WO2017062006A1

WO2017062006A1 - Communication to a downhole tool by acoustic waveguide transfer

Info

Publication number: WO2017062006A1
Application number: PCT/US2015/054612
Authority: WO
Inventors: Gabriel COSS; Bharat B. PAWAR
Original assignee: Halliburton Energy Services, Inc.
Priority date: 2015-10-08
Filing date: 2015-10-08
Publication date: 2017-04-13
Also published as: US20180230799A1; GB201803333D0; GB2557773A; CA2997618A1

Abstract

Systems, methods and apparatuses for communication between a surface of a wellbore and a downhole location of a wellbore via acoustic waveguide transfer. A first device can transmit an acoustic signal through a wellbore waveguide that is coupled with the first device. The acoustic signal can transfer from the wellbore waveguide to a wellbore tubular through a contact between the wellbore waveguide and the wellbore tubular. A second device can receive the acoustic signal via the wellbore tubular that is coupled with the second device.

Description

COMMUNICATION TO A DOWNHOLE TOOL BY ACOUSTIC

WAVEGUIDE TRANSFER

TECHNICAL FIELD

[0001] The present technology pertains to telemetry between the surface of a well and a downhole tool, and more specifically to acoustic telemetry using acoustic waveguide transfer.

BACKGROUND

[0002] Modern well operations routinely utilize tubing, such as coiled tubing or jointed tubing, to carry out various well operations. In typical applications, the tubing is fed from the surface of a well into a wellbore to lower a downhole tool into a desired position. To ensure well operations are completed in a timely and efficient manner, operators at the surface of the well must remain in communication with the downhole tool to change the configuration of the downhole tool, verify the functionality of the downhole tool or reset the downhole tool, for example. Current communication solutions often require the use of a wired link, such as an electrical conductor or a fiber optic cable, integrated with the tubing to facilitate communication between the surface of the well and the downhole tool. However, these telemetry systems are subject to interference caused by the harsh conditions downhole and often require long rig-up times. Other systems, such as pressure-pulse telemetry systems, require occupation of the fluid medium within the tubing and can restrict pumping configurations. Thus, a reliable wireless telemetry system that does not interrupt well operations would be advantageous.

BRIEF DESCRIPTION OF THE DRAWINGS

[0003] 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:

[0004] FIG. 1 illustrates a schematic diagram of an example system for communication between a surface location and a downhole location by acoustic waveguide transfer;

[0005] FIG. 2A illustrates an example of sinusoidal buckling of tubing in a wellbore;

[0006] FIG. 2B illustrates a cross-sectional view of the sinusoidal buckling in FIG. 2A;

[0007] FIG. 2C illustrates an example of helical buckling of tubing in a wellbore;

[0008] FIG. 2D illustrates a cross-sectional view of the helical buckling in FIG. 2C;

[0009] FIG. 3A illustrates a schematic diagram of an example system embodiment for communication from a surface location to a downhole location;

[0010] FIG. 3B illustrates a schematic diagram of an example system embodiment for communication from a downhole location to a surface location; and

[0011] FIG. 4A and 4B illustrate schematic diagrams of example computing systems for use with example system embodiments.

DETAILED DESCRIPTION

[0012] Various embodiments of the disclosure are discussed in detail below. While specific implementations are discussed, it should be understood that this is done for illustration purposes only. A person skilled in the relevant art will recognize that other components and configurations may be used without parting from the spirit and scope of the disclosure.

[0013] Additional features and advantages of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or can be learned by practice of the herein disclosed principles. The features and advantages of the disclosure can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features of the disclosure will become more fully apparent from the following description and appended claims, or can be learned by the practice of the principles set forth herein. [0014] 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 embodiments described herein. However, it will be understood by those of ordinary skill in the art that the embodiments described herein can be practiced without these specific details. In other instances, methods, procedures and components have not been described in detail so as not to obscure the related relevant feature being described. The drawings are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate details and features. The description is not to be considered as limiting the scope of the embodiments described herein.

[0015] The term "coupled" is defined as connected, whether directly or indirectly through intervening components, and is not necessarily limited to physical connections. The term "substantially" is defined to be essentially conforming to the particular dimension, shape or other word that substantially modifies, such that the component need not be exact. For example, substantially rectangular means that the object in question resembles a rectangle, but can have one or more deviations from a true rectangle. The phrase "wellbore tubular" is defined as one or more types of connected tubulars, and can include, but is not limited to, tubing, production tubing, jointed tubing, coiled tubing, casings, liners, drill pipe, landing string, combinations thereof, or the like. The term "transceiver" is defined as a combination of a transmitter/receiver in one package but can include a separate transmitter and a separate receiver in one package or two packages.

[0016] The approaches set forth herein can be used for communication between a surface of a wellbore and a downhole location of a wellbore via acoustic waveguide transfer.

Subterranean wells can employ wellbore tubulars to complete various well operations.

During such operations, the wellbore tubular can be lowered into, or withdrawn from, the wellbore through a process known as "tripping". However, the dynamic nature of the wellbore tubular during tripping can make it difficult to maintain physical contact between the wellbore tubular and an acoustic transmitter at the surface of the wellbore.

Furthermore, wellbore casing or production tubing surrounding the wellbore tubular typically have poor acoustic waveguide characteristics. [0017] Disclosed are systems, methods and apparatuses for communication between a surface of a wellbore and a downhole location of a wellbore via acoustic waveguide transfer. A first device can transmit an acoustic signal through a wellbore waveguide that is coupled with the first device. The acoustic signal can transfer from the wellbore waveguide to a wellbore tubular through a contact between the wellbore waveguide and the wellbore tubular. A second device can receive the acoustic signal via the wellbore tubular that is coupled with the second device.

[0018] The present disclosure is described in relation to the subterranean well depicted schematically in FIG. 1. Although FIG. 1 depicts a specific wellbore configuration, it should be understood by those skilled in the art that the present disclosure is equally well suited for use in wellbores having other orientations including vertical wellbores, slanted wellbores, multilateral wellbores and the like. Accordingly, it should be understood by those skilled in the art that the use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward or uphole direction being toward the surface of the well, the downward or downhole direction being toward the bottom of the well. Also, even though FIG. 1 depicts an onshore operation, it should be understood by those skilled in the art that the present disclosure is equally well suited for use in offshore operations.

[0019] A well operation 100 can include a truck 140 which supports a power unit 102, a tubing cabin 104 and a reel 106. An injector head unit 110 positioned above the Earth's surface 120 can inject (or withdraw) a wellbore tubular 108 from reel 106 into wellbore 138 through wellhead 112. The wellbore 138 can include a casing 124 which can be cemented into place in at least a portion of the wellbore 138. The wellbore 138 can also include a production tubing 122 disposed within casing 124.

[0020] As the wellbore tubing 108 is lowered into wellbore 138, the wellbore tubing 108 can experience various forces such as pressure, thermal and/or frictional forces. These forces can cause the normally straight configuration of the wellbore tubing 108 to become unstable which can result in deformation, or buckling, of the wellbore tubing 108. Buckling of the wellbore tubing 108 can take the form of sinusoidal buckling 130 which can be followed by helical buckling 132. The buckling of wellbore tubing 108, as well as deviations of wellbore 138, can create one or more regions of physical, radial contact 126, 128 between the wellbore tubing 108 and the production tubing 122 and/or the casing 124. The normal contact force imparted by the wellbore tubular 108 on the production tubing 122 and/or the casing 124 at the one or more regions of contact 126, 128 can be directly related to the energy transfer of the acoustic signal disclosed below. To discuss the sinusoidal and helical buckling of wellbore tubular 108 in greater detail, reference is now made to FIGS. 2A-D.

[0021] FIG. 2A illustrates an example of sinusoidal buckling 200 of tubing in a wellbore, such as sinusoidal buckling 130 of wellbore tubular 108 in wellbore 138. The sinusoidal buckling of a wellbore tubular 202 can form a two-dimensional sine wave in the tubing that is bounded by the wellbore casing 204. In general, sinusoidal buckling can occur before or at lower forces than helical buckling. As a non-limiting example, sinusoidal buckling of the tubing can occur when F_p < F_b < 2 2F_p according to equations (1), (2) and (3) below, where F_b is the buckling force, F_p is the Paslay threshold force, F_a is the axial force, p; is the internal pressure, Ai is the internal radius of the tubing, p₀ is the external pressure, A₀ is the external radius of the tubing, w_c is the casing contact load, EI is the pipe bending stiffness, r is the annular clearance, w_e is the distributed buoyed weight of the casing, φ is the wellbore inclination angle, and Θ is the wellbore azimuth angle.

W22] F_b = -F_a + p_iA_i - p₀A₀ (1)

[0023] F_v = ^ (2)

[0024] w_c = ^ (w_esin(p + F_b g) + (¾sincp ) (3)

[0025] As shown in the cross-sectional view of FIG. 2B taken along line A' -A' in FIG. 2A, the wellbore tubular 202 can form one or more radial contact regions with casing 204 as it propagates through the wellbore. At each contact region a contact force can be imparted on the casing 204 by the wellbore tubular 202. As a non-limiting example, the average normal contact force W_n for sinusoidal buckling can be calculated using equation (4) below, where g is the gravitational force.

[0026] W_n = w_egsin6 (4)

[0027] FIG. 2C illustrates an example of helical buckling 210 of tubing in a wellbore, such as helical buckling 132 of wellbore tubular 108 in wellbore 138. As a non-limiting example, helical buckling of the tubing can occur when 2 2F_p < F_b according to equations (1), (2) and (3) above. As depicted in the cross- sectional view of FIG. 2D taken along the line B'-B' in FIG. 2C, the helical buckling of wellbore tubular 212 can form a spiral or corkscrew within the casing 214 of the wellbore. In doing so, the wellbore tubular 212 can create a nearly continuous radial contact region with casing 214 throughout the length of the helical buckling. At each contact region or throughout the continuous contact region, a contact force can be imparted on the casing 214 by the wellbore tubular 212. As a non-limiting example, the average normal contact force W_n for helical buckling can be calculated using equation (5) below.

[0028] W_n = 2£ (5)

[0029] Referring back to FIG. 1, to carry out various well operations such as drilling, completion, workover, treatment, and/or production processes, one or more downhole tools unit 134 can be coupled with the wellbore tubular 108 within wellbore 138. To enable communication between the surface 120 and the one or more downhole tools unit 134, one or more surface telemetry unit 114 and one or more downhole telemetry unit 136 can be used. The one or more surface telemetry unit 114 can be located at surface 120 (e.g., directly on surface 120, at the top of wellbore 138, within a proximity of wellhead 112, etc.) and can be coupled with wellhead 112, production tubing 122 and/or casing 124. Each surface telemetry unit 114 can receive power from power unit 102 via power line 118 and can transmit or receive data to and from tubing cabin 104 via data line 116, which can be a wired or wireless link. In addition, each surface telemetry unit 114 can include a transmitter, receiver and/or transceiver for the purpose of communicating with one or more downhole telemetry unit 136. The one or more downhole telemetry unit 136 can be coupled with the wellbore tubular 108 within wellbore 138. Each downhole telemetry unit 136 can be within a corresponding downhole tools unit 134 and/or communicatively coupled (wired or wirelessly) with one or more downhole tools unit 134. Both the downhole telemetry unit 136 and downhole tools unit 134 can receive power from downhole batteries, generators or any other downhole power source known in the art. Each downhole telemetry unit 136 can include a transmitter, receiver and/or transceiver for the purpose of communicating with one or more surface telemetry unit 114.

[0030] To send data from the surface 120 to one or more downhole tools unit 134, one or more surface telemetry unit 114 can generate and transmit an acoustic signal through a wellbore waveguide, such as the wellhead 112, production tubing 122 and/or casing 124. For example, the surface telemetry unit 114 can transmit an acoustic signal from the production tubing 122, from the casing 124, or from the wellhead 112 which can transfer the signal to the production tubing 122 and/or casing 124, and the like. The acoustic signal can travel through the wellbore waveguide and can transfer to the wellbore tubular 108 at one or more contact regions 126, 128 between the wellbore tubing 108 and the production tubing 122 and/or the casing 124. Once transferred, the acoustic signal can travel through the wellbore tubular 108 and can be received by one or more downhole telemetry unit 136. The downhole telemetry unit 136 can then decode the acoustic signal and transmit the decoded signal to one or more downhole tools unit 134, or can transmit the acoustic signal to one or more downhole tools unit 134 where it can be stored and/or decoded.

[0031] When sending data from a downhole tools unit 134, the data can first be passed to one or more downhole telemetry unit 136 which can then generate and transmit an acoustic signal through the wellbore tubular 108. The acoustic signal can travel through the wellbore tubular 108 and can transfer to a wellbore waveguide, such as the wellhead

112, production tubing 122 and/or casing 124, at one or more contact regions between the wellbore tubing 108 and the wellbore waveguide. Once transferred, the acoustic signal can travel through the wellbore waveguide and can be received by one or more surface telemetry unit 114. The surface telemetry unit 114 can then decode the acoustic signal and transmit the decoded signal to the tubing cabin 104, or can transmit the acoustic signal to the tubing cabin 104 where it can be stored and/or decoded. [0032] FIG. 3A illustrates a schematic diagram of an example telemetry system 300 using acoustic waveguide transfer for communication from a surface location to a downhole location. The system 300 can include a transmitter assembly 304 which can receive a raw data signal 302, for example, from a user input, a processor, a computer- readable storage medium, a tubing cabin and the like. The raw data signal 302 can be a digital signal and can include information, instructions or other data to be transmitted to one or more downhole tools units. The transmitter assembly 304 can be coupled with a wellbore waveguide 314 and can be located at a surface location of a wellbore, such as at the top of the wellbore, on the surface surrounding the wellbore, within a proximity of a wellhead associated with the wellbore and the like. The transmitter assembly can include a digital-to-analog converter 306, an amplifier 308, a shunt 310 and a transmitter 312, although it should be understood by those skilled in the art that the individual components of the transmitter assembly 304 can be separated into one or more subassemblies separate from the transmitter assembly.

[0033] Upon receipt of the raw data signal 302, the transmitter assembly 304 can convert the raw signal into an analog signal via digital-to-analog converter 306. The analog signal can be amplified by an amplifier 308 and can then be passed on to a transmitter 312. In some cases, a shunt 310, such as a blocking inductor, can be included between the amplifier 308 and the transmitter 312 to reduce energy consumption of the transmitter.

[0034] To send the analog signal downhole, the transmitter 312 can transmit the analog signal as an acoustic signal through a wellbore waveguide 314. The transmitter 312 can be a piezoelectric transmitter including one or more piezoelectric elements and can be coupled with the wellbore waveguide 314. The wellbore waveguide 314 can be a static waveguide and can include one or more of a wellhead, a wellbore casing, production tubing and/or any other waveguide extending from the surface of a wellbore towards a downhole location of the wellbore. The wellbore waveguide 314 can encapsulate at least a portion of a wellbore tubular 316 and can have one or more regions of physical contact with the wellbore tubular 316. The one or more regions of contact can be regions of radial contact between the wellbore waveguide 314 and the wellbore tubular 316 which can be formed by deviations of the wellbore, sinusoidal buckling of the wellbore tubular, helical buckling of the wellbore tubular or otherwise. The wellbore waveguide 314 can also include one or more joints or discontinuities along its length which can cause one or more reflections of the acoustic signal.

[0035] When the acoustic signal is reflected, the reflected acoustic signal can constructively and/or destructively interfere with the incident acoustic signal which can create passbands and/or stopbands within the wellbore waveguide 314. Reflections of the acoustic signal can be received by a receiver assembly at the surface of the wellbore (not shown) and analyzed to determine differences between the transmitted acoustic signal and the reflected acoustic signal. The determined differences can be used to determine, for example, an attenuation of the acoustic signal, a passband of the wellbore waveguide, a stopband of the wellbore waveguide, a standing wave ratio, a resonance and the like.

[0036] As the acoustic signal travels down the wellbore waveguide 314, it can transfer from the wellbore waveguide to the wellbore tubular 316 via acoustic waveguide transfer at the one or more regions of contact between the wellbore waveguide and wellbore tubular. The wellbore tubular 316 can act as an acoustic waveguide and can be a dynamic tubular such as coiled tubing or jointed tubing. The wellbore tubular 316 can be a continuous medium to mitigate reflection and/or attenuation of the acoustic signal.

[0037] Once the acoustic signal is transferred (one or more times) to the wellbore tubular 316, it can travel down the wellbore tubular 316 to a receiver assembly 318. The receiver assembly 318 can be located at a downhole location of the wellbore and can be coupled with the wellbore tubular 316 and/or one or more downhole tools units. The receiver assembly 318 can include a receiver 320 configured to receive the acoustic signal from the transmitter assembly 304 via the wellbore tubular 316. The receiver 320 can be coupled with the wellbore tubular 316 and can be any device capable of receiving the acoustic signal from the wellbore tubular, such as an accelerometer or a piezoelectric receiver including one or more piezoelectric elements. Once the acoustic signal is received by receiver 320, it can be converted to a digital signal via analog-to-digital converter 322. A processor 324 can use memory 326 and a demodulator 328 to decode or demodulate the acoustic signal, for example, to determine instructions transmitted from the surface. The demodulator 328 can be demodulating firmware stored on memory 326 and executed by processor 324. The decoded acoustic signal can be stored in memory 326 or can be output from the receiver assembly 318 as output signal 330 which can be transmitted to, for example, one or more downhole tools units.

[0038] FIG. 3B illustrates a schematic diagram of an example telemetry system 350 using acoustic waveguide transfer for communication from a downhole location to a surface location. The system 350 can include a transmitter assembly 354 which can receive a raw data signal 352, for example, from a processor, a computer-readable storage medium, one or more downhole tools units and the like. The raw data signal 352 can be a digital signal and can include information, instructions or other data from downhole tools units and/or sensors to be transmitted to the surface of a wellbore. The transmitter assembly 354 can be located at a downhole location of a wellbore and can be coupled with one or more downhole tools units and a wellbore tubular 364. The transmitter assembly can include a digital-to-analog converter 356, an amplifier 358, a shunt 360 and a transmitter 362, although it should be understood by those skilled in the art that the individual components of the transmitter assembly 354 can be separated into one or more sub-assemblies separate from the transmitter assembly.

[0039] Upon receipt of the raw data signal 352, the transmitter assembly 354 can convert the raw signal into an analog signal via digital-to-analog converter 356. The analog signal can be amplified by an amplifier 358 and can then be passed on to a transmitter 362. In some cases, a shunt 360, such as a blocking inductor, can be included between the amplifier 358 and the transmitter 362 to reduce energy consumption of the transmitter.

[0040] To send the analog signal uphole, the transmitter 362 can transmit the analog signal as an acoustic signal through a wellbore tubular 364. The transmitter 362 can be a piezoelectric transmitter including one or more piezoelectric elements and can be coupled with the wellbore tubular 364. The wellbore tubular 364 can act as an acoustic waveguide and can be a dynamic tubular such as coiled tubing or jointed tubing. The wellbore tubular 364 can be a continuous medium to mitigate reflection and/or attenuation of the acoustic signal. The wellbore tubular 364 can also have one or more regions of physical contact with a wellbore waveguide 366. The one or more regions of contact can be regions of radial contact between the wellbore tubular 364 and the wellbore waveguide 366 which can be formed by deviations of the wellbore, sinusoidal buckling of the wellbore tubular, helical buckling of the wellbore tubular or otherwise.

[0041] As the acoustic signal travels up the wellbore tubular 364, it can transfer from the wellbore tubular to the wellbore waveguide 366 via acoustic waveguide transfer at the one or more regions of contact between the wellbore tubular and wellbore waveguide. The wellbore waveguide 366 can be a static waveguide and can include one or more of a wellhead, a wellbore casing, production tubing and/or any other waveguide extending from the surface of a wellbore towards a downhole location of the wellbore. The wellbore waveguide 366 can encapsulate at least a portion of a wellbore tubular 364. The wellbore waveguide 366 can also include one or more joints or discontinuities along its length which can cause one or more reflections of the acoustic signal.

[0042] When the acoustic signal is reflected, the reflected signal can constructively and/or destructively interfere with the incident acoustic signal which can create passbands and/or stopbands within the wellbore waveguide 366. Reflections of the acoustic signal can be received by a receiver assembly at the downhole location of the wellbore (not shown) and can be analyzed to determine differences between the transmitted acoustic signal and the reflected acoustic signal. The determined differences can be used to determine, for example, an attenuation of the acoustic signal, a passband of the wellbore waveguide, a stopband of the wellbore waveguide, a standing wave ratio, a resonance and the like.

[0043] Once the acoustic signal is transferred (one or more times) to the wellbore waveguide 366, it can travel up the wellbore waveguide 366 to a receiver assembly 368. The receiver assembly 368 can be located at a surface location of the wellbore and can be coupled with, for example, a tubing cabin. The receiver assembly 368 can include a receiver 370 configured to receive the acoustic signal from the transmitter assembly 354 via the wellbore waveguide 366. The receiver 370 can be coupled with the wellbore waveguide 366 and can be any device capable of receiving the acoustic signal from the wellbore waveguide, such as an accelerometer or a piezoelectric receiver including one or more piezoelectric elements. Once the acoustic signal is received by receiver 370, it can be converted to a digital signal via analog-to-digital converter 372. A processor 374 can use memory 376 and a demodulator 378 to decode or demodulate the acoustic signal, for example, to determine data transmitted from downhole. The demodulator 378 can be demodulating firmware stored on memory 376 and executed by processor 374. The decoded acoustic signal can be stored in memory 376 or can be output from the receiver assembly 368 as output signal 380 which can be transmitted to, for example, a surface tubing cabin for analysis.

[0044] Although FIGS. 3 A and 3B were described as separate systems for communication in one direction (i.e., surface to downhole and downhole to surface), it should be understood to those skilled in the art that such systems can be readily combined to form a bidirectional communication system using acoustic waveguide transfer. For example, the surface and downhole locations of the wellbore can include both a transmitter assembly and a receiver assembly in a single unit (i.e., a transceiver) or as separate units. Further, each sub-component of the transmitter and receiver assemblies of FIGS. 3 A and 3B can be divided into one or more sub-assemblies which can be located at separate locations. For example, a transmitter and/or receiver assembly at the surface of a wellbore can be separated into sub-assemblies located at both a wellhead associated with the wellbore and within a tubing cabin associated with the wellbore. In addition, a transmitter and/or receiver assembly at a downhole location of a wellbore can be separated into sub-assemblies located within one or more downhole tools units and on the wellbore tubular outside of the downhole tools unit.

[0045] FIG. 4A and FIG. 4B illustrate example computing systems for use with example system embodiments. The more appropriate embodiment will be apparent to those of ordinary skill in the art when practicing the present technology. Persons of ordinary skill in the art will also readily appreciate that other system embodiments are possible.

[0046] FIG. 4A illustrates a conventional system bus computing system architecture 400 wherein the components of the system are in electrical communication with each other using a bus 405. System 400 can include a processing unit (CPU or processor) 410 and a system bus 405 that couples various system components including the system memory 415, such as read only memory (ROM) 420 and random access memory (RAM) 425, to the processor 410. The system 400 can include a cache of high-speed memory connected directly with, in close proximity to, or integrated as part of the processor 410. The system 400 can copy data from the memory 415 and/or the storage device 430 to the cache 412 for quick access by the processor 410. In this way, the cache can provide a performance boost that avoids processor 410 delays while waiting for data. These and other modules can control or be configured to control the processor 410 to perform various actions. Other system memory 415 may be available for use as well. The memory 415 can include multiple different types of memory with different performance characteristics. The processor 410 can include any general purpose processor and a hardware module or software module, such as module 1 432, module 2 434, and module 3 436 stored in storage device 430, configured to control the processor 4610 as well as a special-purpose processor where software instructions are incorporated into the actual processor design. The processor 410 may essentially be a completely self-contained computing system, containing multiple cores or processors, a bus, memory controller, cache, etc. A multi-core processor may be symmetric or asymmetric.

[0047] To enable user interaction with the computing device 400, an input device 445 can represent any number of input mechanisms, such as a microphone for speech, a touch-sensitive screen for gesture or graphical input, keyboard, mouse, motion input, speech and so forth. An output device 442 can also be one or more of a number of output mechanisms known to those of skill in the art. In some instances, multimodal systems can enable a user to provide multiple types of input to communicate with the computing device 400. The communications interface 440 can generally govern and manage the user input and system output. There is no restriction on operating on any particular hardware arrangement and therefore the basic features here may easily be substituted for improved hardware or firmware arrangements as they are developed.

[0048] Storage device 430 is a non-volatile memory and can be a hard disk or other types of computer readable media which can store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, solid state memory devices, digital versatile disks, cartridges, random access memories (RAMs) 425, read only memory (ROM) 420, and hybrids thereof. [0049] The storage device 430 can include software modules 432, 434, 436 for controlling the processor 410. Other hardware or software modules are contemplated. The storage device 430 can be connected to the system bus 405. In one aspect, a hardware module that performs a particular function can include the software component stored in a computer-readable medium in connection with the necessary hardware components, such as the processor 410, bus 405, output device 442, and so forth, to carry out the function.

[0050] FIG. 4B illustrates an example computer system 450 having a chipset architecture that can be used in executing the described method and generating and displaying a graphical user interface (GUI). Computer system 450 can be computer hardware, software, and firmware that can be used to implement the disclosed technology. System 450 can include a processor 455, representative of any number of physically and/or logically distinct resources capable of executing software, firmware, and hardware configured to perform identified computations. Processor 455 can communicate with a chipset 460 that can control input to and output from processor 455. Chipset 460 can output information to output device 465, such as a display, and can read and write information to storage device 470, which can include magnetic media, and solid state media. Chipset 460 can also read data from and write data to RAM 475. A bridge 480 for interfacing with a variety of user interface components 485 can be provided for interfacing with chipset 460. Such user interface components 485 can include a keyboard, a microphone, touch detection and processing circuitry, a pointing device, such as a mouse, and so on. In general, inputs to system 450 can come from any of a variety of sources, machine generated and/or human generated.

[0051] Chipset 460 can also interface with one or more communication interfaces 490 that can have different physical interfaces. Such communication interfaces can include interfaces for wired and wireless local area networks, for broadband wireless networks, as well as personal area networks. Some applications of the methods for generating, displaying, and using the GUI disclosed herein can include receiving ordered datasets over the physical interface or be generated by the machine itself by processor 455 analyzing data stored in storage 470 or 475. Further, the machine can receive inputs from a user via user interface components 685 and execute appropriate functions, such as browsing functions by interpreting these inputs using processor 455.

[0052] It can be appreciated that systems 400 and 450 can have more than one processor 410 or be part of a group or cluster of computing devices networked together to provide greater processing capability.

[0053] Methods according to the aforementioned description can be implemented using computer-executable instructions that are stored or otherwise available from computer readable media. Such instructions can comprise instructions and data which cause or otherwise configure a general purpose computer, special purpose computer, or special purpose processing device to perform a certain function or group of functions. Portions of computer resources used can be accessible over a network. The computer executable instructions may be binaries, intermediate format instructions such as assembly language, firmware, or source code. Computer-readable media that may be used to store instructions, information used, and/or information created during methods according to the aforementioned description include magnetic or optical disks, flash memory, USB devices provided with non-volatile memory, networked storage devices, and so on.

[0054] For clarity of explanation, in some instances the present technology may be presented as including individual functional blocks including functional blocks comprising devices, device components, steps or routines in a method embodied in software, or combinations of hardware and software.

[0055] The computer-readable storage devices, mediums, and memories can include a cable or wireless signal containing a bit stream and the like. However, when mentioned, non-transitory computer-readable storage media expressly exclude media such as energy, carrier signals, electromagnetic waves, and signals per se.

[0056] Devices implementing methods according to these disclosures can comprise hardware, firmware and/or software, and can take any of a variety of form factors. Such form factors can include laptops, smart phones, small form factor personal computers, personal digital assistants, rackmount devices, standalone devices, and so on. Functionality described herein also can be embodied in peripherals or add-in cards. Such functionality can also be implemented on a circuit board among different chips or different processes executing in a single device.

[0057] The instructions, media for conveying such instructions, computing resources for executing them, and other structures for supporting such computing resources are means for providing the functions described in these disclosures.

[0058] Although a variety of information was used to explain aspects within the scope of the appended claims, no limitation of the claims should be implied based on particular features or arrangements, as one of ordinary skill would be able to derive a wide variety of implementations. Further and although some subject matter may have been described in language specific to structural features and/or method steps, it is to be understood that the subject matter defined in the appended claims is not necessarily limited to these described features or acts. Such functionality can be distributed differently or performed in components other than those identified herein. Rather, the described features and steps are disclosed as possible components of systems and methods within the scope of the appended claims. Moreover, claim language reciting "at least one of" a set indicates that one member of the set or multiple members of the set satisfy the claim.

STATEMENTS OF THE DISCLOSURE INCLUDE:

[0059] Statement 1: A method, comprising: transmitting, by a first device, an acoustic signal through a wellbore waveguide that is coupled with the first device, transferring the acoustic signal from the wellbore waveguide to a wellbore tubular through a contact between the wellbore waveguide and the wellbore tubular, and receiving, by a second device, the acoustic signal via the wellbore tubular that is coupled with the second device.

[0060] Statement 2: The method according to Statement 1, wherein the first device and the second device comprise at least one of an accelerometer and a piezoelectric element.

[0061] Statement 3: The method according to Statement 1 or 2, wherein the contact is a radial contact formed by at least one of sinusoidal buckling of the wellbore tubular and helical buckling of the wellbore tubular. [0062] Statement 4: The method according to any of Statements 1-3, further comprising: receiving, by the first device, a reflected acoustic signal, and determining one or more differences between the transmitted acoustic signal and the reflected acoustic signal.

[0063] Statement 5: The method according to any of Statements 1-4, wherein the wellbore waveguide encapsulates at least a portion of the wellbore tubular.

[0064] Statement 6: The method according to any of Statements 1-5, wherein the wellbore waveguide is a static waveguide comprising casing or production tubing, and wherein the wellbore tubular is a dynamic tubular comprising coiled tubing or jointed tubing.

[0065] Statement 7: The method according to any of Statements 1-6, wherein the first device is at a surface location of a wellbore, and wherein the second device is at a downhole location of the wellbore.

[0066] Statement 8: The method according to any of Statements 1-7, wherein the acoustic signal comprises instructions for a downhole tool, the method further comprising: decoding the acoustic signal to produce a digital signal, and processing the digital signal via the downhole tool.

[0067] Statement 9: The method according to any of Statements 1-8, further comprising: transmitting, by the second device, a second acoustic signal through the wellbore tubular that is coupled with the second device, transferring the second acoustic signal from the wellbore tubular to the wellbore waveguide through the contact between the wellbore tubular and the wellbore waveguide, and receiving, by the first device, the second acoustic signal via the wellbore waveguide that is coupled with the first device.

[0068] Statement 10: The method according to any of Statements 1-9, wherein the second acoustic signal comprises data from a downhole tool.

[0069] Statement 11: A system, comprising: a wellbore waveguide, a wellbore tubular having one or more regions of contact with the wellbore waveguide, a transmitter for transmitting an acoustic signal through the wellbore waveguide, wherein the transmitter is coupled with the wellbore waveguide at a surface location of a wellbore, and a receiver for receiving the acoustic signal via the wellbore tubular, wherein the receiver is coupled with the wellbore tubular at a downhole location of the wellbore.

[0070] Statement 12: The system according to Statement 11, wherein the one or more regions of contact are formed by at least one of sinusoidal buckling of the wellbore tubular and helical buckling of the wellbore tubular.

[0071] Statement 13: The system according to Statement 11 or 12, wherein the acoustic signal comprises instructions for a downhole tool.

[0072] Statement 14: The system according to any of Statements 11-13, wherein the wellbore waveguide is a static waveguide comprising casing or production tubing, and wherein the wellbore tubular is a dynamic tubular comprising coiled tubing or jointed tubing.

[0073] Statement 15: The system according to any of Statements 11-14, further comprising: a second receiver for receiving a reflected acoustic signal via the wellbore waveguide, wherein the second receiver is coupled with the wellbore waveguide at a surface location of a wellbore, a processor coupled with the second receiver for receiving the reflected acoustic signal, and a computer-readable storage medium having stored therein instructions which, when executed by the processor, cause the processor to perform operations comprising: detecting one or more difference between the acoustic signal and the reflected acoustic signal.

[0074] Statement 16: A system, comprising: a wellbore waveguide, a wellbore tubular having one or more regions of contact with the wellbore waveguide, a transmitter that transmits an acoustic signal through the wellbore tubular, wherein the transmitter is coupled with the wellbore tubular at a downhole location of a wellbore, and a receiver that receives the acoustic signal via the wellbore waveguide, wherein the receiver is coupled with the wellbore waveguide at a surface location of the wellbore.

[0075] Statement 17: The system according to Statement 11, wherein the one or more regions of contact are formed by at least one of sinusoidal buckling of the wellbore tubular and helical buckling of the wellbore tubular. [0076] Statement 18: The system according to Statement 11 or 17, wherein the wellbore waveguide encapsulates at least a portion of the wellbore tubular.

[0077] Statement 19: The system according to any of Statements 11-18, wherein the wellbore waveguide is a static waveguide comprising casing or production tubing, and wherein the wellbore tubular is a dynamic tubular comprising coiled tubing or jointed tubing.

[0078] Statement 20: The system according to any of Statements 11-19, wherein the acoustic signal comprises data from a downhole tool.

[0079] Statement 21: A system, comprising: a waveguide, a transmitter for transmitting an acoustic signal through the waveguide, wherein the transmitter is adapted to be coupled with the waveguide at a surface location of a wellbore, and a receiver adapted to receive the acoustic signal via a wellbore tubular, wherein the receiver is adapted to be coupled with the wellbore tubular at a downhole location of the wellbore.

[0080] Statement 22: The system according to any of Statements 11-21, wherein the wellbore tubular is adapted to receive the acoustic signal from the waveguide through a contact between the waveguide and the wellbore tubular.

[0081] Statement 23: The system according to any of Statements 11-22, wherein the transmitter comprises one or more piezoelectric elements.

[0082] Statement 24: The system according to any of Statements 11-23, wherein the receiver comprises at least one of an accelerometer and a piezoelectric element.

[0083] Statement 25: The system according to any of Statements 11-24, wherein the wellbore tubular is a dynamic wellbore tubular.

Claims

CLAIMS We claim:

1. A method, comprising:

transmitting, by a first device, an acoustic signal through a wellbore waveguide that is coupled with the first device;

transferring the acoustic signal from the wellbore waveguide to a wellbore tubular through a contact between the wellbore waveguide and the wellbore tubular; and

receiving, by a second device, the acoustic signal via the wellbore tubular that is coupled with the second device.

2. The method of claim 1, wherein the first device and the second device comprise at least one of an accelerometer and a piezoelectric element.

3. The method of claim 1, wherein the contact is a radial contact formed by at least one of sinusoidal buckling of the wellbore tubular and helical buckling of the wellbore tubular.

4. The method of claim 1, further comprising:

receiving, by the first device, a reflected acoustic signal; and

determining one or more differences between the transmitted acoustic signal and the reflected acoustic signal.

5. The method of claim 1, wherein the wellbore waveguide encapsulates at least a portion of the wellbore tubular.

6. The method of claim 1, wherein the wellbore waveguide is a static waveguide comprising casing, wellhead or production tubing, and wherein the wellbore tubular is a dynamic tubular comprising coiled tubing or jointed tubing.

7. The method of claim 1, wherein the first device is at a surface location of a wellbore, and wherein the second device is at a downhole location of the wellbore.

8. The method of claim 7, wherein the acoustic signal comprises instructions for a downhole tool, the method further comprising:

decoding the acoustic signal to produce a digital signal; and

processing the digital signal via the downhole tool.

9. The method of claim 1, further comprising:

transmitting, by the second device, a second acoustic signal through the wellbore tubular that is coupled with the second device;

transferring the second acoustic signal from the wellbore tubular to the wellbore waveguide through the contact between the wellbore tubular and the wellbore waveguide; and

receiving, by the first device, the second acoustic signal via the wellbore waveguide that is coupled with the first device.

10. The method of claim 9, wherein the second acoustic signal comprises data from a downhole tool.

11. A system, comprising:

a wellbore waveguide;

a wellbore tubular having one or more regions of contact with the wellbore waveguide;

a transmitter for transmitting an acoustic signal through the wellbore waveguide, wherein the transmitter is coupled with the wellbore waveguide at a surface location of a wellbore; and

a receiver for receiving the acoustic signal via the wellbore tubular, wherein the receiver is coupled with the wellbore tubular at a downhole location of the wellbore.

12. The system of claim 11, wherein the one or more regions of contact are formed by at least one of sinusoidal buckling of the wellbore tubular and helical buckling of the wellbore tubular.

13. The system of claim 11, wherein the acoustic signal comprises instructions for a downhole tool.

14. The system of claim 11, wherein the wellbore waveguide is a static waveguide comprising casing or production tubing, and wherein the wellbore tubular is a dynamic tubular comprising coiled tubing or jointed tubing.

15. The system of claim 11, further comprising:

a second receiver for receiving a reflected acoustic signal via the wellbore waveguide, wherein the second receiver is coupled with the wellbore waveguide at a surface location of a wellbore;

a processor coupled with the second receiver for receiving the reflected acoustic signal; and

a computer-readable storage medium having stored therein instructions which, when executed by the processor, cause the processor to perform operations comprising:

detecting one or more difference between the acoustic signal and the reflected acoustic signal.

16. A system, comprising:

a waveguide;

a transmitter for transmitting an acoustic signal through the waveguide, wherein the transmitter is adapted to be coupled with the waveguide at a surface location of a wellbore; and

a receiver adapted to receive the acoustic signal via a wellbore tubular, wherein the receiver is adapted to be coupled with the wellbore tubular at a downhole location of the wellbore.

17. The system of claim 16, wherein the wellbore tubular is adapted to receive the acoustic signal from the waveguide through a contact between the waveguide and the wellbore tubular.

18. The system of claim 16, wherein the transmitter comprises one or more piezoelectric elements.

19. The system of claim 16, wherein the receiver comprises at least one of an accelerometer and a piezoelectric element.

20. The system of claim 16, wherein the wellbore tubular is a dynamic wellbore tubular.