Wireless Transmission of Well Formation Information

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.

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. 1illustrates a portion of a downhole tool segment44including one embodiment of a configuration of sensor10housed in a housing18. In at least one embodiment, the sensor10is an acoustic sensor. Other portions of the downhole tool segment44may include additional sensors10. The sensor10has a body12that houses internal sensor components and that defines at least one sidewall16. According to the depicted embodiment, the sidewall16of the body12is substantially cylindrical, but sidewall16is not limited to this shape. The sensor10includes at least one sensing component14that is supported by the body12of the sensor10. Specifically, the body12of the sensor10may support the sensing component14against pressure from drilling mud, the pressure directed from outside the downhole tool segment44to inside the downhole tool segment44as can be seen inFIG. 5. The sensing component14of the sensor10of the downhole tool segment44may be a condition-sensing component of an acoustic sensor, e.g., a piezo. In other aspects, the sensing component14of the sensor10includes a plurality of stacked piezos.

In various embodiments, a polymer22may partially or completely cover various portions of the sensor10. The polymer22may be, without limitation, an elastomer, an acrylic, an epoxy, a resin, a thermoplastic material, or, more specifically, polyetheretherketone (“PEEK”) in various embodiments.

The sensor10also includes electrical contacts20extending into the interior46of the downhole tool segment44. Connector pins21are configured to couple the electrical contacts20of the sensor10to an electronics module such as a controller54(depicted inFIG. 5) or other electronic circuitry. The sensor10may be situated in an aperture of the downhole tool segment44(as depicted inFIG. 5) and supported by the sensor housing18, which includes housing opening edges48.

The sensor10is 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). Sensor10is 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. 2illustrates a cross-sectional view of the sensor10. The sensor10is oriented such that the outer wall of the downhole tool segment44is at the top of the figure, as may be clarified by reference toFIG. 5. In at least one embodiment, the downhole tool segment44includes a retaining member208that retains the sensor10within an outer layer of the downhole tool segment44. As depicted, the retaining member208includes holes which serve to improve the signal path for propagation of acoustic signals from a well formation to the sensor10. The retaining member208may include hinges and fasteners such that the retaining member208may be moved to allow the sensor10to be removed from the downhole tool.

As depicted, the sensor10includes the sensing component14, an acoustic sensor transmitter (“transmitter”)202, and an acoustic sensor receiver (“receiver”)204. In at least one embodiment, the transmitter202and receiver204are wirelessly coupled. As such, the transmitter202transmits information, based on a signal it receives from the sensing component14, wirelessly to the receiver204, which receives the information. The transmitter202may include elements of circuits or integrated circuits that process the signal received from the sensing component14into information using amplifiers, filters, and the like. The receiver204may also include elements of circuits or integrated circuits that process the information received from the transmitter202into data using amplifiers, filters, and the like. Due to the wireless coupling, the transmitter202and receiver204may be separated, as depicted, by one or more layers of polymers, such as rubber206or PEEK200, 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 transmitter202and receiver204. In at least one embodiment, the coupling of connector pins21to controller54(depicted inFIG. 5) is implemented through a wireway210. Similarly, the connector pins21may couple to other electronic circuitry. Using this coupling, the controller54or other electronic circuitry receives data from the receiver204based on the information.

In a non-illustrated embodiment, the sensing component14and the transmitter202may be enclosed in or supported by a polymer layer (as described above), and the combination of sensing component14, transmitter202and 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 component14, while the container protects the sensing component14from 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 component14and the transmitter202may 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 transmitter202and the receiver204are inductively coupled, i.e., indirectly coupled via induction without wires connecting the transmitter202and receiver204. 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 transmitter202may be an inductive circuit that is coupled to the sensing component14. Similarly, the receiver204may be an inductive circuit. Such inductive circuits may be integrated circuits and may reside on printed circuit boards. In at least one embodiment, the transmitter202and receiver204share 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 transmitter202may transmit the information to the receiver204using radio waves. For example, the transmitter202may include a radio wave transmitter to encode information about the received signal. The receiver204may include an antenna to receive the radio waves. As other alternatives, the transmitter202and receiver204may 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 transmitter202and receiver204, the sensor10may be reduced in size and cost. Specifically, a mechanical coupling (i.e., a physical connection between the transmitter202and receiver204) may be eliminated. By virtue of the reduction in size of the sensor10, 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 sensor10would result in disadvantages. First, the sensor10would inhabit a greater percentage of the downhole tool resulting in less space for other downhole tool elements. Second, a sensor10inhabiting 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 transmitter202and receiver204reduces the amount of service and maintenance required by the sensor10and downhole tool because the removal of a mechanical coupling (i.e., a physical connection between the transmitter202and receiver204) adds greater integrity to the sensor10and 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 sensor10to another part thereof or from the sensor10to 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. 3illustrates a method300for wireless transmission of well formation information, beginning at302and ending at310, in accordance with at least one illustrated embodiment. At304, 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. At306, 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 method300further includes wirelessly receiving, e.g., inductively, optically, capacitively, or via radio waves in various embodiments, the information based on the signal. At308, 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 method300includes any action described in this disclosure.

FIG. 4illustrates an embodiment of a downhole tool segment44. The downhole tool segment44may, without limitation, be substantially cylindrical, for example, largely symmetrical about cylindrical axis50(also referred to as a longitudinal axis), as depicted inFIG. 4. Again as illustrated inFIG. 4, downhole tool segment44may include a substantially cylindrical sensor housing18configured for coupling to a drill string36(depicted inFIG. 7) or wireline (not depicted) and therefore may include threaded end portions6for coupling to drill string36or a wireline. Through pipe52, 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 bit34(depicted inFIG. 7).

The sensor housing18may define at least one aperture8bordered by housing opening edges48(depicted inFIG. 1). The sensor10is situated in the aperture8and is supported by the sensor housing18. The downhole tool segment44may include one or more sensors10.

FIG. 5illustrates a cross-sectional view of a downhole tool segment. The depicted downhole tool segment44includes three sensors10configured about the cylindrical axis50. Two of the sensors10are configured on either side of the through pipe52. 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 sensor10is positioned such that the sensing component14of the sensor10is directed toward and is in communication with the exterior of the downhole tool segment44. Furthermore, each sensor10may abut the housing opening edges48. In such a configuration, the widest external dimension of the polymer22(depicted inFIG. 1) surrounding the sensor's sensing component14abuts the widest internal dimension defined by the aperture8(depicted inFIG. 4) in the sensor housing18, so as to create a seal between (polymer22surrounding) sensing component14and sensor housing18. Each sensor10may be sealed within the sensor housing18to substantially prevent the flow of drilling fluid from the exterior of the downhole tool segment44from entering through the aperture8to the interior46of the downhole tool segment44. In such aspects of the downhole tool segment44, the seal between each sensor10and the sensor housing18may be fluid tight between the polymer22covering the sensor10and the housing opening edges48of the sensor housing18. During operation, the exterior of the downhole tool segment44may be subject to high temperatures and high pressures. The interior46of the downhole tool segment44may be at a lower temperature and pressure such as atmospheric pressure.

The electronics module or controller54may 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 sensors10. Controller54may also include other controllable components, such as additional sensors, data storage devices, power supplies, timers, and the like. The controller54may also be in electronic communication with various sensors and/or probes for monitoring physical parameters of the wellbore38(FIG. 7), such as a gamma ray sensor, a depth detection sensor, or an accelerometer. The controller54may also communicate with other instruments in the drill string36(depicted inFIG. 7), wireline (not depicted), or drilling system30(depicted inFIGS. 6 and 7), such as telemetry systems that communicate with the surface in various embodiments. Also, the controller54may further include volatile or non-volatile memory or a data storage device. Further, while the controller54is shown within downhole tool segment44, it may alternatively be located elsewhere in the drill string36, wireline (not depicted), or drilling system30.

The controller54may 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 segment44. The controller54may 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 contacts20of sensors10may be in operable connection with the controller54. These electrical contacts20may be configured to communicate detected conditions to the controller54or to other elements utilizing the sensor10. Thus, during use, conditions sensed by the sensor10are communicable to the controller54. Depending upon the condition detected, adjustments to the operation of the drilling system30may be made.

FIG. 6illustrates an example of a drilling system30in which sensors10of the present disclosure may be utilized. The depicted drilling system30includes a wireline (not depicted) that extends underneath an earthen surface32. According toFIG. 6, the earthen surface32is an off-shore location, but in other aspects, the earthen surface32may be an on-shore location. The wireline of the depicted drilling system30may include several active devices such as multiple sensors10aligned along a portion of the line and situated within a downhole location40.

FIG. 7illustrates another example of a drilling system30in which sensors10of the present disclosure may be utilized. The depicted drilling system30includes a drill string36extending into a wellbore38that extends beneath an earthen surface32. According toFIG. 7, the earthen surface32is an off-shore location, but in other aspects, the earthen surface32may be an on-shore location. A downhole tool, including downhole tool segment44housing one or more sensors10, is included along the drill string36. An earth-boring tool, such as a drill bit34or reamer, is also coupled to the drill string36. The drill string36may further include other active devices such as a downhole drill motor and one or more additional sensors for sensing downhole characteristics of the wellbore38and 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.