US20140375467A1

US20140375467A1 - Wireless Transmission of Well Formation Information

Info

Publication number: US20140375467A1
Application number: US13/924,305
Authority: US
Inventors: David H. Lilly; John M. Moore
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2013-06-21
Filing date: 2013-06-21
Publication date: 2014-12-25
Also published as: GB2534291A; GB201600478D0; GB2534291B; WO2014205312A1; BR112015030554A2; NO20160016A1

Abstract

An apparatus includes an acoustic sensor that receives a signal propagated by a well formation. The acoustic sensor includes a sensing component that receives the signal, a transmitter that transmits information based on the signal, and a receiver that receives the information. The transmitter and receiver are wirelessly coupled. The transmitter and receiver may be inductively coupled, capacitively coupled, or optically coupled, or the transmitter may transmit information using radio waves. The transmitter may be encapsulated in a polymer. The acoustic sensor may be part of a system including a downhole tool that detects subterranean conditions. The downhole tool may include a retaining member that retains the acoustic sensor within an outer layer of the downhole tool.

Description

TECHNICAL FIELD OF THE DISCLOSURE

The present disclosure relates generally to systems, methods, and apparatuses for wireless transmission of well formation information.

BACKGROUND

Wellbores are formed for various purposes including, for example, extraction of oil and gas. Sensors are employed to monitor conditions at downhole locations in the wellbores either during drilling or after drilling. Sensors utilized at a drilling site may be incorporated within a “drill string.” A drill string may include a series of elongated tubular segments connected end-to-end, and may extend into the wellbore from a drilling rig or platform. An earth-boring rotary drill bit and other components may be coupled at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of tools and components is referred to as a bottom hole assembly.

SUMMARY

Embodiments of the present disclosure provide systems, methods, and apparatuses for wireless transmission of well formation information. According to one embodiment, an apparatus includes an acoustic sensor that receives a signal propagated by a well formation. The acoustic sensor includes a sensing component that receives the signal, a transmitter that transmits information based on the signal, and a receiver that receives the information. The transmitter and receiver are wirelessly coupled.
According to another embodiment of the disclosure, a system includes a downhole tool that detects subterranean conditions and an acoustic sensor that receives a signal propagated by a well formation. The acoustic sensor is coupled to the downhole tool, and the acoustic sensor includes a sensing component that receives the signal, a transmitter that transmits information based on the signal, and a receiver that receives the information. The transmitter and receiver are wirelessly coupled.
According to another embodiment of the disclosure, a method includes receiving a signal propagated by a well formation, and transmitting, wirelessly, information based on the signal. The method further includes sending data, based on the information, to a controller in a downhole tool.
Other embodiments described herein will become apparent from the following description and the accompanying drawings, which illustrate the principles of the embodiments by way of example only.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures form part of the specification, are included to further demonstrate certain aspects of the claimed subject matter, and should not be used to limit or define the claimed subject matter. The claimed subject matter may be better understood by reference to one or more of these drawings in combination with the detailed description, in which like reference numerals identify like elements, wherein:

FIG. 1 depicts a side view of an apparatus for wireless transmission of well formation information in accordance with at least some illustrated embodiments;

FIG. 2 depicts a cross section of an apparatus for wireless transmission of well formation information in accordance with at least some illustrated embodiments;

FIG. 3 depicts a method for wireless transmission of well formation information in accordance with at least some illustrated embodiments;

FIG. 4 depicts portion of a system for wireless transmission of well formation information in accordance with at least some illustrated embodiments;

FIG. 5 depicts a cross section of a system for wireless transmission of well formation information in accordance with at least some illustrated embodiments;

FIG. 6 depicts a system for wireless transmission of well formation information in accordance with at least some illustrated embodiments; and

FIG. 7 depicts a system for wireless transmission of well formation information in accordance with at least some illustrated embodiments.

Certain terms are used throughout the following to refer to particular system components and configurations. As one skilled in the art will appreciate, the same component may be referred to by different names. This document does not intend to distinguish between components that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection or through an indirect connection via other devices and connections such as a wireless connection or inductive connection.
As used herein, the term “sensor” means and includes a device that responds to a physical condition and transmits a signal based on that condition. For example, sensors may be configured to detect pressures, flow rates, temperatures, etc., and may be configured to communicate with other parts of a system, such as a drill string (e.g., a control system).
As used herein, the term “acoustic sensor” means and includes a sensor that senses sound waves and/or acoustic signals. An acoustic sensor may also include, without limitation, an acoustic sensor transmitter and an acoustic sensor receiver.
As used herein, the term “acoustic sensor transmitter” means and includes a transmitter housed within an acoustic sensor. The acoustic sensor transmitter may, without limitation, transmit information based on a signal to an acoustic sensor receiver.
As used herein, the term “acoustic sensor receiver” means and includes a receiver housed with an acoustic sensor. The acoustic sensor receiver may, without limitation, receive information based on a signal from an acoustic sensor transmitter.
As used herein, the term “acoustic generator” means and includes a device that produces and transmits sound waves and/or acoustic signals.
As used herein, the term “drilling system” means and includes any grouping of inter-communicable or interactive tools configured for use in testing, surveying, drilling, completing, sampling, monitoring, utilizing, maintaining, repairing, etc., a bore. Drilling systems include, without limitation, on-shore systems, off-shore systems, systems utilizing a drill string, and systems utilizing a wireline.
As used herein, the term “downhole tool” means and includes any tool used within a wellbore in a subterranean formation. Downhole tools include, without limitation, tools used to measure or otherwise detect or log conditions in the downhole environment and tools used to communicate conditions to uphole locations. Although the description herein may refer to a downhole tool segment, it will be understood that this term refers to a segment or portion of a downhole tool.
As used herein, the term “high-pressure” refers to pressures at or exceeding 10,000 psi.
As used herein, the term “high-temperature” refers to temperatures at or exceeding 100 degrees Celsius.
As used herein, the term “well formation” refers to any or all of the following: the earth formation(s) surrounding a well, and objects and fluids of interest that may be inserted into the earth formation(s) or into the well formed in the earth formation(s). Such objects and fluids may include, but are not limited to, cement, casing, and drilling fluid (also referred to as drilling mud). However, the term “well formation” does not include the downhole tool body. As such, the well formation or components thereof may propagate signals of interest, which may be, without limitation, acoustic signals. Signals may also emanate from the downhole tool body. The term “fluid” includes both liquids and gases.

DETAILED DESCRIPTION

The foregoing description of the figures is provided for convenience. It should be understood, however, that embodiments are not limited to the precise arrangements and configurations shown in the figures. Also, the figures are not necessarily drawn to scale, and certain features may be shown exaggerated in scale, or in generalized or schematic form, for clarity and conciseness.
While various embodiments are described herein, it should be appreciated that the present disclosure encompasses many concepts that may be embodied in a wide variety of contexts. The following detailed description of exemplary embodiments, read in conjunction with the accompanying drawings, is merely illustrative and is not to be taken as limiting the scope of the disclosure as it would be impossible or impractical to include all of the possible contexts of the disclosure. Upon reading this disclosure, many alternative embodiments will be apparent.
Conditions in a downhole environment are harsh. Sensors used downhole must be able to withstand temperatures ranging to and beyond 150 degrees Celsius and pressures ranging to and beyond 30,000 psi. Surrounded by earth, debris, and drilling mud, downhole conditions are often also moisture-filled spaces. Acoustic sensors are one type of sensor used in downhole tools subject to such harsh conditions. An acoustic sensor may contain a piezo transducer (“piezo”) to receive acoustic signals propagated by well formations. Such acoustic signals may be generated by acoustic generators also used in downhole tools. The piezo may also convert the received acoustic (pressure) signals to electric signals, which may be supplied to other components. The acoustic sensor may be located within the same device as the acoustic generator in at least one embodiment. In another embodiment, the acoustic sensor may be located in a separate device from the acoustic generator, but the acoustic sensor and the acoustic generator may be near to each other within the downhole tool. Finally, the acoustic sensor may be located in a separate device from the acoustic generator, and the acoustic sensor and the acoustic generator may be far from each other within the downhole tool. The acoustic sensor may include an acoustic sensor transmitter (“transmitter”) and an acoustic sensor receiver (“receiver”).
A portion of the acoustic signal generated by the acoustic generator may be propagated by various well formations, and may be received by the acoustic sensor. Various characteristics of the downhole environment may be inferred from the received signal. For example, characteristics of the downhole environment such as dimensions, temperature, pressure, fluid flow rate and type, formation resistivity, and fluid characteristics may be inferred from characteristics of the acoustic signal such as frequency, amplitude, speed, direction, wavelength, wave number, pressure, and intensity. Not only should acoustic sensors be able to survive the harsh downhole conditions, but acoustic sensors should also be able to accurately detect desired signals (that is, signals propagated by well formations in response to the signals generated by the acoustic generator). Detection of desired signals can be hampered by the presence of undesired signals (that is, other signals), particularly when such undesired signals bear similarities to the desired signals. Accordingly, when changes in acoustic sensor configurations in downhole tools are made to improve performance, care should be taken that such design changes do not increase the presence of undesired signals. An example of an undesired signal that bears similarities to desired signals is the signal produced by the acoustic generator but not propagated by one or more well formations. Specifically, such a signal may be conducted from the acoustic generator to the receiver by the downhole tool body itself
FIG. 1 illustrates a portion of a downhole tool segment 44 including one embodiment of a configuration of sensor 10 housed in a housing 18. In at least one embodiment, the sensor 10 is an acoustic sensor. Other portions of the downhole tool segment 44 may include additional sensors 10. The sensor 10 has a body 12 that houses internal sensor components and that defines at least one sidewall 16. According to the depicted embodiment, the sidewall 16 of the body 12 is substantially cylindrical, but sidewall 16 is not limited to this shape. The sensor 10 includes at least one sensing component 14 that is supported by the body 12 of the sensor 10. Specifically, the body 12 of the sensor 10 may support the sensing component 14 against pressure from drilling mud, the pressure directed from outside the downhole tool segment 44 to inside the downhole tool segment 44 as can be seen in FIG. 5. The sensing component 14 of the sensor 10 of the downhole tool segment 44 may be a condition-sensing component of an acoustic sensor, e.g., a piezo. In other aspects, the sensing component 14 of the sensor 10 includes a plurality of stacked piezos.
In various embodiments, a polymer 22 may partially or completely cover various portions of the sensor 10. The polymer 22 may be, without limitation, an elastomer, an acrylic, an epoxy, a resin, a thermoplastic material, or, more specifically, polyetheretherketone (“PEEK”) in various embodiments.
The sensor 10 also includes electrical contacts 20 extending into the interior 46 of the downhole tool segment 44. Connector pins 21 are configured to couple the electrical contacts 20 of the sensor 10 to an electronics module such as a controller 54 (depicted in FIG. 5) or other electronic circuitry. The sensor 10 may be situated in an aperture of the downhole tool segment 44 (as depicted in FIG. 5) and supported by the sensor housing 18, which includes housing opening edges 48.
The sensor 10 is configured to detect a signal, such as an acoustic pulse, in an environment at a pressure of at least 30,000 psi and at a temperature of at least 175 degrees Celsius (e.g., in a downhole environment at 30,000 psi and 175 degrees Celsius, at 33,000 psi and 175 degrees Celsius, at 30,000 psi and 185 degrees Celsius, and at other pressures and temperatures). Sensor 10 is further configured to detect a signal in an environment below a pressure of 30,000 psi and at a temperature lower than 175 degrees Celsius.
FIG. 2 illustrates a cross-sectional view of the sensor 10. The sensor 10 is oriented such that the outer wall of the downhole tool segment 44 is at the top of the figure, as may be clarified by reference to FIG. 5. In at least one embodiment, the downhole tool segment 44 includes a retaining member 208 that retains the sensor 10 within an outer layer of the downhole tool segment 44. As depicted, the retaining member 208 includes holes which serve to improve the signal path for propagation of acoustic signals from a well formation to the sensor 10. The retaining member 208 may include hinges and fasteners such that the retaining member 208 may be moved to allow the sensor 10 to be removed from the downhole tool.
As depicted, the sensor 10 includes the sensing component 14, an acoustic sensor transmitter (“transmitter”) 202, and an acoustic sensor receiver (“receiver”) 204. In at least one embodiment, the transmitter 202 and receiver 204 are wirelessly coupled. As such, the transmitter 202 transmits information, based on a signal it receives from the sensing component 14, wirelessly to the receiver 204, which receives the information. The transmitter 202 may include elements of circuits or integrated circuits that process the signal received from the sensing component 14 into information using amplifiers, filters, and the like. The receiver 204 may also include elements of circuits or integrated circuits that process the information received from the transmitter 202 into data using amplifiers, filters, and the like. Due to the wireless coupling, the transmitter 202 and receiver 204 may be separated, as depicted, by one or more layers of polymers, such as rubber 206 or PEEK 200, or other appropriate materials (which may include materials other than polymers), to dampen undesired acoustic signals traveling through the downhole tool itself As such, there need be no mechanical coupling (i.e. physical connection) between the transmitter 202 and receiver 204. In at least one embodiment, the coupling of connector pins 21 to controller 54 (depicted in FIG. 5) is implemented through a wireway 210. Similarly, the connector pins 21 may couple to other electronic circuitry. Using this coupling, the controller 54 or other electronic circuitry receives data from the receiver 204 based on the information.
In a non-illustrated embodiment, the sensing component 14 and the transmitter 202 may be enclosed in or supported by a polymer layer (as described above), and the combination of sensing component 14, transmitter 202 and polymer layer may be contained in a container containing or filled with oil or another, e.g., viscous, liquid. The container may be made of metal or another material. In this arrangement, the oil allows acoustic signals to be conducted to the sensing component 14, while the container protects the sensing component 14 from the environment. A bellowed sealing lid may be provided whereby, as the oil expands and contracts due to changes in temperature, the bellowed sealing lid provides necessary expansion and contraction space such that no piston compensation mechanism is needed inside the metal cylinder. Alternatively, the container may be expandable and contractible by means of a piston. As a variant of this embodiment, the polymer layer may be omitted, that is, the sensing component 14 and the transmitter 202 may be contained in the container of oil or other liquid, without being enclosed in/supported by a polymer layer.
In at least one embodiment, the transmitter 202 and the receiver 204 are inductively coupled, i.e., indirectly coupled via induction without wires connecting the transmitter 202 and receiver 204. An inductor may be a coil of conductive material wrapped around a core of magnetic material or air. The conductive material, such as a copper wire, solenoid, or cable, may be shielded or unshielded. Furthermore, the core may be adjustable, giving the inductor the ability to change inductance. In at least one embodiment, the transmitter 202 may be an inductive circuit that is coupled to the sensing component 14. Similarly, the receiver 204 may be an inductive circuit. Such inductive circuits may be integrated circuits and may reside on printed circuit boards. In at least one embodiment, the transmitter 202 and receiver 204 share mutual inductance. That is, a change in current in the transmitter circuit induces a voltage in the receiver circuit.
As an alternative to inductive coupling, the transmitter 202 may transmit the information to the receiver 204 using radio waves. For example, the transmitter 202 may include a radio wave transmitter to encode information about the received signal. The receiver 204 may include an antenna to receive the radio waves. As other alternatives, the transmitter 202 and receiver 204 may be capacitively coupled or optically coupled. Such coupling modes may be implemented using appropriate transmitting and receiving elements and conductive path, as will be understood by one of ordinary skill in the art. For example, capacitive coupling may be achieved using a metal plate for both sides. It is possible that the body of the sensing device may be used as such. As an example of optical coupling, an LED may be used for transmission and a photodetector for reception, with associated support circuitry. The optical coupling device may, for example, include a protected area smeared with a clear grease or the like to keep out mud, etc.
By wirelessly coupling the transmitter 202 and receiver 204, the sensor 10 may be reduced in size and cost. Specifically, a mechanical coupling (i.e., a physical connection between the transmitter 202 and receiver 204) may be eliminated. By virtue of the reduction in size of the sensor 10, the downhole tool may also be reduced in size and cost without introducing additional acoustic coupling (i.e., signals conducted from the acoustic generator to the receiver by the downhole tool body itself) and without losing space for other downhole tool elements. It will be appreciated that a reduction in size of the downhole tool without a reduction in size of the sensor 10 would result in disadvantages. First, the sensor 10 would inhabit a greater percentage of the downhole tool resulting in less space for other downhole tool elements. Second, a sensor 10 inhabiting a greater percentage of the downhole tool would be exposed to more undesired acoustic signals through the tool body than would a smaller sensor.
Additionally, wireless coupling of the transmitter 202 and receiver 204 reduces the amount of service and maintenance required by the sensor 10 and downhole tool because the removal of a mechanical coupling (i.e., a physical connection between the transmitter 202 and receiver 204) adds greater integrity to the sensor 10 and downhole tool, which may be beneficial in a high-pressure and high-temperature environment. Specifically, a mechanical coupling is vulnerable to breaches of integrity, and the presence of a mechanical coupling would permit such breaches to spread across the coupling from one part of the sensor 10 to another part thereof or from the sensor 10 to the downhole tool. With the provision of wireless coupling, thus, the interior of the downhole tool may be kept sealed at atmospheric pressure to protect signal processing circuitry inside. The greater integrity results in less frequent damage leading to less frequent service and maintenance requirements and repair or replacement visits, which leads to decreased expense.
FIG. 3 illustrates a method 300 for wireless transmission of well formation information, beginning at 302 and ending at 310, in accordance with at least one illustrated embodiment. At 304, an acoustic signal propagated by a well formation is received. The signal may be converted, by a piezo or other transducer, to electrical energy, which may be processed into information, using amplifiers, filters, and the like. At 306, information based on the signal is transmitted wirelessly. In various embodiments, transmitting the information includes transmitting, inductively, optically, or capacitively, the information based on the signal. Alternatively, transmitting the information includes transmitting the information based on the signal using radio waves. In at least one embodiment, the method 300 further includes wirelessly receiving, e.g., inductively, optically, capacitively, or via radio waves in various embodiments, the information based on the signal. At 308, data based on the information is sent to a controller or other electronic circuitry in a downhole tool, and such data may be sent conductively. For example, the data based on the information may take the form of electrical currents traveling through a conductive wire. Conductive wire may be made of materials such as copper, aluminum, tungsten, and the like. In various embodiments, the method 300 includes any action described in this disclosure.
FIG. 4 illustrates an embodiment of a downhole tool segment 44. The downhole tool segment 44 may, without limitation, be substantially cylindrical, for example, largely symmetrical about cylindrical axis 50 (also referred to as a longitudinal axis), as depicted in FIG. 4. Again as illustrated in FIG. 4, downhole tool segment 44 may include a substantially cylindrical sensor housing 18 configured for coupling to a drill string 36 (depicted in FIG. 7) or wireline (not depicted) and therefore may include threaded end portions 6 for coupling to drill string 36 or a wireline. Through pipe 52, suitable for use while drilling, provides a conduit for the flow of drilling fluid downhole, for example, to a drill bit assembly having a drill bit 34 (depicted in FIG. 7).
The sensor housing 18 may define at least one aperture 8 bordered by housing opening edges 48 (depicted in FIG. 1). The sensor 10 is situated in the aperture 8 and is supported by the sensor housing 18. The downhole tool segment 44 may include one or more sensors 10.
FIG. 5 illustrates a cross-sectional view of a downhole tool segment. The depicted downhole tool segment 44 includes three sensors 10 configured about the cylindrical axis 50. Two of the sensors 10 are configured on either side of the through pipe 52. The disclosure is not limited to any particular number or orientation of sensors that may be deployed at one time. In at least one embodiment, each sensor 10 is positioned such that the sensing component 14 of the sensor 10 is directed toward and is in communication with the exterior of the downhole tool segment 44. Furthermore, each sensor 10 may abut the housing opening edges 48. In such a configuration, the widest external dimension of the polymer 22 (depicted in FIG. 1) surrounding the sensor's sensing component 14 abuts the widest internal dimension defined by the aperture 8 (depicted in FIG. 4) in the sensor housing 18, so as to create a seal between (polymer 22 surrounding) sensing component 14 and sensor housing 18. Each sensor 10 may be sealed within the sensor housing 18 to substantially prevent the flow of drilling fluid from the exterior of the downhole tool segment 44 from entering through the aperture 8 to the interior 46 of the downhole tool segment 44. In such aspects of the downhole tool segment 44, the seal between each sensor 10 and the sensor housing 18 may be fluid tight between the polymer 22 covering the sensor 10 and the housing opening edges 48 of the sensor housing 18. During operation, the exterior of the downhole tool segment 44 may be subject to high temperatures and high pressures. The interior 46 of the downhole tool segment 44 may be at a lower temperature and pressure such as atmospheric pressure.
The electronics module or controller 54 may include a programmable processor (not shown), such as a microprocessor or microcontroller, and may also include processor-readable or computer-readable program code embodying logic including instructions for controlling the sensors 10. Controller 54 may also include other controllable components, such as additional sensors, data storage devices, power supplies, timers, and the like. The controller 54 may also be in electronic communication with various sensors and/or probes for monitoring physical parameters of the wellbore 38 (FIG. 7), such as a gamma ray sensor, a depth detection sensor, or an accelerometer. The controller 54 may also communicate with other instruments in the drill string 36 (depicted in FIG. 7), wireline (not depicted), or drilling system 30 (depicted in FIGS. 6 and 7), such as telemetry systems that communicate with the surface in various embodiments. Also, the controller 54 may further include volatile or non-volatile memory or a data storage device. Further, while the controller 54 is shown within downhole tool segment 44, it may alternatively be located elsewhere in the drill string 36, wireline (not depicted), or drilling system 30.
The controller 54 may include electrical drive voltage electronics (e.g., a high voltage, high frequency power supply) for applying a waveform (e.g., a square wave voltage pulse) to a piezo causing the piezo to vibrate and launch a pressure pulse external to the downhole tool segment 44. The controller 54 may also or alternatively include receiving electronics such as a variable gain amplifier for amplifying a received signal. The receiving electronics may also include various filters (e.g., low and/or high pass filters), rectifiers, multiplexers, and other circuit components for signal processing.
The electrical contacts 20 of sensors 10 may be in operable connection with the controller 54. These electrical contacts 20 may be configured to communicate detected conditions to the controller 54 or to other elements utilizing the sensor 10. Thus, during use, conditions sensed by the sensor 10 are communicable to the controller 54. Depending upon the condition detected, adjustments to the operation of the drilling system 30 may be made.
FIG. 6 illustrates an example of a drilling system 30 in which sensors 10 of the present disclosure may be utilized. The depicted drilling system 30 includes a wireline (not depicted) that extends underneath an earthen surface 32. According to FIG. 6, the earthen surface 32 is an off-shore location, but in other aspects, the earthen surface 32 may be an on-shore location. The wireline of the depicted drilling system 30 may include several active devices such as multiple sensors 10 aligned along a portion of the line and situated within a downhole location 40.
FIG. 7 illustrates another example of a drilling system 30 in which sensors 10 of the present disclosure may be utilized. The depicted drilling system 30 includes a drill string 36 extending into a wellbore 38 that extends beneath an earthen surface 32. According to FIG. 7, the earthen surface 32 is an off-shore location, but in other aspects, the earthen surface 32 may be an on-shore location. A downhole tool, including downhole tool segment 44 housing one or more sensors 10, is included along the drill string 36. An earth-boring tool, such as a drill bit 34 or reamer, is also coupled to the drill string 36. The drill string 36 may further include other active devices such as a downhole drill motor and one or more additional sensors for sensing downhole characteristics of the wellbore 38 and the surrounding formation.
In light of the principles and example embodiments described and illustrated herein, it will be recognized that the example embodiments can be modified in arrangement and detail without departing from such principles. Also, the foregoing discussion has focused on particular embodiments, but other configurations are also possible. In particular, even though expressions such as “in one embodiment,” “in another embodiment,” or the like are used herein, these phrases are meant to generally reference embodiment possibilities, and are not intended to limit the disclosure to particular embodiment configurations. As used herein, these terms may reference the same or different embodiments that are combinable into other embodiments. As a rule, any embodiment referenced herein is freely combinable with any one or more of the other embodiments referenced herein, and any number of features of different embodiments are combinable with one another, unless indicated otherwise.
Similarly, although example processes have been described with regard to particular operations performed in a particular sequence, modifications could be applied to those processes to derive alternative embodiments of the present disclosure. For example, alternative embodiments may include processes that use fewer than all of the disclosed operations, processes that use additional operations, and processes in which the individual operations disclosed are combined, subdivided, rearranged, or otherwise altered.
In view of the wide variety of useful permutations that may be readily derived from the example embodiments described herein, this detailed description is intended to be illustrative only, and should not be taken as limiting the scope of the claims.

Claims

What is claimed is:

1. An apparatus, comprising:

an acoustic sensor that receives a signal propagated by a well formation, the acoustic sensor comprising:

a sensing component that receives the signal;

a transmitter that transmits information based on the signal; and

a receiver that receives the information;

wherein the transmitter and receiver are wirelessly coupled.

2. The apparatus of claim 1, wherein the transmitter and the receiver are inductively coupled.

3. The apparatus of claim 1, wherein (a) the transmitter comprises an inductive circuit, coupled to the sensing component, used to transmit the information and/or (b) the receiver comprises an inductive circuit used to receive the information.

4. The apparatus of claim 1, wherein the sensing component and the transmitter are enclosed in a polymer layer and/or contained in a container containing oil.

5. The apparatus of claim 1, wherein the transmitter and the receiver are capacitively coupled.

6. The apparatus of claim 1, wherein the transmitter and the receiver are optically coupled.

7. The apparatus of claim 1, wherein the transmitter transmits the information using radio waves.

8. The apparatus of claim 1, wherein the transmitter is encapsulated in a polymer.

9. A system, comprising:

a downhole tool that detects subterranean conditions;

an acoustic sensor that receives a signal propagated by a well formation, the acoustic sensor coupled to the downhole tool, the acoustic sensor comprising:

a sensing component that receives the signal;

a transmitter that transmits information based on the signal; and

a receiver that receives the information;

wherein the transmitter and receiver are wirelessly coupled.

10. The system of claim 9, wherein the transmitter transmits the information using radio waves.

11. The system of claim 9, wherein the downhole tool comprises a retaining member that retains the acoustic sensor within an outer layer of the downhole tool.

12. The system of claim 9, wherein the downhole tool comprises a controller that receives data from the receiver based on the information.

13. The system of claim 9, wherein the transmitter and the receiver are optically coupled.

14. The system of claim 9, wherein the transmitter and the receiver are inductively coupled.

15. The system of claim 9, wherein the transmitter and the receiver are capacitively coupled.

16. A method, comprising:

receiving a signal propagated by a well formation;

transmitting, wirelessly, information based on the signal;

sending data, based on the information, to a controller in a downhole tool.

17. The method of claim 16, wherein transmitting the information comprises transmitting, inductively, the information based on the signal.

18. The method of claim 16, further comprising receiving, wirelessly, the information based on the signal.

19. The method of claim 16, wherein transmitting the information comprises transmitting, using radio waves, the information based on the signal.

20. The method of claim 16, wherein transmitting the information comprises transmitting, optically, the information based on the signal.

21. The method of claim 16, wherein transmitting the information comprises transmitting, capacitively, the information based on the signal.