.

In some aspects, the waves can include components such as, for example, longitudinal components, flexural components, axial components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement. For example, the downhole or uphole acoustic transmitter may impact the conduit at predetermined frequencies, directions and/or intensities such that waves corresponding to the predetermined frequencies, directions, and/or intensities propagate through the conduit to the corresponding acoustic receiver. In another example, the downhole or uphole acoustic transmitter may interrupt with a flow of fluid to generate a pressure pulse at a predetermined frequency such that waves corresponding to the predetermined frequency propagate through the fluid to the corresponding acoustic receiver. By way of one example, the downhole acoustic transmitter may transmit the first acoustic signal via the conduit by inducing vibrations on the conduit. The first acoustic signal may represent data gathered from a sensor of the downhole tool. The uphole acoustic transmitter may transmit the second acoustic signal via the fluid flowing within the conduit by interrupting flow of the fluid using a valve to thereby generate a pressure pulse within the fluid. The second acoustic signal may represent commands or instructions for controlling an operation of the downhole tool.

The second acoustic telemetry component is separate from the first acoustic telemetry component. For example, the downhole acoustic transmitter may be a different type of transmitter than the uphole acoustic transmitter Similarly, the uphole acoustic receiver may be different than the downhole acoustic receiver. Accordingly, the first acoustic telemetry component can send the signal separate and independently through a different method of acoustic telemetry than the second acoustic telemetry component.

In at least one example, the first acoustic signal may have a higher data rate when compared to the second acoustic signal. In another example, because the first acoustic signal and the second acoustic signal utilize different acoustic telemetry components (for example inducing vibrations on conduit, interrupting flow of a fluid to generate a pressure pulse, etc.), the first and second acoustic signals do not interfere with each other.

FIG. 1 is a schematic diagram illustrating an exemplary environment for a bi-directional acoustic telemetry system 100, in accordance with various aspects of the subject technology. The environment may include a wellhead 30 extending over and around a wellbore 14. The wellbore 14 is within an earth formation 22 and, in at least one example, can have a casing 20 lining the wellbore 14. The casing 20 can be held into place by cement 16. In at least one example, the casing 20 can be at least partially made of an electrically conductive material, for example steel. In another example, the casing 20 can be at least partially made of a non-electrically conductive material, for example fiberglass or PEEK, or of a low-conductivity material, for example carbon composite, or a combination of such materials. A downhole tool 50 can be disposed within the wellbore 14 and moved down the wellbore 14 via a conduit 18 to a desired location. The conduit 18 may be coiled tubing. In other examples, the conduit 18 can be, for example, tubing-conveyed via a wireline, slickline, work string, joint tubing, jointed pipe, pipeline, and/or any other suitable means. The downhole tools 50 can include, for example, downhole sensors, chokes, and valves. The chokes and valves may include actuatable flow regulation devices, such as variable chokes and valves, and may be used to interrupt, regulate, or alter the flow of the fluids flowing within the conduit 18.

The wellhead 30 can include a blowout preventer 34, a stripper 36, and/or an injector 32. The injector 32 can inject the conduit 18 into the wellbore 14. For example, the conduit 18 can be stored in a reel 12 and when dispatched, may extend from the reel 12, pass through the injector 32, and into the wellbore 14. In other examples, the injector 32 can pull the conduit 18 to retrieve the conduit 18 from the wellbore 14. The stripper 36 can provide a pressure seal around the conduit 18 as the conduit 18 is being run into and/or pulled out of the wellbore 14. The blowout preventer 34 can seal, control, and/or monitor the wellbore 14 to prevent blowouts, or uncontrolled and/or undesired release of fluids from the wellbore 14. In other examples, different systems may be utilized based on the type of conduit 18 and/or the environment, such as those involving subsea or surface operations.

While FIG. 1 generally depicts a land-based operation, those skilled in the art would readily recognize that the principles described herein are equally applicable to operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. Further, even though FIG. 1 depicts a vertical wellbore, the present disclosure is equally well-suited for use in wellbores having other orientations, including horizontal wellbores, slanted wellbores, multilateral wellbores or the like.

The bi-directional acoustic telemetry system 100 includes a first acoustic telemetry component 150 and a second acoustic telemetry component 160. The first acoustic telemetry component 150 is operable to transmit a first acoustic signal 151 from a downhole tool 50 disposed in a wellbore 14 to a surface. The first acoustic telemetry component 150 includes a downhole acoustic transmitter 152 disposed in the wellbore 14 and operable to transmit the first acoustic signal 151 by creating waves to propagate in the wellbore 14, and an uphole acoustic receiver 154 positioned uphole from the downhole acoustic transmitter 152 and operable to detect the waves transmitted by the downhole acoustic transmitter 152. The second acoustic telemetry component 160 is operable to transmit a second acoustic signal 161 from the surface to the downhole tool 50 disposed in the wellbore 14. The second acoustic telemetry component 160 includes an uphole acoustic transmitter 162 operable to transmit the second acoustic signal 161 by creating waves to propagate in the wellbore 14, and a downhole acoustic receiver 164 positioned downhole from the uphole acoustic transmitter 162 and operable to detect the waves transmitted by the uphole acoustic transmitter 162.

The second acoustic telemetry component 160 is separate from the first acoustic telemetry component 150. For example, the downhole acoustic transmitter 152 may be a different type of transmitter than the uphole acoustic transmitter 162. Similarly, the uphole acoustic receiver 154 may be different than the downhole acoustic receiver 164. Accordingly, the first acoustic telemetry component 150 can send the signal separate and independently through a different method of acoustic telemetry than the second acoustic telemetry component 160.

The first acoustic telemetry component 150 may be utilized to transmit acoustic signals representing data from a sensor of the downhole tool 50, to the surface. The data from the sensor of the downhole tool 50 may include wellbore temperature, wellbore pressure, collar location, gamma ray, inclination, vibration, tool face, azimuth, tension, compression, torque, fluid rate, fluid resistivity, magnetic field strength and direction, gravitational field strength and direction, acoustic readings, casing composition, wellbore composition, wellbore diameter, particle concentration, gas concentration, still images, video, fluid composition, and/or fluid density. The data may also include status of the downhole tool, such as board temperature, current consumption, battery status, voltage or current levels, warnings and/or failure indicators. The second acoustic telemetry component 160 may be utilized to transmit acoustic signals representing data, such as instructions for the downhole tool 50, from the surface to the downhole tool 50.

The downhole acoustic transmitter 152 of the first acoustic telemetry component 150 may convey the first acoustic signal 151 to the uphole acoustic receiver 154 by inducing vibrations such that compressional, torsional, rotational and/or flexural waves are propagated through the conduit 18 disposed within the wellbore 14; or by interrupting a flow of fluid within an annulus of the wellbore 14 to generate a pressure pulse at a predetermined frequency such that waves corresponding to the predetermined frequency propagate through the fluid to the uphole acoustic receiver 154. The waves may propagate through the conduit 18, along an annulus of the wellbore 14, along the annulus of the wellbore 14 through a fluid, annulus of the conduit 18 disposed within the wellbore 14, or along the annulus of the conduit 18 through a fluid. In at least one example, the vibrations may be induced by impacting the conduit or by opening or closing a valve or by altering rotation of a turbine to affect fluid flow to generate a pressure pulse. The waves generated by the downhole acoustic transmitter 152 may include components such as, for example, longitudinal components, flexural components, axial components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement. Other waveforms may also be utilized, such as Ricker pulses (or other form of wavelet), Gaussian pulses, square wave pulses, and/or sinusoidal pulses.

The downhole acoustic transmitter 152 may be disposed within the wellbore 14, on the downhole tool 50, and electrically coupled to a sensor of the downhole tool 50 to receive electrical signals from the coupled sensor. In at least one example, the downhole acoustic transmitter 152 may be communicatively coupled with the downhole tool 50. In some examples, the downhole acoustic transmitter 152 may be part of the downhole tool 50, such that the downhole tool 50 can be shipped and disposed within the wellbore 14 along with the downhole acoustic transmitter 152. In some examples, the downhole acoustic transmitter 152 may be coupled with the conduit 18 such that the acoustic transmitter 152 can induce the conduit 18 to vibrate, compress, rotate, bend, flex, and/or expand such that waves are propagated through the conduit 18 to the uphole acoustic receiver 154. The downhole acoustic transmitter 152 may include at least one of: a piezoelectric transducer, a siren, a mud pulse, an Electro-Magnetic Acoustic Transducer (“EMAT”), a pinger, a voice coil, and/or a phased acoustic array.

The uphole acoustic receiver 154 is configured to detect compressional, torsional, rotational, and/or flexural waves propagating through the conduit 18 created by the downhole acoustic transmitter 152. The uphole acoustic receiver 154 may be positioned between the injector 32 and the reel 12 at a side of the system 100 with a lower pressure. In some examples, the uphole acoustic receiver 154 may be positioned to measure waves propagating through the conduit 18 through the blowout preventer 34, and/or the stripper 36 at the side of the system 100 with a higher pressure. In yet another example, the uphole acoustic receiver 154 may be positioned to measure components of waves propagating through the conduit 18 at the injector 32. In some examples, the uphole acoustic receiver 154 may be disposed proximate to the conduit 18. In at least one example, the uphole acoustic receiver 154 may be coupled with the conduit 18 by a stand which protrudes from the conduit 18 and/or a casing. In some examples, the uphole acoustic receiver 154 may function without being in direct contact with the conduit 18. In at least one example, the uphole acoustic receiver 154 may be removably coupled with the system 100. For example, the uphole acoustic receiver 154 may be removed and/or installed independently from the rest of the system 100. Accordingly, the uphole acoustic receiver 154 may be independently delivered, installed in, and/or removed from the system 100. In other examples, the uphole acoustic receiver 154 may be installed during operation of the system 100, such as while undertaking coiled tubing operations.

The uphole acoustic receiver 154 may include an optical vibrometer that may be configured to emit at least one optical beam to a single point of reference on the conduit 18 and receive one or more reflections of the at least one optical beam off of the single point of reference on the conduit 18. In another example, the uphole acoustic receiver 154 may include a time of flight-based laser system such as a light detection and ranging (“LIDAR”) system. The laser system may be utilized to extract the flexural component of the compressional wave propagating through the conduit 18. In other examples, the uphole acoustic receiver 154 may include a Doppler sonar, Doppler LIDAR, Doppler vibrometer, laser Doppler velocimeters, strain gauge, pressure sensor, accelerometer, laser microphone, laser scanning vibrometer, optical amplitude system, optical phased array LIDAR, flash LIDAR, spinning LIDAR, mechanical scanning LIDAR, frequency modulated continuous-wave LIDAR, amplitude-modulated continuous wave LIDAR, proximity detectors, acoustic ranging devices, magnetic ranging devices, a Hall effect sensor, and/or other suitable systems to detect flexural and longitudinal components of an acoustic signal.

The uphole acoustic receiver 154 is configured to detect the first acoustic signal 151 generated by the downhole acoustic transmitter 152 and provide data representing the detected first acoustic signal 151 to a first controller 156, which is discussed in further detail with reference to FIG. 2. The first controller 156 is configured to receive the data from the uphole acoustic receiver 154 and determine the components of the compressional, torsional, rotational, and/or flexural waves propagating through the conduit 18 and created by the downhole acoustic transmitter 152. The first controller 156 is thus configured to determine the first acoustic signal 151 transmitted by the downhole acoustic transmitter 152 based on the components of the waves propagating through the conduit 18.

In some examples, the first controller 156 determines the compressional, torsional, rotational, and/or flexural waves of the first acoustic signal 151 by processing data (for example, filtering, error correction, cross correlations, time-reversal pre-equalization, equalization, Golay encoding, etc.) received from the uphole acoustic receiver 154. The first controller 156 may, for example, use or integrate displacement data, velocity data, and/or acceleration data received from the uphole acoustic receiver 154 to determine the components of the waves, which may, for example, comprise longitudinal components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement. Based on the components of the waves, the first controller 156 reconstructs the first acoustic signal 151 and demodulates the first acoustic signal 151 to determine the data being conveyed by the downhole acoustic transmitter 152.

For example, in a simple frequency shift keying (FSK) modulation using compressional waves, the downhole acoustic transmitter 152 can generate compressional acoustic waves at two distinct frequencies f1 and f2 to represent the binary 1 and 0. The first acoustic signal 151 can be coded using sequences of these two frequencies. The uphole acoustic receiver 154 is configured to detect the two frequencies as time sequences and the first controller 156 demodulates the components of the wave to determine the original transmitted binary sequence. Other modulation schemes are contemplated, however, including time-delay schemes, time domain modulation (TDM), On-Off keying, higher order modulations (such as QAM), orthogonal frequency division multiplexing (OFDM), spread spectrum, time domain modulation, and/or amplitude shift keying.

As discussed above, the data conveyed by the downhole acoustic transmitter 152 may include wellbore data such as temperature, pressure, casing collar locations, radiation levels, tool weights, magnetic field strength and direction, gravitational field strength and direction, acoustic readings, casing composition, wellbore composition, wellbore diameter, particle concentration, gas concentration, still images, video, fluid composition, and/or fluid density taken from sensors of the downhole tool 50. The data may also include status of the downhole tool, such as board temperature, current consumption, battery status, voltage or current levels, warnings and/or failure indicators. The data may be input into logs and/or simulations and based on the data, adjustments may be made such as closing sections of the well, stimulation of the formation, or any other suitable actions.

The uphole acoustic transmitter 162 of the second acoustic telemetry component 160 may convey the second acoustic signal 161 to the downhole acoustic receiver 164 by inducing vibrations such that compressional, torsional, rotational, and/or flexural waves are propagated through the conduit 18; or by interrupting a flow of fluid within an annulus of the wellbore 14 to generate a pressure pulse at a predetermined frequency such that waves corresponding to the predetermined frequency propagate through the fluid to the downhole acoustic receiver 164. In at least one example, the vibrations may be induced by impacting the conduit or by opening or closing a valve or by altering rotation of a turbine to affect fluid flow to generate the pressure pulse. The waves may propagate through the conduit 18, along an annulus of the wellbore 14, along the annulus of the wellbore 14 through a fluid, annulus of the conduit 18 disposed within the wellbore 14, or along the annulus of the conduit 18 through a fluid. The waves generated by the downhole acoustic transmitter 152 may include components such as, for example, longitudinal components, flexural components, axial components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement. Other waveforms may also be utilized, such as Ricker pulses (or other form of wavelet), Gaussian pulses, square wave pulses, and/or sinusoidal pulses.

The uphole acoustic transmitter 162 may be disposed uphole from the downhole tool 50 and the downhole acoustic receiver 164. As illustrated in FIG. 1, the uphole acoustic transmitter 162 may be disposed within the wellbore 14 below the wellhead 30 and/or after the injector 32. It is understood, however, that the uphole acoustic transmitter 162 may be disposed between the wellhead 30 and the reel 12 or in any other suitable location as would be understood by one of ordinary skill The uphole acoustic transmitter 162 may include at least one of a piezoelectric transducer, a siren, a mud pulse, an Electro-Magnetic Acoustic Transducer (“EMAT”), a pinger, a voice coil, and/or a phased acoustic array. The uphole acoustic transmitter 162 is configured to receive electrical signals representing instructions and convert the electrical signals into the second acoustic signal 161.

The downhole acoustic receiver 164 is configured to detect compressional, torsional, rotational, and/or flexural waves propagating through the conduit 18 created by the uphole acoustic transmitter 162. In some examples, the downhole acoustic receiver 164 is configured to detect the pressure pulse created by the uphole acoustic transmitter 162. The downhole acoustic receiver 164 may be disposed in the wellbore 14, on the downhole tool 50, and communicatively coupled with a downhole tool 50. The downhole acoustic receiver 164 is configured to detect the second acoustic signal 161. The downhole acoustic receiver 164 may include at least one of an optical vibrometer, LIDAR, Doppler sonar, Doppler LIDAR, Doppler vibrometer, laser Doppler velocimeters, strain gauge, pressure sensor, accelerometer, laser microphone, laser scanning vibrometer, optical amplitude system, optical phased array LIDAR, flash LIDAR, spinning LIDAR, mechanical scanning LIDAR, frequency modulated continuous-wave LIDAR, amplitude-modulated continuous wave LIDAR, acoustic ranging system, magnetic ranging system, a piezoelectric sensor, a Hall effect sensor, and/or other suitable systems to detect flexural and longitudinal components of an acoustic signal or to detect a pressure pulse of a fluid.

The downhole acoustic receiver 164 is configured to detect the second acoustic signal 161 generated by the uphole acoustic transmitter 162 and provide data representing the detected second acoustic signal 161 to a second controller 166, which is discussed in further detail with reference to FIG. 2. The second controller 166 is configured to receive the data from the downhole acoustic receiver 164 and determine components of the compressional, torsional, rotational, and/or flexural waves propagating through the conduit or fluid and created by the uphole acoustic transmitter 162. The second controller 166 is thus configured to determine the second acoustic signal 1561 transmitted by the uphole acoustic transmitter 162 based on the components of the waves propagating through the conduit or the fluid.

In some examples, the second controller 166 determines the compressional, torsional, rotational, and/or flexural waves of the second acoustic signal 161 by processing data (for example, filtering, error correction, cross correlations, time-reversal pre-equalization, equalization, Golay encoding, etc.) received from the downhole acoustic receiver 164. The second controller 166 may, for example, use or integrate displacement data, velocity data, and/or acceleration data received from the downhole acoustic receiver 164 to determine the components of the waves, which may, for example, include longitudinal components, torsional components, frequencies, phases, amplitudes, velocities, accelerations, angular velocities, angular accelerations, angular displacement, and/or displacement. Based on the components of the waves, the second controller 166 reconstructs the second acoustic signal 161 and demodulates the second acoustic signal 161 to determine the instructions being conveyed by the uphole acoustic transmitter 162. Modulation schemes utilized by the second controller 166 may include time-delay schemes, time domain modulation (TDM), On-Off keying, higher order modulations (such as QAM), orthogonal frequency division multiplexing (OFDM), spread spectrum, time domain modulation, frequency shift keying (FSK), and/or amplitude shift keying. The instructions conveyed by the uphole acoustic transmitter 162 and provided to the downhole tool 50 may be used to conduct an operation. For example, if the downhole tool 50 includes a valve, the instructions may include opening or closing the valve.

In at least one example, the first acoustic telemetry component 150 and the second acoustic telemetry component 160 are separate and utilize different acoustic telemetry methods. For example, the first acoustic telemetry component 150 may be operable to induce vibrations on the conduit 18 by impacting the conduit 18 to transmit the first acoustic signal 151. The first acoustic signal 151 may represent data gathered from a sensor of the downhole tool 50. The second acoustic telemetry component 160 may be operable to interrupt a flow of fluid to generate a pressure pulse (e.g., second acoustic signal 161) at a predetermined frequency such that waves corresponding to the predetermined frequency propagate through the fluid to the downhole acoustic receiver 164. The second acoustic signal 161 may represent commands or instructions for controlling an operation of the downhole tool 50. As such, the downhole acoustic transmitter 152 and the uphole acoustic transmitter 162 may include different transmitter components, and the uphole acoustic receiver 154 and the downhole acoustic receiver 164 may include different receiver components. For example, the first acoustic telemetry component 150 may utilize an EMAT as the downhole acoustic transmitter 152 to generate the first acoustic signal 151 through the conduit 18 and an optical vibrometer as the uphole acoustic receiver 154. The second acoustic telemetry component 160 may utilize a siren as the uphole acoustic transmitter 162 to generate the second acoustic signal 161 comprising a pressure pulse within fluid flowing in an annulus of the wellbore 14, and a pressure sensor as the downhole acoustic receiver 164.

By utilizing different components for each of the first and second acoustic telemetry components, 150 and 160 respectively, and utilizing different types of acoustic signals, 151 and 161 respectively, for each of the first and second acoustic telemetry components, 150 and 160 respectively, interference between the two systems is mitigated. In some examples, because the first acoustic telemetry component 150 and the second acoustic telemetry component 160 are separate and different, a data rate for each component may be different. For example, a data rate for the first acoustic signal 151 may be higher compared to a data rate of the second acoustic signal 161.

FIG. 2 is a schematic diagram of a controller 156, 166 of a bi-directional acoustic telemetry system, in accordance with various aspects of the subject technology. The controller 156, 166 is configured to perform processing of data and communicate with the acoustic receiver 1154, 164, for example as illustrated in FIG. 1. In operation, controller 156, 166 communicates with one or more of the above-discussed components, for example the uphole acoustic receiver 154 and downhole acoustic receiver 164, respectively, and may also be configured to communicate with remote devices/systems.

As shown, controller 156, 166 includes hardware and software components such as network interfaces 210, at least one processor 220, sensors 260 and a memory 240 interconnected by a system bus 250. Network interface(s) 210 can include mechanical, electrical, and signaling circuitry for communicating data over communication links, which may include wired or wireless communication links. Network interfaces 210 are configured to transmit and/or receive data using a variety of different communication protocols, as will be understood by those skilled in the art.

Processor 220 represents a digital signal processor (e.g., a microprocessor, a microcontroller, or a fixed-logic processor, etc.) configured to execute instructions or logic to perform tasks in a wellbore environment. Processor 220 may include a general purpose processor, special-purpose processor (where software instructions are incorporated into the processor), a state machine, application specific integrated circuit (ASIC), a programmable gate array (PGA) including a field PGA, an individual component, a distributed group of processors, and the like. Processor 220 typically operates in conjunction with shared or dedicated hardware, including but not limited to, hardware capable of executing software and hardware. For example, processor 220 may include elements or logic adapted to execute software programs and manipulate data structures 245, which may reside in memory 240.

Sensors 260 typically operate in conjunction with processor 220 to perform measurements, and can include special-purpose processors, detectors, transmitters, receivers, and the like. In this fashion, sensors 260 may include hardware/software for generating, transmitting, receiving, detection, logging, and/or sampling magnetic fields, electric fields, seismic activity, and/or acoustic waves, temperature, pressure, fluid types and concentrations, particle concentrations, or other parameters. Additionally, sensors 260 may include the uphole acoustic receiver 154 and downhole acoustic receiver 164, as disclosed herein.

Memory 240 comprises a plurality of storage locations that are addressable by processor 220 for storing software programs and data structures 245 associated with the embodiments described herein. An operating system 242, portions of which may be typically resident in memory 240 and executed by processor 220, functionally organizes the device by, inter alia, invoking operations in support of software processes and/or services 244 executing on controller 200. These software processes and/or services 244 may perform processing of data and communication with controller 200, as described herein. Note that while process/service 244 is shown in centralized memory 240, some examples provide for these processes/services to be operated in a distributed computing network.

It will be apparent to those skilled in the art that other processor and memory types, including various computer-readable media, may be used to store and execute program instructions pertaining to the fluidic channel evaluation techniques described herein. Also, while the description illustrates various processes, it is expressly contemplated that various processes may be embodied as modules having portions of the process/service 244 encoded thereon. In this fashion, the program modules may be encoded in one or more tangible computer readable storage media for execution, such as with fixed logic or programmable logic (e.g., software/computer instructions executed by a processor, and any processor may be a programmable processor, programmable digital logic such as field programmable gate arrays or an ASIC that comprises fixed digital logic. In general, any process logic may be embodied in processor 220 or computer readable medium encoded with instructions for execution by processor 220 that, when executed by the processor, are operable to cause the processor to perform the functions described herein.

FIG. 3A is a diagram illustrating an exemplary acoustic receiver 154, 164, in accordance with various aspects of the subject technology. The waves propagating through the conduit 18 as illustrated in FIG. 3A are illustrative and may not be indicative of the relative amount of flexural expansion. The acoustic receiver 154, 164 is positioned and supported such that an optical beam 173 is focused on the conduit 18. The acoustic receiver 154, 164 can include an optical emitter 171 and an optical receiver 172. The optical emitter 171 is operable to emit an optical beam 173 to a single point of reference 175 on the conduit 18. In at least one example, the optical beam 173 can have a wavelength between about 100 nm and about 10,000 nm. The optical beam 173 reflects off of and/or interferes at the single point of reference 175 of the conduit 18, and the reflections 174 can scatter and/or reflect back to the optical receiver 172. The optical receiver 172 is operable to receive one or more of the reflections 174 of the optical beam 173 off of the single point of reference on the conduit 18. While FIG. 3A illustrates that the optical emitter 171 and the optical receiver 172 are separate components, in at least one example, the optical emitter 171 and the optical receiver 172 can be one component. In some examples, the optical emitter 171 and the optical receiver 172 may be independent and separate components and are not housed in the same device. In some examples, the optical receiver 172 can either be positioned near the optical emitter 171, or at any angle to receive the reflections 174. In at least one example, the optical emitter 171 and optical receiver 172 can be time gated and share a time reference to permit distance resolution with LIDAR techniques. In at least one example, at least two optical receivers 172 can be included to extract out two or more waves, for example both torsional and compressional waves simultaneously. In some examples, a single optical receiver 172 can be rotated to extract compressional waves and then separately, the optical receiver 172 can be rotated to extract torsional waves. In some examples, two optical receivers 172 can be positioned to generate an interference pattern on the conduit 18 imaged by an optical receiver 172.

In at least one example, the optical beam 173 reflects off of the conduit 18 directly. In some examples, the conduit 18 may include a reflector to enhance and/or deflect the reflection of the optical beam 173. In some examples, two acoustic receivers 154, 164 can be utilized and/or the optical emitter 171 and the optical receiver 172 can be positioned separate from one another, the transmitted optical beam 173 and the reflections 174 can be separated. The conveyed signal from the acoustic transmitters 152, 162 can be determined in such an example by cross correlation. In some examples, the conduit 18 may include a retroreflector such that the reflections 174 are directed back in the same path as the optical beam 173.

FIG. 3B is a diagram illustrating another example of an acoustic receiver 154, 164 with multiple optical vibrometers 155, 355, in accordance with various aspects of the subject technology. For example, as illustrated in FIG. 3B, one optical vibrometer 155 emits an optical beam 173 and receives reflections 174 on a single point of reference 175 on the conduit 18.

Another optical vibrometer 355 also emits an optical beam 373 and receives reflections 374 on the single point of reference 175 on the conduit 18. For example, optical vibrometer 155 may detect longitudinal components of the waves while optical vibrometer 355 may be rotated 90 degrees to detect torsional components of the waves. The controller 156, 166 can receive the detected components of the waves and more accurately determine the signal conveyed by the downhole acoustic transmitter 152 and uphole acoustic transmitter 162, respectively.

In another example, the acoustic receiver 154, 164 may include an optical vibrometer 155 that is configured to emit a first and second optical beam such that the first and second optical beams interfere at the single point of reference 175 on the conduit 18. In this example, the controller 156, 166 may be configured to measure a spacing of the interference pattern to determine a velocity of the conduit 18 or to measure an optical frequency of the reflections on the single point of reference 175 to determine the velocity of the conduit.

In some examples, the one optical vibrometer 155 and another optical vibrometer 355 can be positioned on opposite sides of the conduit 18, for example 180 degrees from one another. In other examples, more than two optical vibrometers 155, 355 may be included. In at least one example, the optical vibrometers 155, 355 can be spaced equally apart from one another about the circumference of the conduit 18. In some examples, the optical vibrometers 155, 355 can be spaced at any desired and predetermined distance from one another. However, the optical vibrometers 155, 355 can all independently detect the compressional waves and do not need a second point of reference. Additionally, the single point of reference 175 can refer to a single longitudinal point of reference 175 on the conduit 18. For example, a single longitudinal point along the circumference of the conduit 18 can be the single point of reference 175.

FIG. 4 is an example method 400 for transmitting and receiving different acoustic signals in a wellbore system, in accordance with various aspects of the subject technology. The method 400 is provided by way of example, as there are a variety of ways to carry out the method. The method 400 described below can be carried out using the configurations illustrated in FIGS. 1-3B, for example, and various elements of these figures are referenced in explaining example method 400. Each block shown in FIG. 4 represents one or more processes, methods or subroutines, carried out in the example method 400. Furthermore, the illustrated order of operations is illustrative only and the order of the operations can change according to the present disclosure. Additional operations may be added or fewer operations may be utilized, without departing from this disclosure. The example method 400 can begin at block 410.

At block 410, a first acoustic signal is transmitted by a first acoustic telemetry component from a downhole tool disposed in a wellbore to a surface. At block 420, a second acoustic signal is transmitted by a second acoustic telemetry component separate from the first acoustic telemetry component from the surface to the downhole tool. The first acoustic telemetry component includes a downhole acoustic transmitter disposed in the wellbore and operable to transmit the first acoustic signal by creating waves to propagate in the wellbore. The first acoustic telemetry component further includes an uphole acoustic receiver positioned uphole from the downhole acoustic transmitter and operable to detect the waves transmitted by the downhole acoustic transmitter. The second acoustic telemetry component includes an uphole acoustic transmitter operable to transmit the second acoustic signal by creating waves to propagate in the wellbore. The second acoustic telemetry component further includes a downhole acoustic receiver positioned downhole from the uphole acoustic transmitter and operable to detect the waves transmitted by the uphole acoustic transmitter.

In some examples, the first acoustic telemetry component and the second acoustic telemetry component are separate and different systems. The downhole acoustic transmitter and the uphole acoustic transmitter may include different transmitter components, and the uphole acoustic receiver and the downhole acoustic receiver may include different receiver components. By utilizing different components for each of the first and second acoustic telemetry component and utilizing different types of acoustic signals for each of the first and second acoustic telemetry component, interference between the two systems is mitigated. In some examples, because the first acoustic telemetry component and the second acoustic telemetry component utilize different acoustic methods, a data rate for each component may be different. For example, a data rate for the first acoustic signal may be higher compared to a data rate of the second acoustic signal.

As described above, the acoustic transmitter of the first acoustic telemetry component and/or the second acoustic telemetry component may transmit compressional waves, torsional, rotational, and/or flexural waves to convey data to the corresponding acoustic receiver. A controller of each system is configured to measure components of the compressional waves which may include velocities, distances, and/or accelerations, flexural components of the flexural waves which may include bending angle, outer and inner diameters, and associated dynamics of bending and radial expansion and/or contraction, and torsional components of the torsional waves which may include angular velocities, angular distances, and/or angular accelerations of the torsional waves.

The controller is also configured to demodulate the waves to determine data conveyed from the acoustic transmitter. For example, the data can include measurements from sensors downhole or instructions for a downhole tool. Based on the data, adjustments to the system can be made. For example, the data can include wellbore data such as temperature, pressure, casing collar locations, radiation levels, tool weights, magnetic field strength and direction, gravitational field strength and direction, acoustic readings, casing composition, wellbore composition, wellbore diameter, particle concentration, gas concentration, still images, video, fluid composition, and/or fluid density taken from sensors of the downhole tool. The data may also include status of the downhole tool, such as board temperature, current consumption, battery status, voltage or current levels, warnings and/or failure indicators. The data can be received by the acoustic receiver, and input into logs and/or simulations. Based on such data, adjustments may be made such as closing sections of the well, stimulation of the formation, or any other suitable actions. Additionally, if the data is being transmitted to an acoustic receiver disposed downhole and in communication with a downhole tool, the downhole tool may be adjusted, for example opening or closing valves, or for example enabling and disabling sensors.

The bi-directional acoustic telemetry system described above may be used in a fracturing or stimulation operation where the fluid is pumped either through the annulus of the conduit (e.g., coiled tubing or jointed pipe), directly through the string, or a combination of both. In another example, the bi-directional acoustic telemetry system described above may be used in a stimulation operation that involves pumping more than one fluid trough the string into the reservoir formation. The fluids used in the operation can be acid, solvents or a combination of both. In yet another example, the bi-directional acoustic telemetry system described above may be used in a wellbore operation that involves pumping a fluid either through the annulus of conduit (e.g., coiled tubing), directly through the string or a combination of both to prevent flow of water or unwanted gas from a reservoir formation. In yet another example, the bi-directional acoustic telemetry system described above may be used in a wellbore operation that requires the use of isolation tools like mechanical packers, single and straddle inflatable packers. In yet another example, the bi-directional acoustic telemetry system described above may be used to perform a stimulation operation involving water control or gas control treatment through an inflatable packer. In yet another example, the bi-directional acoustic telemetry system described above may be used in a wellbore operation that involves the use of an indexing tool to enter a lateral branch of a multilateral well; performing a stimulation operation, after entering the lateral with the above indexing tool; and obtaining wellbore measurements during the above treatments and using the data to adjust the treatments volumes, rates, fluids concentration, fluid type and properties in real-time. In yet another example, the bi-directional acoustic telemetry system described above may be used in a wellbore operation involving the use of perforating guns, as well as a wellbore operation requiring performance of a well test.

Numerous examples are provided herein to enhance understanding of the present disclosure. A specific set of statements are provided as follows.

Statement 1: A telemetry system is disclosed comprising: a first acoustic telemetry component operable to transmit a first acoustic signal from a downhole tool disposed in a wellbore to a surface, the first acoustic telemetry component including a downhole acoustic transmitter disposed in the wellbore and operable to transmit the first acoustic signal by creating waves to propagate in the wellbore, and an uphole acoustic receiver positioned uphole from the downhole acoustic transmitter and operable to detect the waves transmitted by the downhole acoustic transmitter; and a second acoustic telemetry component separate from the first acoustic telemetry component operable to transmit a second acoustic signal from the surface to the downhole tool disposed in the wellbore, the second acoustic telemetry component including an uphole acoustic transmitter operable to transmit the second acoustic signal by creating waves to propagate in the wellbore, and a downhole acoustic receiver positioned downhole from the uphole acoustic transmitter and operable to detect the waves transmitted by the uphole acoustic transmitter.

Statement 2: A telemetry system is disclosed according to Statement 1, further comprising a controller coupled with the uphole acoustic receiver, the controller determining components of the waves created by the downhole acoustic transmitter and determining the acoustic signal transmitted from the downhole acoustic transmitter based on the components of the waves.

Statement 3: A telemetry system is disclosed according to Statements 1 or 2, wherein the downhole acoustic transmitter and/or the uphole acoustic transmitter is coupled with a conduit disposed in the wellbore through a wellhead, and the downhole acoustic transmitter and/or the uphole acoustic transmitter creates the waves by impacting the conduit.

Statement 4: A telemetry system is disclosed according to any of preceding Statements 1-3, wherein the downhole acoustic transmitter and the uphole acoustic transmitter each include at least one of the following transmitter components: a piezoelectric transducer, a voice coil, a pinger, a siren, a mud pulse, and/or an electromagnetic acoustic transducer (EMAT).

Statement 5: A telemetry system is disclosed according to any of preceding Statements 1-5, wherein the downhole acoustic transmitter and the uphole acoustic transmitter include different transmitter components.

Statement 6: A telemetry system is disclosed according to any of preceding Statements 1-4, wherein the uphole acoustic receiver and the downhole acoustic receiver each include at least one of the following receiver components: an optical vibrometer, a light detection and ranging (LIDAR) system, an optical amplitude system, a microphone, a pressure sensor, an electromagnetic acoustic transducer (EMAT), proximity detector, acoustic ranging device, magnetic ranging device, a Hall effect sensor, and/or an accelerometer.

Statement 7: A telemetry system is disclosed according to any of preceding Statements 1-6 wherein the uphole acoustic receiver and the downhole acoustic receiver include different receiver components.

Statement 8: A telemetry system is disclosed according to any of preceding Statements 1-7, wherein the downhole acoustic transmitter and the uphole acoustic transmitter convert electric signals into the first and second acoustic signals, respectively.

Statement 9: A telemetry system is disclosed according to any of preceding Statements 1-8, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along a conduit disposed in the wellbore.

Statement 10: A telemetry system is disclosed according to any of preceding Statements 1-9, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along an annulus of the wellbore.

Statement 11: A telemetry system is disclosed according to any of preceding Statements 1-10, wherein the waves propagate along the annulus of the wellbore through a fluid.

Statement 12: A telemetry system is disclosed according to any of preceding Statements 1-11, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along an annulus of a conduit disposed in the wellbore.

Statement 13: A telemetry system is disclosed according to any of preceding Statements 1-12, wherein the waves propagate along the annulus of the conduit through a fluid.

Statement 14: A wellbore system is disclosed comprising: a conduit disposed in a wellbore; a first acoustic telemetry component operable to transmit a first acoustic signal from a downhole tool disposed in a wellbore to a surface, the first acoustic telemetry component including: a downhole acoustic transmitter disposed in a wellbore and operable to transmit the first acoustic signal by creating waves to propagate in the wellbore, and an uphole acoustic receiver positioned uphole from the downhole acoustic transmitter and operable to detect the waves transmitted by the downhole acoustic transmitter; and a second acoustic telemetry component separate from the first acoustic telemetry componentoperable to transmit a second acoustic signal from the surface to the downhole tool disposed in the wellbore, the second acoustic telemetry component including: an uphole acoustic transmitter operable to transmit the second acoustic signal by creating waves to propagate in the wellbore, and a downhole acoustic receiver positioned downhole from the uphole acoustic transmitter and operable to detect the waves transmitted by the uphole acoustic transmitter.

Statement 15: A wellbore system is disclosed according to Statement 14, further comprising a controller coupled with the uphole acoustic receiver, the controller determining components of the waves created by the downhole acoustic transmitter and determining the acoustic signal transmitted from the downhole acoustic transmitter based on the components of the waves.

Statement 16: A wellbore system is disclosed according to Statements 14 or 15, wherein the downhole acoustic transmitter and the uphole acoustic transmitter each include at least one of the following transmitter components: a piezoelectric transducer, a voice coil, a pinger, a siren, a mud pulse, a phased acoustic array, and/or an electromagnetic acoustic transducer (EMAT); wherein the downhole acoustic transmitter and the uphole acoustic transmitter include different transmitter components.

Statement 17: A wellbore system is disclosed according to any of preceding Statements 14-16, wherein the uphole acoustic receiver and the downhole acoustic receiver each include at least one of the following receiver components: an optical vibrometer, a light detection and ranging (LIDAR) system, an optical amplitude system, a microphone, a pressure sensor, an electromagnetic acoustic transducer (EMAT), proximity detector, acoustic ranging device, magnetic ranging device, a Hall effect sensor, and/or an accelerometer.

Statement 18: A wellbore system is disclosed according to Statement 17, wherein the uphole acoustic receiver and the downhole acoustic receiver include different receiver components.

Statement 19: A method for transmitting and receiving different acoustic signals in a wellbore system is disclosed comprising: transmitting, by a first acoustic telemetry component, a first acoustic signal from a downhole tool disposed in a wellbore to a surface; transmitting, by a second acoustic telemetry component separate from the first acoustic telemetry component, a second acoustic signal from the surface to the downhole tool.

Statement 20: A method is disclosed according to Statement 19, further comprising utilizing the first acoustic telemetry component and the second acoustic telemetry component in a wellbore operation, the wellbore operation including at least one of: a fracturing operation; a stimulation operation; a fluid being pumped either through an annulus of a conduit, directly through a string, or a combination of both to prevent a flow of fluid from a reservoir formation; utilizing an isolation tool; a stimulation operation involving a water control or gas control treatment through an inflatable packer; utilizing an indexing tool to enter a lateral branch of a multilateral well; a stimulation operation performed after entering a lateral branch of a multilateral well with an indexing tool; obtaining measurements during a treatment and using the measurements to adjust a treatment volume, rate, fluid concentration, fluid type or property in real-time; utilizing a perforating gun; and/or performance of a well test.

Statement 21: A method is disclosed according to Statements 19 or 20, wherein the downhole acoustic transmitter and the uphole acoustic transmitter include different transmitter components, and the uphole acoustic receiver and the downhole acoustic receiver include different receiver components.

The disclosures shown and described above are only examples. Even though numerous characteristics and advantages of the present technology have been set forth in the foregoing description, together with details of the structure and function of the present disclosure, the disclosure is illustrative only, and changes may be made in the detail, especially in matters of shape, size and arrangement of the parts within the principles of the present disclosure to the full extent indicated by the broad general meaning of the terms used in the attached claims. It will therefore be appreciated that the examples described above may be modified within the scope of the appended claims.

Claims

1. A telemetry system comprising:

a first acoustic telemetry component to transmit a first acoustic signal from a downhole tool disposed in a wellbore to a surface, the first acoustic telemetry component including a downhole acoustic transmitter disposed in the wellbore to transmit the first acoustic signal by creating waves to propagate in the wellbore, and an uphole acoustic receiver positioned uphole from the downhole acoustic transmitter and to detect the waves transmitted by the downhole acoustic transmitter; and

a second acoustic telemetry component separate from the first acoustic telemetry component to transmit a second acoustic signal from the surface to the downhole tool disposed in the wellbore, the second acoustic telemetry component including an uphole acoustic transmitter to transmit the second acoustic signal by creating waves to propagate in the wellbore, and a downhole acoustic receiver positioned downhole from the uphole acoustic transmitter to detect the waves transmitted by the uphole acoustic transmitter.

2. The telemetry system of claim 1, further comprising a controller coupled with the uphole acoustic receiver, the controller determining components of the waves created by the downhole acoustic transmitter and determining the acoustic signal transmitted from the downhole acoustic transmitter based on the components of the waves.

3. The telemetry system of claim 1, wherein the downhole acoustic transmitter and/or the uphole acoustic transmitter is coupled with a conduit disposed in the wellbore through a wellhead, and the downhole acoustic transmitter and/or the uphole acoustic transmitter creates the waves by impacting the conduit.

4. The telemetry system of claim 1, wherein the downhole acoustic transmitter and the uphole acoustic transmitter each include at least one of the following transmitter components: a piezoelectric transducer, a voice coil, a pinger, a siren, a mud pulse, a phased acoustic array, and/or an electromagnetic acoustic transducer (EMAT).

5. The telemetry system of claim 4, wherein the downhole acoustic transmitter and the uphole acoustic transmitter include different transmitter components.

6. The telemetry system of claim 1, wherein the uphole acoustic receiver and the downhole acoustic receiver each include at least one of the following receiver components: an optical vibrometer, a light detection and ranging (LIDAR) system, an optical amplitude system, a microphone, a pressure sensor, an electromagnetic acoustic transducer (EMAT), proximity detector, acoustic ranging device, magnetic ranging device, a Hall effect sensor, and/or an accelerometer.

7. The telemetry system of claim 6, wherein the uphole acoustic receiver and the downhole acoustic receiver include different receiver components.

8. The telemetry system of claim 1, wherein the downhole acoustic transmitter and the uphole acoustic transmitter convert electric signals into the first and second acoustic signals, respectively.

9. The telemetry system of claim 1, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along a conduit disposed in the wellbore.

10. The telemetry system of claim 1, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along an annulus of the wellbore.

11. The telemetry system of claim 10, wherein the waves propagate along the annulus of the wellbore through a fluid.

12. The telemetry system of claim 1, wherein at least one of the downhole acoustic transmitter and the uphole acoustic transmitter transmit the corresponding first and/or second acoustic signal by creating the waves to propagate along an annulus of a conduit disposed in the wellbore.

13. The telemetry system of claim 12, wherein the waves propagate along the annulus of the conduit through a fluid.

14. A wellbore system comprising:

a conduit disposed in a wellbore;

a first acoustic telemetry component to transmit a first acoustic signal from a downhole tool disposed in a wellbore to a surface, the first acoustic telemetry component including a downhole acoustic transmitter disposed in a wellbore to transmit the first acoustic signal by creating waves to propagate in the wellbore, and an uphole acoustic receiver positioned uphole from the downhole acoustic transmitter and to detect the waves transmitted by the downhole acoustic transmitter; and

a second acoustic telemetry component separate from the first acoustic telemetry component to transmit a second acoustic signal from the surface to the downhole tool disposed in the wellbore, the second acoustic telemetry component including an uphole acoustic transmitter to transmit the second acoustic signal by creating waves to propagate in the wellbore, and a downhole acoustic receiver positioned downhole from the uphole acoustic transmitter and to detect the waves transmitted by the uphole acoustic transmitter.

15. The wellbore system of claim 14, further comprising a controller coupled with the uphole acoustic receiver, the controller determining components of the waves created by the downhole acoustic transmitter and determining the acoustic signal transmitted from the downhole acoustic transmitter based on the components of the waves.

16. The wellbore system of claim 14, wherein the downhole acoustic transmitter and the uphole acoustic transmitter each include at least one of the following transmitter components: a piezoelectric transducer, a voice coil, a pinger, a siren, a mud pulse, a phased acoustic array, and/or an electromagnetic acoustic transducer (EMAT); wherein the downhole acoustic transmitter and the uphole acoustic transmitter include different transmitter components.

17. The telemetry wellbore system of claim 14, wherein the uphole acoustic receiver and the downhole acoustic receiver each include at least one of the following receiver components: an optical vibrometer, a light detection and ranging (LIDAR) system, an optical amplitude system, a microphone, a pressure sensor, an electromagnetic acoustic transducer (EMAT), proximity detector, acoustic ranging device, magnetic ranging device, a Hall effect sensor, and/or an accelerometer.

18. The wellbore system of claim 17, wherein the uphole acoustic receiver and the downhole acoustic receiver include different receiver components.

19. A method for transmitting and receiving different acoustic signals in a wellbore system, the method comprising:

transmitting, by a first acoustic telemetry component, a first acoustic signal from a downhole tool disposed in a wellbore to a surface;

transmitting, by a second acoustic telemetry component separate from the first acoustic telemetry component, a second acoustic signal from the surface to the downhole tool.

20. The method of claim 19, further comprising: utilizing the first acoustic telemetry component and the second acoustic telemetry component in a wellbore operation including at least one of: a fracturing operation; a stimulation operation; a fluid being pumped either through an annulus of a conduit, directly through a string, or a combination of both to prevent a flow of fluid from a reservoir formation; utilizing an isolation tool; a stimulation operation involving a water control or gas control treatment through an inflatable packer;

utilizing an indexing tool to enter a lateral branch of a multilateral well; a stimulation operation performed after entering a lateral branch of a multilateral well with an indexing tool; obtaining measurements during a treatment and using the measurements to adjust a treatment volume, rate, fluid concentration, fluid type or property in real-time; utilizing a perforating gun; and/or performance of a well test.