Transmitter and receiver interface for downhole logging

A system may comprise a transmitter amplifier, a first isolation module, a first transducer, a first receiver, a second isolation module, a second transducer, wherein the second isolation module is connected to the second transducer, and a second receiver, wherein the second isolation module and the second transducer are connected to the second receiver. A method may comprise disposing a downhole tool into a wellbore, transmitting an excitation signal from the transmitter amplifier to the first transducer and the second transducer through the first isolation module and second isolation module, and creating a pressure pulse from the first transducer and the second transducer, sensing the echo with the first transducer and the second transducer, converting the echo into a received signal at the first transducer and the second transducer, and transmitting the received signal to the first receiver and the second receiver.

BACKGROUND

Wellbores drilled into subterranean formations may enable recovery of desirable fluids (e.g., hydrocarbons) using any number of different techniques. Currently, drilling operations may identify subterranean formations through a bottom hole assembly if the subterranean formation is disposed horizontal to the bottom hole assembly. During operations, measurement operations may utilize a measurement assembly that may produce a pressure pulse, which may be recorded along with the echoes. Therefore, currently simultaneous excitation and sensing in a synchronous manner may be preferred in many types of logging tools where multiple actuators/sensors may be present. For example, accurate downhole caliper logging requires common excitation and then same time measurement from multiple ultrasonic transducers to limit tool motion impacts on the caliper measurement. A convenient and commonly used approach is to duplicate multiple transmitter/receiver channels and control them digitally to act at the same time. However, downhole tools usually have a lot of constraints on power and space, which requires simple, efficient hardware electronics design. Duplicating channels not only waste power and space downhole, there are also robustness issues when a lot of channels need to be controlled at the same time.

DETAILED DESCRIPTION

This disclosure may generally relate to a system and method for producing an excitation without saturating a receiver module and, more particularly, to a compact passive design that may allow multiple transducers to have common high voltage excitation path but with separate receiver paths without a digital system to intervene.

FIG. 1illustrates an example of drilling system100. As illustrated, wellbore102may extend from a wellhead104into a subterranean formation106from a surface108. Generally, wellbore102may include horizontal, vertical, slanted, curved, and other types of wellbore geometries and orientations. Wellbore102may be cased or uncased. In examples, wellbore102may include a metallic member. By way of example, the metallic member may be a casing, liner, tubing, or other elongated steel tubular disposed in wellbore102.

As illustrated, wellbore102may extend through subterranean formation106. As illustrated inFIG. 1, wellbore102may extend generally vertically into the subterranean formation106, however, wellbore102may extend at an angle through subterranean formation106, such as horizontal and slanted wellbores. For example, althoughFIG. 1illustrates a vertical or low inclination angle well, high inclination angle or horizontal placement of the well and equipment may be possible. It should further be noted that whileFIG. 1generally depicts land-based operations, those skilled in the art may recognize that the principles described herein are equally applicable to subsea operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.

As illustrated, a drilling platform110may support a derrick112having a traveling block114for raising and lowering drill string116. Drill string116may include, but is not limited to, drill pipe and coiled tubing, as generally known to those skilled in the art. A kelly118may support drill string116as it may be lowered through a rotary table120. A drill bit122may be attached to the distal end of drill string116and may be driven either by a downhole motor and/or via rotation of drill string116from surface108. Without limitation, drill bit122may include, roller cone bits, PDC bits, natural diamond bits, any hole openers, reamers, coring bits, and the like. As drill bit122rotates, it may create and extend wellbore102that penetrates various subterranean formations106. A pump124may circulate drilling fluid through a feed pipe126through kelly118, downhole through interior of drill string116, through orifices in drill bit122, back to surface108via annulus128surrounding drill string116, and into a retention pit132.

With continued reference toFIG. 1, drill string116may begin at wellhead104and may traverse wellbore102. Drill bit122may be attached to a distal end of drill string116and may be driven, for example, either by a downhole motor and/or via rotation of drill string116from surface108. Drill bit122may be a part of bottom hole assembly130at the distal end of drill string116. Bottom hole assembly130may further include tools for look-ahead resistivity applications. As will be appreciated by those of ordinary skill in the art, bottom hole assembly130may be a measurement-while drilling (MWD) or logging-while-drilling (LWD) system.

Bottom hole assembly130may comprise any number of tools, transmitters, and/or receivers to perform downhole measurement operations. For example, as illustrated inFIG. 1, bottom hole assembly130may include a measurement assembly134. It should be noted that measurement assembly134may make up at least a part of bottom hole assembly130. Without limitation, any number of different measurement assemblies, communication assemblies, battery assemblies, and/or the like may form bottom hole assembly130with measurement assembly134. Additionally, measurement assembly134may form bottom hole assembly130itself. In examples, measurement assembly134may comprise at least one transducer136a, which may be disposed at the surface of measurement assembly134. It should be noted that whileFIG. 1illustrates a single transducer136a, there may be any number of transducers disposed on measurement assembly134. While illustrations may show transducers136a-c, as seen below, references to transducer136aapply to all transducers within the disclosure. Without limitation, transducers may be referred to as a transceiver. Without limitation, transducer136amay also be disposed within measurement assembly134and there may be four other transducers that may be disposed ninety degrees from each other. However, it should be noted that there may be any number of transducers disposed along bottom hole assembly130at any degree from each other. Transducer136a, and any other transducer, may function and operate to generate an acoustic pressure pulse that travels through borehole fluids. In examples, transducers136amay further sense and acquire the reflected pressure wave which is modulated (i.e., reflected as an echo) by the borehole wall. During measurement operations, the travel time of the pulse wave from transmission to recording of the echo may be recorded. This information may lead to determining a radius of the borehole, which may be derived by the fluid sound speed. By analyzing the amplitude of the echo signal, the acoustic impedance may also be derived. Without limitation, transducers136amay be made of piezo-ceramic crystals, or optionally magnetostrictive materials or other materials that generate an acoustic pulse when activated electrically or otherwise. In examples, transducers136amay also include backing materials and matching layers. It should be noted that transducers136aand assemblies housing transducers136amay be removable and replaceable, for example, in the event of damage or failure.

Without limitation, bottom hole assembly130may be connected to and/or controlled by information handling system138, which may be disposed on surface108. Without limitation, information handling system138may be disposed down hole in bottom hole assembly130. Processing of information recorded may occur down hole and/or on surface108. Processing occurring downhole may be transmitted to surface108to be recorded, observed, and/or further analyzed. Additionally, information recorded on information handling system138that may be disposed down hole may be stored until bottom hole assembly130may be brought to surface108. In examples, information handling system138may communicate with bottom hole assembly130through a communication line (not illustrated) disposed in (or on) drill string116. In examples, wireless communication may be used to transmit information back and forth between information handling system138and bottom hole assembly130. Information handling system138may transmit information to bottom hole assembly130and may receive as well as process information recorded by bottom hole assembly130. In examples, a downhole information handling system (not illustrated) may include, without limitation, a microprocessor or other suitable circuitry, for estimating, receiving and processing signals from bottom hole assembly130. Downhole information handling system (not illustrated) may further include additional components, such as memory, input/output devices, interfaces, and the like. In examples, while not illustrated, bottom hole assembly130may include one or more additional components, such as analog-to-digital converter, filter, and amplifier, among others, that may be used to process the measurements of bottom hole assembly130before they may be transmitted to surface108. Alternatively, raw measurements from bottom hole assembly130may be transmitted to surface108.

Any suitable technique may be used for transmitting signals from bottom hole assembly130to surface108, including, but not limited to, wired pipe telemetry, mud-pulse telemetry, acoustic telemetry, and electromagnetic telemetry. While not illustrated, bottom hole assembly130may include a telemetry subassembly that may transmit telemetry data to surface108. At surface108, pressure transducers (not shown) may convert the pressure signal into electrical signals for a digitizer (not illustrated). The digitizer may supply a digital form of the telemetry signals to information handling system138via a communication link140, which may be a wired or wireless link. The telemetry data may be analyzed and processed by information handling system138.

As illustrated, communication link140(which may be wired or wireless, for example) may be provided that may transmit data from bottom hole assembly130to an information handling system138at surface108. Information handling system138may include a personal computer141, a video display142, a keyboard144(i.e., other input devices), and/or non-transitory computer-readable media146(e.g., optical disks, magnetic disks) that can store code representative of the methods described herein. In addition to, or in place of processing at surface108, processing may occur downhole.

As discussed below, methods may be utilized by information handling system138to determine properties of subterranean formation106. Information may be utilized to produce an image, which may be generated into, one, two or three-dimensional models of subterranean formation106. These models may be used for well planning, (e.g., to design a desired path of wellbore102). Additionally, they may be used for planning the placement of drilling systems within a prescribed area. This may allow for the most efficient drilling operations to reach a subsurface structure. During drilling operations, measurements taken within wellbore102may be used to adjust the geometry of wellbore102in real-time to reach a geological target. Measurements collected from bottom hole assembly130of the formation properties may be used to steer drilling system100toward a subterranean formation106. Optionally, these measurements may be used to plan well completion operations, including but not limited to placement of packers, hydraulic fracturing, cementing, acidizing or the placement of mud-loss mitigation treatments. Optionally, these measurements may be used for reservoir or over-burden characterization purposes.

FIG. 2illustrates a cross-sectional view of an example of well measurement system200. As illustrated, well measurement system200may comprise downhole tool202attached a vehicle204. In examples, it should be noted that downhole tool202may not be attached to a vehicle204. Downhole tool202may be supported by rig206at surface108. Downhole tool202may be tethered to vehicle204through conveyance210. Conveyance210may be disposed around one or more sheave wheels212to vehicle204. Conveyance210may include any suitable means for providing mechanical conveyance for downhole tool202, including, but not limited to, wireline, slickline, coiled tubing, pipe, drill pipe, downhole tractor, or the like. In some embodiments, conveyance210may provide mechanical suspension, as well as electrical and/or optical connectivity, for downhole tool202. Conveyance210may comprise, in some instances, a plurality of electrical conductors and/or a plurality of optical conductors extending from vehicle204, which may provide power and telemetry. In examples, an optical conductor may utilize a battery and/or a photo conductor to harvest optical power transmitted from surface108. Conveyance210may comprise an inner core of seven electrical conductors covered by an insulating wrap. An inner and outer steel armor sheath may be wrapped in a helix in opposite directions around the conductors. The electrical and/or optical conductors may be used for communicating power and telemetry between vehicle204and downhole tool202. Information from downhole tool202may be gathered and/or processed by information handling system138. For example, signals recorded by downhole tool202may be stored in memory and then processed by downhole tool202. The processing may be performed real-time during data acquisition or after recovery of downhole tool202. Processing may alternatively occur downhole or may occur both downhole and at surface. In some embodiments, signals recorded by downhole tool202may be conducted to information handling system138by way of conveyance210. Information handling system138may process the signals, and the information contained therein may be displayed for an operator to observe and stored for future processing and reference. Information handling system138may also contain an apparatus for supplying control signals and power to downhole tool202.

Systems and methods of the present disclosure may be implemented, at least in part, with information handling system138. While shown at surface108, information handling system138may also be located at another location, such as remote from borehole224. Information handling system138may include any instrumentality or aggregate of instrumentalities operable to compute, estimate, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system138may be a personal computer141, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. Information handling system138may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling system138may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard144, a mouse, and a video display142. Information handling system138may also include one or more buses operable to transmit communications between the various hardware components. Furthermore, video display142may provide an image to a user based on activities performed by personal computer141. For example, producing images of geological structures created from recorded signals. By way of example, a video display unit may produce a plot of depth versus the two cross-axial components of the gravitational field and versus the axial component in borehole coordinates. The same plot may be produced in coordinates fixed to the Earth, such as coordinates directed to the North, East and directly downhole (Vertical) from the point of entry to the borehole. A plot of overall (average) density versus depth in borehole or vertical coordinates may also be provided. A plot of density versus distance and direction from the borehole versus vertical depth may be provided. It should be understood that many other types of plots are possible when the actual position of the measurement point in North, East and Vertical coordinates is taken into account. Additionally, hard copies of the plots may be produced in paper logs for further use.

Alternatively, systems and methods of the present disclosure may be implemented, at least in part, with non-transitory computer-readable media146. Non-transitory computer-readable media146may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Non-transitory computer-readable media146may include, for example, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.

In examples, rig206includes a load cell (not shown) which may determine the amount of pull on conveyance210at the surface of borehole224. Information handling system138may comprise a safety valve (not illustrated) which controls the hydraulic pressure that drives drum226on vehicle204which may reel up and/or release conveyance210which may move downhole tool202up and/or down borehole224. The safety valve may be adjusted to a pressure such that drum226may only impart a small amount of tension to conveyance210over and above the tension necessary to retrieve conveyance210and/or downhole tool202from borehole224. The safety valve is typically set a few hundred pounds above the amount of desired safe pull on conveyance210such that once that limit is exceeded, further pull on conveyance210may be prevented.

As illustrated inFIG. 2, downhole tool202may include measurement assembly134. It should be noted that measurement assembly134may make up at least a part of downhole tool202. Without limitation, any number of different measurement assemblies, communication assemblies, battery assemblies, and/or the like may form downhole tool202with measurement assembly134. Additionally, measurement assembly134may form downhole tool202itself. In examples, measurement assembly134may comprise at least one transducer136a, which may be disposed at the surface of measurement assembly134. As illustrated, transducers136a-cmay also be disposed within measurement assembly134. Without limitation, there may be four transducers that may be disposed ninety degrees from each other. However, it should be noted that there may be any number of transducers disposed along bottom hole assembly130at any degree from each other. Transducers may function and operate to generate and receive acoustic pulses in the borehole fluid.

FIG. 3illustrates a close-up view of an example of measurement assembly134. As illustrated, measurement assembly134may include at least one battery section300and at least one instrument section302. Battery section300may operate and function to enclose and/or protect at least one battery that may be disposed in battery section300. Without limitation, battery section300may also operate and function to power measurement assembly134. Specifically, battery section300may power at least one transducer136a, which may be disposed at any end of battery section300in instrument section302.

Instrument section302may house at least one transducer136a. Transducers may function and operate to generate and record excitations within a borehole. For example, during operations, transducer136amay transmit an excitation into wellbore102(e.g., referring toFIG. 1). Without limitation, the excitation may be in the form of a pressure pulse, current, electromagnetic field, radio frequency, and/or any other suitable medium. This may allow for transducer136ato be an ultrasonic device, acoustic device, electromagnetic device, radio frequency device, and/or the like. In examples, may be made of piezo-ceramic crystals, or optionally magnetostrictive materials or other materials that generate an acoustic pulse when activated electrically or otherwise. In one or more examples, transducers136amay also include backing materials and matching layers. Additionally, transducer136amay include coils, antennas, and/or the like. It should be noted that transducers136aand/or instrument section302may be removable and replaceable, for example, in the event of damage or failure.

During operations, in examples where transducer136amay emit a pressure wave, specifically an ultrasonic pressure pulse wave, the pressure pulse may have a frequency range from about 10 kHz to about 500 kHz, with a center of about 250 kHz. It should be noted that the pulse signal may be emitted with different frequency content. Recordings and/or measurements taken by transducer136amay be transmitted to information handling system138by any suitable means, as discussed above. Transmission may be performed in real-time (transmitted to the surface via mud-pulse, wired-pipe or other telemetry) or post-drill (from data stored in the tool memory and recovered at the surface during tripping).

In examples, transducers136amay further sense and record the transmission of the excitation. The excitation may travel from transducer136aand reflect off a borehole wall. The reflected excitation is defined as an echo, which is recorded by transducer136a. Without limitation, transducers136amay measure the excitation as it travels from transducer136aand is reflected back to transducer136aas an echo.

Measurements may be used to form images of the surrounding borehole and/or subterranean formation. To generate these images, measurement assembly134may utilize one or more transducers136apositioned at varying azimuths around the circumference of measurement assembly134. In examples, each transducer136amay operate and function independently emitting an excitation and detecting its reflection from the borehole wall as a reflected echo.

The amplitude of the received echo at each transducer136amay be stacked into composite spatial bins or pixels (typically of 1- or 2-degree width and ¼ inch (0.6 cm) height) at each depth. Stacking may be defined as taking the mean, or median, or harmonic mean, or trimmed-mean (where the larger and smaller outliers are discarded) of the values of all the reflection amplitude measurements falling into each pixel. This list of definitions of the term stacking should not be taken to be exhaustive and those skilled in the art could easily derive alternative means of averaging. However, irrespective of the stacking method used the resulting image may be a sum of contributions from two or more transducers.

FIG. 4illustrates an example of device schematic400disposed within measuring assembly134(e.g., referring toFIG. 3). As illustrated inFIG. 4, measuring assembly134may comprise a digital control system402, a transmitter amplifier404, isolation modules identified as406a-c(ISO1˜n), transducers identified as136a-c(XDC1˜n), receivers410a-c(RX1˜n) and an analog digital controller (ADC) module412. It should be noted that isolation modules406a-cmay be identified collectively as isolation modules406a-cor individually as first isolation module406a, second isolation module406b, and third isolation module406c. Likewise, transducers136a-cmay be identified collectively as transducers136a-cand individually as first transducer136a, second transducer136b, and third transducer136c, and receivers410a-cmay be identified collectively as receivers410a-cand individually as first receiver410a, second receiver410b, and third receiver410c. It should be noted that each of transducers136a-cmay be referred to as a “pinger” and/or transceiver. During operations, digital control system402may operate and/or function to control transmitter amplifier404. For example, digital control system402may activate transmitter amplifier404to emit an excitation. Transmitter amplifier404may operate and/or function to transmit a high voltage signals for a fixed time interval to at least one of the isolation modules406a-c, simultaneously. It should be noted that “high voltage” is defined as 100 volts or greater. During the transmission of the high voltage signals, the high voltage may pass through at least one of the isolation modules406a-c. Without limitation, there may be at least one of the isolation modules406a-cfor each transmitter amplifier404. In examples, each of the isolation modules406a-cmay pass the high voltage excitation to one of the directly connected transducers136a-cand one of the directly connected receivers410a-c. For example, first isolation module406amay pass the high voltage excitation directly to the first transducer136aand the first receiver410a.

Transducers136a-cmay exert (e.g., broadcast, produce, and/or transmit) an excitation into wellbore102(e.g., referring toFIG. 1). An excitation may be a pressure pulse, an electromagnetic field, a magnetic field, a radio wave, acoustic wave, ultrasonic wave, and/or the like. Without limitation, transducers136a-cmay be an ultrasonic transducer, an EM transceiver coil, or an NMR antenna. It should be noted that an application with different transducers136a-cor transceivers (must be able to both transmit and receive) may utilize this circuitry topology, such as the downhole electromagnetic tool with electromagnetic sensors. The signal does not have to be differential as shown inFIG. 5. A single-ended signal may operate and function with this circuit topology. In an example of downhole operations, the excitation may be emitted from each of transducers136a-cas a pressure pulse. The pressure pulse may reflect off a wall of wellbore102. It should be noted that the pressure pulse may be reflected off the wall of wellbore102in the form of an echo. The echo may be sensed, measured, and/or recorded by each of transducers136a-c. The received signal (e.g., echo), usually low voltage (millivolts), may be isolated from flowing back to transmitter amplifier404or any other receiver channels. For example, each of receivers410a-cmay capture the response (i.e., received signal) from each of transducers136a-c. The received signal may be amplified by each of receivers410a-cand transmitted to ADC412. ADC412may digitize the received signal then send the digitized signal to digital control system402for storage, processing, and/or further transmission to an off-site location. From the digitized signal, digital control system402may alter operations and control of transmitter amplifier404. Therefore, each channel (i.e., first transducer136a, second transducer136b, third transducer136c) may share a common source of the high voltage driving signal but may remain independent in terms of receiving a signal (i.e., echo) without interfering with each other.

FIG. 5is an example of a circuit diagram500disposed in measuring assembly134(e.g., referring gotFIG. 1). Additionally, circuit diagram500illustrates the physical setup for device schematic400(i.e., referring toFIG. 4). As illustrated inFIG. 5, transmitter amplifier404generates the high voltage signal from a voltage source506. The voltage may traverse through an inductor508to stabilize the signal. Inductor508may be connected to MOSFETs510a-d, capacitors512a, b, and resistor514, which are connected in parallel, transmitter amplifier404may be either linear or switching types. The high voltage signal generated from transmitter amplifier404may traverse through isolation modules406a-c. Each of the isolation modules406a-cmay comprise at least one diode502, discussed below. Traversing through isolation modules406a-c, the high voltage signal may activate and drive transducers136a-cto produce and emit an excitation, such as a pressure pulse, into wellbore102(i.e., referring toFIG. 2). Simultaneously, the high voltage signal may be blocked by at least one switch504from traversing to a particular one of the receivers410a-c. A switch504may be associated with each of the receivers410a-c.

Switch504may engage during reflecting receiving time (e.g., recording an echo or reflected excitation) where switch504may allow a low voltage signal through and block the high voltage pulse signal from damaging the associated one of the receivers410a-c. Switch504may prevent the pulse signal from entering and causing damage to the associated one of the receivers410a-c. It should be noted that switch504may be controlled by the digital control system402(i.e., referring toFIG. 4). This may allow switch504to be active or passive. For example, if switch504is active, then it may be directly controlled by another device such as digital control system402. If the switch504is passive, then switch504may act autonomously by opening and/or closing based at least in part on the presence of a high voltage signal. After emitting the ultrasonic pressure pulse, the ultrasonic pressure pulse may reflect off a wall of wellbore402as an echo. The echo may be sensed, measured, and/or recorded by transducers136a-c(e.g., referring toFIG. 1). The received signal may be a low voltage signal. A low voltage signal may pass through switch504, which may still be engaged, to the associated one of the receivers410a-c. One of the isolation modules406a-cmay prevent the received low voltage signal from flowing back to transmitter amplifier404and may also prevent each receiver channel (e.g., each receiver channel may be each individual one of receivers410a-c) from interfering with each other. Receivers410a-cmay be amplifiers followed by analog-to-digital converters (not illustrated) which may transmit digital signals to digital control system402(i.e., referring toFIG. 4).

Each of the isolation module406a-c, discussed above, may be a series of diodes502that may be disposed in chains. Additionally, diodes502may be paired with other diodes502and diode chains may be paired with other diode chains. For example, the number of diode pairs in each chain may be pre-determined by a perceived voltage of the received signal. If the received signal may be large in amplitude, more diodes pairs may be needed to block the received signal from flowing back. For example, if the received signal has peak amplitude around 1 volt, and each back to back diode pair has 0.7V forward voltage drop, one or more of the isolation modules406a-cmay include at least 2 pairs of diodes (0.7V×2) to block the received signal from passing through. Additionally, the total forward voltage drop of diodes502in the chains may need to be considered and for the excitation pulse transmitted from transmitter amplifier404.

FIGS. 6 and 7are example graphs of simulated data demonstrating the operation of the circuitry set-up for measuring assembly134(e.g., referring toFIG. 3). As seen in the graph ofFIG. 6an 80V peak to peak firing signal generated by transmitter amplifier404(e.g., referring toFIG. 4) is shown. The firing signal generated and shown inFIG. 6may be utilized across multiple receivers, for example410a-c. This may be possible due to the peak to peak firing signal that is generated across the firing signal.FIG. 7shows the result from three receivers410a-c(e.g., a three channels transceiver system). In this example, each of transducers136a-c(i.e., referring toFIG. 4) may be set-up with different targets, which may allow each transducer136a-cto have a distinct response. InFIG. 7, a response from each channel is captured and plotted as a first channel700, a second channel702, and a third channel704. It may be seen that the excitation signal from transmitter amplifier404(e.g., referring toFIG. 4) are transmitted and/or recorded at the same time on all channels (e.g., receivers410a-c), and each channel received reflection has the same feature (frequency) from the excitation signal. But there is no crosstalk between different receiver channels and each channel has different arrival time, amplitude, and/or phase.

It will be appreciated by those of ordinary skill in the art, exemplary examples of the system and individual devices of the present disclosure may be used in a variety of subterranean applications, including imaging. Exemplary examples of the system and devices may be introduced into a subterranean formation and utilized to image a borehole and the surrounding formation. While the preceding discussion is directed to the use of downhole imaging, those of ordinary skill in the art will also appreciate that it may be desirable to utilize other types of imaging in the marine field and medical field, in accordance with examples of the present disclosure.

While methods disclosed above may be used for devices and systems related to oil field devices, the methods are not limited to the oil field. Without limitation, the methods, systems, devices, their function and operation may be utilized in the medical and/or marine fields.

Statement 1: A system may comprise a transmitter amplifier, a first isolation module, where the transmitter amplifier is connected to the first isolation module, a first transducer, wherein the first isolation module is connected to the first transducer, a first receiver, wherein the first isolation module and the first transducer are connected to the first receiver, a second isolation module, where the transmitter amplifier is connected to the second isolation module, a second transducer, wherein the second isolation module is connected to the second transducer, and a second receiver, wherein the second isolation module and the second transducer are connected to the second receiver.

Statement 2. The system of statement 1, wherein the transmitter amplifier is configured to transmit an excitation signal.

Statement 3. The system of statement 2, wherein the excitation signal transverses from the transmitter amplifier to the first transducer through the first isolation module and to the second transducer through the second isolation module.

Statement 4. The system of statement 3, wherein the first transducer and the second transducer are configured to emit a pressure pulse.

Statement 5. The system of statement 1 or 2, wherein the first isolation module and the second isolation module each individually comprise at least one diode.

Statement 6. The system of statement 5, wherein the at least one diode is paired with a second diode.

Statement 7. The system of statement 1, 2, or 5, wherein the system further comprises at least one switch disposed between the first transducer and the first isolation module, and between the first transducer and the first receiver.

Statement 8. The system of statement 7, wherein the system further comprises another switch disposed between the second transducer and the second isolation module, and between the second transducer and the second receiver.

Statement 9. The system of statement 8, wherein the at least one switch prevents a high voltage from entering the first receiver and the second receiver.

Statement 10. The system of statement 1, 2, 5, or 7, wherein a digital control system is configured to control the transmitter amplifier.

Statement 11. A downhole tool may comprise a digital control system, a transmitter amplifier, wherein the transmitter amplifier is controlled by the digital control system and configured to transmit an excitation signal, a first isolation module, where the transmitter amplifier is connected to the first isolation module, wherein the excitation signal traverses from the transmitter amplifier to the first isolation module, a first transducer, wherein the first isolation module is connected to the first transducer, wherein the first transducer is configured to emit a pressure pulse, a first receiver, wherein the first isolation module and the first transducer are connected to the first receiver, a second isolation module, where the transmitter amplifier is connected to the second isolation module wherein the excitation signal traverses from the transmitter amplifier to the second isolation module, a second transducer, wherein the second isolation module is connected to the second transducer, wherein the second transducer is configured to emit the pressure pulse, a second receiver, wherein the second isolation module and the second transducer are connected to the second receiver, and an analog to digital converter connected to the first receiver and the second receiver.

Statement 12. The downhole tool of statement 11, wherein the pressure pulse has a frequency range of about 10 kHz to about 500 kHz.

Statement 13. The downhole tool of statements 11-12, wherein the first isolation module and the second isolation module comprise at least one chain of diodes.

Statement 14. The downhole tool of statements 11-13, further comprising at least one switch configured to block high voltage and allow low voltage to pass, disposed between the first transducer and the first isolation module, and the first receiver.

Statement 15. The downhole tool of statement 14, further comprising another switch configured to block high voltage and allow low voltage to pass, disposed between the second transducer and the second isolation module, and the second receiver.

Statement 16. A method may comprise disposing a downhole tool into a wellbore, wherein the downhole tool comprise a digital control system, a transmitter amplifier, wherein the transmitter amplifier is controlled by the digital control system and configured to transmit an excitation signal, a first isolation module, where the transmitter amplifier is connected to the first isolation module, wherein the excitation signal traverses from the transmitter amplifier to the first isolation module, a first transducer, wherein the first isolation module is connected to the first transducer, wherein the first transducer is configured to emit a pressure pulse, a first receiver, wherein the first isolation module and the first transducer are connected to the first receiver, a second isolation module, where the transmitter amplifier is connected to the second isolation module wherein the excitation signal traverses from the transmitter amplifier to the second isolation module, a second transducer, wherein the second isolation module is connected to the second transducer, wherein the second transducer is configured to emit the pressure pulse, a second receiver, wherein the second isolation module and the second transducer are connected to the second receiver, and an analog to digital converter. The method may further comprise transmitting an excitation signal from the transmitter amplifier to the first transducer and the second transducer through the first isolation module and second isolation module, creating a pressure pulse from the first transducer and the second transducer, wherein the pressure pulse reflects off a wall of a wellbore as an echo, sensing the echo with the first transducer and the second transducer, converting the echo into a received signal at the first transducer and the second transducer, and transmitting the received signal to the first receiver and the second receiver.

Statement 17. The method of statement 16, further comprising sending the received signal from the first receiver and the second receiver to the analog to digital converter.

Statement 18. The method of statement 17, further comprising digitizing the received signal to a digital signal at the analog to digital converter.

Statement 19. The method of statement 18, further comprising sending the digital signal from the analog to digital converter to a digital control system.

Statement 20. The method of statement 16 and 17, wherein the first transducer and second transducer are ultrasonic transducers.