NO20171001A1 - Downhole acoustic telemetry module with multiple communication modes - Google Patents

Description

DOWNHOLE ACOUSTIC TELEMETRY MODULE WITH MULTIPLE

COMMUNICATION MODES

BACKGROUND

During oil and gas exploration and production, many types of information are collected and analyzed. The information is used to determine the quantity and quality of hydrocarbons in a reservoir, and to develop or modify strategies for hydrocarbon production. One technique for collecting relevant information involves measurement-while-drilling (MWD) and logging-while-drilling (LWD).

Various types of telemetry have been developed to convey data uphole and/or dowhole during drilling operations or logging operations. Uphole data often corresponds to MWD or LWD survey data while downhole data corresponds to logging or steering commands. Mud pulse telemetry (MPT) is a commonly used telemetry option, but suffers from a low data rate. Some example efforts to increase the data rate for uphole or downhole communications involve supplementing or replacing MPT with wired telemetry, electromagnetic (EM) telemetry, and/or acoustic telemetry.

Acoustic telemetry is a promising technology, where data can be communicated up to several tens of thousands of feet by arranging acoustic transducers and repeaters along a borehole. Depending on the transmission frequency and modulation scheme, acoustic telemetry data rates of up to 100 bits per seconds may be possible. One of the challenges related to acoustic telemetry is that acoustic data streams need to be distinguished from stray noises that occur in the downhole environment, especially during drilling. Receiver saturation (e.g., due to a nearby transmitter) is another challenge related to acoustic telemetry. When receiver saturation occurs, simultaneously conveying uplink and downlink data is not possible or is otherwise rendered ineffective.

BRIEF DESCRIPTION OF THE DRAWINGS

Accordingly, there are disclosed in the drawings and the following description a downhole acoustic module with multiple communication modes. In the drawings:

FIG. 1 is a schematic diagram showing an illustrative drilling environment.

FIG. 2A and 2B are block diagrams showing illustrative downhole acoustic telemetry arrangements. FIG. 3A is a schematic diagram showing a pair of acoustic telemetry modules in a first communication mode scenario.

FIG. 3B is a cross-sectional view of an acoustic telemetry module.

FIG. 3C is a schematic diagram showing a pair of acoustic telemetry modules arranged to communicate using compressional and shear acoustic waves. FIG. 3D is a schematic diagram showing a pair of acoustic telemetry modules in a second communication mode scenario. FIGS. 4A-4E are views showing various acoustic telemetry module deployment options.

FIG. 5 is a flowchart showing an illustrative downhole acoustic telemetry method.

It should be understood, however, that the specific embodiments given in the drawings and detailed description do not limit the disclosure. On the contrary, they provide the foundation for one of ordinary skill to discern the alternative forms, equivalents, and modifications that are encompassed together with one or more of the given embodiments in the scope of the appended claims.

DETAILED DESCRIPTION

Disclosed herein are various methods and systems employing downhole acoustic telemetry modules, each module håving a plurality of transducers and multiple communication modes. In different embodiments, the plurality of transducers correspond to at least a pair of acoustic transmitters and a pair of acoustic receivers arranged as transmitter-receivers or transceivers. The positioning, orientation, and acoustic insulation for the transducers may vary for different embodiments to enable multiple communication modes. The multiple communication modes include, for example, a first communication mode in which transducers of a downhole acoustic telemetry module simultaneously convey uplink data and downlink data (i.e., a full-duplex or two-way mode). In a second communication mode, transducers of a downhole acoustic telemetry module simultaneously convey only uplink data or only downlink data (i.e., a half-duplex or one-way mode). The second communication mode provides an increased uplink data rate or an increased downlink data rate relative to the first communication mode. Alternatively, the second communication mode provides an increased uplink data redundancy or an increased downlink data redundancy relative to the first communication mode. Additional communication mode options are possible. For example, the second communication mode may be further divided into four categories or sub-modes: an uplink option with an increased data rate relative to the first communication mode, an uplink option with an increased data redundancy relative to the first communication mode, a downlink option with an increased data rate relative to the first communication mode, and a downlink option with an increased data redundancy relative to the first communication mode.

The downhole acoustic telemetry modules are deployed, for example, along a drill string or a casing to provide a communication interface between a downhole tool and a surface controller. In at least some embodiments, the downhole tool is part of a bottomhole assembly (BHA) configured to transmit uplink data such as measurement-while-drilling (MWD) or logging-while-drilling (LWD) survey data. Alternatively, the downhole tool may correspond to a sensor unit or sensor assembly configured to transmit uplink data. Alternatively, the downhole tool may correspond to an actuator unit configured to transmit uplink data. Meanwhile, the surface controller may correspond to a computer or other programmable system that receives uplink data from the downhole tool. The surface controller may store, process, and/or display the uplink data or information obtained using the uplink data. Further, the surface controller may transmit downlink data to the downhole tool via the downhole acoustic telemetry modules. In at least some embodiments, the downlink data may correspond to directional drilling instructions. In other embodiments, the downlink data may correspond to commands for actuating valves or other components (e.g., filters, screens, fluid injectors, perforators) deployed along drill string or casing. In another embodiment, the downlink data may correspond to synchronization data (e.g., clock synchronization), firmware updates, modes of operation (e.g., in the form of an MIT table), and/or other important information for a BHA.

In accordance with at least some embodiments, an example system includes a downhole tool configured to transmit uplink data. The system also includes a surface controller configured to receive the uplink data and to transmit downlink data to the downhole tool. The system also includes a plurality of acoustic telemetry modules deployed downhole, wherein each of the modules selectively operates in a first communication mode in which its transducers simultaneously convey uplink data and downlink data, and in a second communication mode in which its transducers simultaneously convey only uplink data or only downlink data. Meanwhile, an example method includes deploying a tool downhole. The method also includes deploying a plurality of acoustic telemetry modules downhole, wherein each of the modules supports a first communication mode in which its transducers simultaneously convey uplink data and downlink data and a second communication mode in which its transducers simultaneously convey only uplink data or only downlink data. The method also includes using the plurality of acoustic telemetry modules to convey uplink data or downlink data between the tool and a surface controller. Various downhole acoustic telemetry module options, module use options, and module deployment options are disclosed herein.The disclosed methods and systems are best understood in an application context. Turning now to the figures, FIG. 1 shows an illustrative directional drilling environment that includes a drilling platform 2 supporting a derrick 4 with a traveling block 6 for raising and lowering a drill string 8. A top drive 10 supports and rotates the drill string 8 as it is lowered through the wellhead 12. A drill bit 14 is driven by a downhole motor and/or rotation of the drill string 8. As bit 14 rotates, it creates a borehole 16 that passes through various formations. During drilling operations, a pump 20 circulates drilling fluid through a feed pipe 22 to top drive 10, downhole through the interior of drill string 8, through nozzles in drill bit 14, back to the surface via the annulus 9 around drill string 8, and into a retention pit 24. The drilling fluid transports cuttings from the borehole 16 into the pit 24 and aids in maintaining the borehole integrity.

The drill bit 14 is just one piece of a BHA 50 that typically includes one or more drill collars (thick-walled steel pipe) to provide weight and rigidity to aid the drilling process. Some of these drill collars may include a survey tool 26 to gather survey data such as position, orientation, weight-on-bit, borehole diameter, or formation parameters (e.g., resistivity logs, porosity logs, electromagnetic (EM) logs, density logs, sonic logs, seismic logs, gamma ray logs, nuclear magnetic resonance (NMR) logs, etc). The tool orientation may be specified in terms of a tool face angle (rotational orientation), an inclination angle (the slope), and compass direction, each of which can be derived from measurements by magnetometers, inclinometers, and/or accelerometers, though other sensor types such as gyroscopes may alternatively be used. In at least some embodiments, uplink data (e.g., survey data collected by the survey tool 26) and downlink data (e.g., steering commands) is used to steer the drill bit 14 along a desired path 18 relative to bed boundaries 46 and 48 using any one of various suitable directional drilling systems that operate in real-time. Example steering mechanisms include steering vanes, a "bent sub," and a rotary steerable system.

In at least some embodiments, uplink data and downlink data are conveyed between a telemetry sub 28 of BHA 50 and earth's surface using acoustic telemetry modules, each module håving at least a first communication mode and a second communication mode as described herein. For example, the telemetry sub 28 may include an acoustic telemetry module while another acoustic telemetry module is at or near earth's surface. As needed, one or more additional acoustic telemetry modules may be deployed as repeaters along the drill string 8. In at least some embodiments, telemetry sub 28 also may support other telemetry options such as mud pulse telemetry, electromagnetic telemetry, and wired telemetry. Regardless of the type(s) of telemetry employed telemetry sub 28, one or more transducers 30, 32 at earth's surface convert an uplink data stream into electrical signal(s) for a signal digitizer 34. The digitizer 34 supplies a digital form of the uplink data stream via a communications link 36 to a computer system 37 or some other data processing system. While transducers 30, 32 are shown to be positioned along feed pipe 22, it should be appreciated that one or more of such transducers 30, 32 may be positioned elsewhere to convey an uplink data stream to digitizer 34. Further, the transducers 30, 32 or other transducers (not shown) may operate to convert an electrical signal corresponding to a downlink data stream (e.g., from computer system 37 or link 36) into an acoustic signal or other telemetry signal for conveyance downhole towards BFIA 50.

In at least some embodiments, the computer system 37 includes a processing unit 38 that performs analysis of the data stream and/or performs other operations by executing software or instiuctions obtained from a local or remote non-transitory computer-readable medium 40. The computer system 37 also may include input device(s) 42 ( e. g., a keyboard, mouse, touchpad, etc.) and output device(s) 44 ( e. g., a monitor, printer, etc). Such input device(s) 42 and/or output device(s) 44 provide a user interface that enables an operator to interact with the BHA 50, surface/downhole directional drilling components, and/or software executed by the processing unit 38. For example, the computer system 37 may enable an operator to review or select: drilling options, survey tool options ( e. g., to update the operations of survey tool 26), data logs derived from the survey data, plans derived from the survey data, drilling status charts, waypoints, a desired borehole path, an estimated borehole path, data processing options, telemetry options and/or to perform other tasks. As needed, the computer system 37 may provide downlink data to a tool (e.g., telemetry sub 28, survey tool 26) that is part of the BHA 50 or to other downhole tools.

FIG. 2A and 2B are block diagrams showing illustrative downhole acoustic telemetry arrangements 100A and 100B. In arrangements 100A and 100B, a plurality of acoustic telemetry modules 104A-104N are positioned between a surface controller 102 and downhole tool 106. The surface controller 102 may correspond to a computer system (e.g., computer system 37) or another programmable controller. Meanwhile, the downhole tool 106 may be part of a BHA (e.g., telemetry sub 28, survey tool 26), a sensor unit deployed along a drill string or casing, an actuator unit deployed along a drill string or casing, or another type of tool. In the arrangements 100A and 100B, each of the acoustic telemetry modules 104A-104N supports at least a first communication mode in which its transducers simultaneously convey uplink data and downlink data and a second communication mode in which its transducers simultaneously convey only uplink data or only downlink data. The difference between arrangements 100A and 100B is that arrangement 100B includes short hop telemetry modules 108 between the surface controller 102 and the downhole tool 106. As shown, short hop telemetry modules 108 may be positioned between different acoustic telemetry modules. Alternatively, short hop telemetry modules 108 may be positioned between the surface controller 102 and the acoustic telemetry modules 104A-104N. Alternatively, short hop telemetry modules 108 may be positioned between the downhole tool 106 and the acoustic telemetry modules 104A-104N. The short hop modules 108 use non-acoustic telemetry techniques (e.g., EM, wired, mud pulse) to convey uplink data or downlink data part of the distance between the downhole tool 106 and surface controller 102. For example, short hop modules 108 may be deployed at portions of the path between downhole tool 106 and surface controller 102, where an acoustic channel is unavailable or degraded. For example, short hop modules 108 may be used in a BHA to convey sensor data from sensors near the drill bit 14 to the telemetry sub 28 (e.g., to convey data from one side of a mud motor to the other side). Further, short hop modules 108 may be used at earth's surface to convey a data stream from computer system 37 or communication link 36 to an acoustic telemetry module along the drill string 8. Further, short hop modules 108 may be used along the drill string 8, where the acoustic channel is unavailable or degraded.

FIG. 3A is a schematic diagram showing a pair of acoustic telemetry modules 104A and 104B in a first communication mode scenario in which transducers of modules 104A and 104B simultaneously convey uplink data and downlink data. As shown, the acoustic telemetry module 104A includes at least two transducers (receiver HOA and transmitter 112A) separated by acoustic dampening material 118. Similarly, the acoustic telemetry module 104B includes at least two transducers (receiver 110B and transmitter 112B) separated by acoustic dampening material 118. The orientation of the receiver 11 OA and transmitter 112 A of module 104 relative to the receiver 11 OB and transmitter 112B of module 104B is reversed such that transmitter 112A is aligned with receiver 11 OB, while transmitter 112B is aligned with receiver HOA. Thus, transmitter 112A and receiver 11 OB are acoustically separated from transmitter 112B and receiver HOA (at least sufficiently to enable full-duplex communications). In at least some embodiments, the acoustic dampening material 118 corresponds to Fluorocarbon cement (e.g., Tungsten powder + Viton Cement - Elastomer compound) or another known acoustic dampening material, such as backing material, highly-saturated nitrile (HSN) rubber with Carbide chips, or Viton rubber with Tungsten Carbide chips.

In at least some embodiments, acoustic dampening material 118 is placed such that it surrounds the transducers (receivers/transmitters) in a module 104. For example, acoustic dampening material 118 may surround both transmitter 112A and receiver HOA of module 104 to prevent a leakage path between the transmitter 112A and the receiver 110A. Acoustic dampening material 118 may additionally or alternatively be added in the space between transducers in a module 104 for absorption between the transducers.

FIG. 3B is a cross-sectional view of an acoustic telemetry module 104 corresponding to a tubular or ring 120 with a receiver 110 and a transmitter 112. The tubular or ring 120 may, for example, correspond to a protective sleeve with acoustic telemetry components, where the tubular or ring 120 attaches to the interior or exterior of a drill string or casing segment. For an interior attachment scenario, the outer surface of the tubular or ring 120 holds a corresponding acoustic telemetry module 104 in place by contacting the interior of a drill string or casing segment. For an exterior attachment scenario, the inner surface of the tubular or ring 120 holds a corresponding acoustic telemetry module 104 in place by contacting an exterior surface of drill string or casing segment.

As shown in FIG. 3B, acoustic dampening material 118 surrounds the receiver 110 and the transmitter 112. Further, acoustic dampening material 118 is embedded into the ring or tubular 120 at various locations between transmitter 110 and receiver 112. The amount of acoustic dampening material 118 may be small compared to the total cross-sectional area of the ring or tubular 120 so as to ensure the strength of the ring or tubular 120 is not compromised by the acoustic dampening material 118. As needed, acoustic absorption material can also be positioned between an acoustic telemetry module 104 and a drill bit or reamer to reduce the amount of noise from known or potential sources of interference. For more information regarding acoustic dampening materials, reference may be had to U.S. Pat. Nos. 7,068,183 and 7,210,555. However, it should be noted that at least some of the acoustic dampening applied herein is to prevent receiver saturation rather than to prevent noise coupling as in U.S. Pat. Nos. 7,068,183 and 7,210,555. To prevent receiver saturation as described herein, at least some of the acoustic dampening material 118 is selected to attenuate both high and low frequencies or just the higher frequencies at which communications take place rather than lower frequencies associated with drilling noise.

Besides using acoustic dampening material 118 to reduce interference and/or receiver saturation, the transmitters 112A and 112B may transmit at different carrier frequencies to reduce interference and/or receiver saturation. Further, the acoustic channel(s) 105 and the acoustic telemetry modules 104A and 104B may support unidirectional transmission paths to reduce interference and/or receiver saturation. Further, the position of transducers (transmitters/receivers) may be selected to reduce interference and/or receiver saturation. As shown in FIG. 3B, receiver 110 and transmitter 112 are on opposite sides of the ring or tubular 120 (i.e., a 180° offset). In an alternative embodiment, transducers are positioned on different sides of the ring or tubular 120 (e.g., a 90° offset or some other offset), but not on opposite sides. In either case, the position of transducers should provide sufficient separation to enable placement of acoustic dampening material 118 around and/or between the transducers.

In at least some embodiments, acoustic telemetry modules 104A and 104B also include controllers (CTRLs) 116A and 116B. Each of the controllers 116A and 116B provides features such as power, data storage/buffering, and mode control for its respective module. In FIG. 3A, the acoustic telemetry modules 104A and 104B operate in a first communication mode, in which uplink data and downlink data are conveyed at the same time (i.e., receiver HOA receives uplink data as transmitter 112A transmits downlink data, receiver 11 OB receives downlink data as transmitter 112B transmits uplink data, and so on).

Besides providing separate acoustic channels and separate transmitters/receivers for each channel, another way to enable simultaneous conveyance of uplink data and downlink data at each acoustic telemetry module involves using different types of acoustic waves, namely shear waves and compressional waves. FIG. 3C shows another first communication mode scenario, in which acoustic telemetry modules 104A and 104B simultaneously convey uplink data and downlink data using compressional and shear acoustic waves. In FIG. 3C, transmitter 122A of module 104A and transmitter 122B of module 104B correspond to actuators which actuate in their axial direction. Meanwhile, receiver 120 A of module 104 A and receiver 120B of module 104B correspond to transducers that are directionally sensitive to particle motion in their axial direction, which is oriented perpendicular to their nearby transmitter. Shear waves propagate perpendicular to the direction of excitation, while compressional waves travel in the same direction as the direction of excitation. Thus, in FIG. 3C, transmitter 122A of module 104A outputs compressional waves in the direction of telemetry and shear waves perpendicular to the direction of telemetry. This allows receiver 120A to receive a much attenuated wave from the transmitter 122A, hence reducing the likelihood of receiver saturation. Similarly, transmitter 122B of module 104B outputs shear waves in the direction of propagation and compressional waves perpendicular to the direction of telemetry.

In at least some embodiments, transmitter 122A and receiver 120A of module 104A are orientated 90° apart. Meanwhile, transmitter 122B and receiver 120A of module 104A are oriented 90° apart. In other words, transmitter 122A and receiver 120B share a first orientation, while transmitter 122B and receiver 120A share a second orientation that is offset from the first orientation by 90°. By arranging the transmitters and receivers of adjacent acoustic telemetry modules carefully as in FIG. 3C, receiver saturation (due to transmitter 122A being in close proximity to receiver 120A, and due to transmitter 122B being in close proximity to receiver 120B, and so on) can be avoided using shear waves and compressional waves to convey uplink data and downlink data.

In FIG. 3C, controllers 116A and 116B again provide features such as power, data storage/buffering, and mode control for its respective module. Further, in at least some embodiments, an attenuator 116 may be positioned between the lowest acoustic telemetry module (module 104B in FIG. 3C) and the drill bit 14. Attenuator 116 may be formed from acoustic dampening material (e.g., material 118), and may cover as much cross-sectional area of a tubular (e.g., a drill string or casing) as possible, or only selected portions of a tubular.

Besides the first communication mode, acoustic telemetry modules such as acoustic telemetry modules 104A-104N may also operate in a second communication mode in which their respective transducers simultaneously convey only uplink data or only downlink data. FIG. 3D is a schematic diagram showing acoustic telemetry modules 104A and 104B in a second communication mode scenario. In order to support the second communication mode, the acoustic telemetry module 104A includes a pair of transceivers 11 IA and 11 IB, while acoustic telemetry module 104B includes another pair of transceivers 111C and 11 ID. Comparing the first communication mode scenario of FIG. 3A with the second communication mode scenario of FIG. 3D, itshouldbenotedthatreceivers HOA, 110B, and transmitters 112A, 112B in FIGS. 3A and 3C may be part of transceivers 11 lA-11 ID in FIG. 3D (e.g., receiver HOA may be part of transceiver 11 IA, transmitter 112A may be part of transceiver 11 IB, transmitter 112B may be part of transceiver 111C, and receiver 11 OB may be part of transceiver 11 ID). In an alternative embodiment, transceivers 111A-111D may each be replaced by a transmitter-receiver (the difference being that transceivers share more circuitry than a transmitter-receiver). In the second communication mode scenario of FIG. 3D, conveyance of downlink data is represented where transceivers 11 IA and 11 IB transmit downlink data and transceivers 111C and 11 ID receive downlink data. The downlink data being transmitted in the second communication mode scenario of FIG. 3D may be associated with a higher data rate compared to the downlink data transmitted in the first communication mode scenarios of FIG. 3 A and 3C. For example, each of the transceivers 11 IA and 11 IB may transmit half of a data package.

Alternatively, the downlink data being transmitted in the second communication mode scenario of FIG. 3D may be associated with a greater reliability or redundancy compared to the downlink data transmitted in the first communication mode scenarios of FIGS. 3 A and 3C. By conveying uplink data or downlink data redundantly using different sets of transceivers, multiple sets of data received by the surface controller 102 or the downhole tool 106 can be compared to correct for each other as needed (e.g., in case one of the links is not functioning as expected). Link failure can be due to different reasons such as failure of a particular transceiver or the noise level being too high at a particular transceiver (e.g., due to the SNR being negatively affected by the drill string contacting the formation at one or more spots).

While the second communication mode scenario of FIG. 3D shows conveyance of downlink data, it should be appreciated that acoustic telemetry modules 104A-104N may use a similar communication mode to convey uplink data (e.g., to convey uplink data from downhole tool 106 to surface controller 102). Further, it should be appreciated that the acoustic telemetry modules 104A-104N may switch between using the second communication mode for downlink data and using the second communication mode or similar mode for uplink data (i.e., the second communication mode could include different categories or sub-modes corresponding to an uplink option with a higher data rate relative to the first communication mode, an uplink option with a higher data redundancy relative to the first communication mode, a downlink option with a higher data rate relative to the first communication mode, and a downlink option with a higher data redundancy relative to the first communication mode). Further, the acoustic telemetry modules 104A-104N may switch between any of the second communication mode options and the first communication mode as needed.

To switch between the different communication modes, the controller 116 for each acoustic telemetry module 104 may receive commands and/or may be programmed to switch communication modes according to a predeterminedSchedule. During drilling operations, the first communication mode may be used to enable a BELA (e.g., BELA 50) to receive geosteering commands while transferring uplink data (e.g., data collected by survey tool 26). Without the first communication mode, a delay of 30 seconds or more between geosteering commands would occur, which could negatively affect the steering path. On the other hand, uplink data is usually more abundant compared to downlink data (e.g., geosteering commands). Accordingly, there may be times when the second communication mode is preferred over the first communication mode. Further, as desired, drilling operations can be slowed or stalled to increase the amount of uplink data and downlink data received relative to the amount of drilling that occurs.

In at least some embodiments, the transducers used for the acoustic transmitters/receivers of the acoustic telemetry modules 104 correspond to piezoelectric or magnetostrictive materials. Piezoelectric transducers have been used in a wide range of downhole products/services (e.g., BAT™, seismic-while-drilling, ATS™, Dynalink®) and can be driven at a wide range of voltages. The power consumption to operate such transducers can be very low (e.g., on the order of milliamps per hour), while providing a telemetry system capable of sending information up to 10,000 feet along a drill string or casing. The same or similar acoustic telemetry modules described herein can also be used for short hop scenarios (e.g., to hop 40 ft or so across a mud motor for MWD or LWD scenarios). The modulation scheme for acoustic telemetry using acoustic telemetry modules as described herein depends on the desired transmission frequency spectrum and processor capability. Different modulation scheme enable different data rates at different frequency bands. While acoustic telemetry has been determined to support data rates of about 100 bits per second, greater data rates may be possible depending on the modulation scheme employed.

In different embodiments, acoustic telemetry modules 104 may be deployed along a drill string or casing by attaching modules inside or outside of a drill string or casing and/or by integrating module components with a drill string or casing. FIGS. 4A-4E shows various acoustic telemetry module deployment options. Specifically, FIG. 4A shows an acoustic telemetry module 104 with a sleeve protector that houses and protects acoustic telemetry components (e.g., a pair of transceivers 111 and a controller 116). Acoustic dampening material could also be integrated with the sleeve protector as desired. The illustrative sleeve protector has two semi-cylindrical components 204A, 204B that can be secured together around a tubular 202 (e.g., a drill string or casing) by threaded connectors such as screws or bolts 206. The materials used for the sleeve protector can be a metallic or non-metallic material that is resilient and cushions impacts to prevent crushing of acoustic telemetry components. Further, the sleeve protector should be compatible with providing one or more acoustic channels. In some embodiments, instead of using threaded connectors and bolts, an alternative arrangement for the semi-cylindrical components 204A, 204B may be to use hinged components with fingers that mesh to form a keyway, where the sleeve protector is closed when a key is forced into the keyway. In either case, the sleeve protector enables corresponding acoustic telemetry modules 104 to be readily removed and replaced as needed. In other embodiments, a sleeve protector with acoustic telemetry components can be welded in place, or acoustic telemetry components can be encased in a moldable material around a tubular, where the moldable material is compatible with acoustic telemetry.

FIG. 4B shows another deployment option, in which an acoustic telemetry module 104 includes a protective sleeve formed from two U-shaped components 304A, 304B that when held together by a clamp 216 form a hollow cylinder. A cross-sectional view of the deployment option represented in FIG. 4B is shown in FIG. 4D. As shown, the larger U-shaped component 304A houses a pair of transceivers 111 and a controller 116, where conductors 220 couple the controller 116 to each transceiver 111. The component 304A has an opening large enough to accommodate a tubular 202, while component 304A fills the opening to complete a cylindrical profile. The clamp 216 (FIG. 4B) can take the form of a so-called "hose clamp", which is a metal strip håving apertures to engage the threads of a screw. As the screw is turned, the strap is tightened in a recess to secure components 304A and 304B in place. Other techniques can alternatively or additionally be employed, including without limitation: keys, bolts, adhesives, and welds. FIG. 4C shows a variation of the package in FIG. 4B, in which the U-shaped components 304A, 304B conform to the taper around the base of the box end 210 (or pin end). This variation may offer increased protection for acoustic telemetry components by improving the mesh between the protective sleeve and other components of a drill string or casing. In both embodiments, the inner surface of the components 304A, 304B can be roughened to increase adhesion to the tubular.

It should be noted that protective sleeves with acoustic telemetry components could be placed inside a tubular rather than outside a tubular. For example, FIG. 4E shows an illustrative deployment option in which acoustic telemetry components are positioned on the interior of a tubular. More specifically, a package 224 with transceivers 111 and a controller (not shown) may be positioned at the base of box 210 and held in place by a fully seated pin end 230. The package 224 has an outer diameter slightly smaller than the inner diameter of the box bore (with O-rings to provide a pressure seal), and an inner diameter matching the inner diameter of the rest of the adjacent drill string or casing.

In at least some embodiments, acoustic telemetry modules 104 may include sensors (e.g., temperature sensors, pressure sensors, mud resistivity sensors, accelerometers, calipers, sensors for specific chemicals, etc.) inside or outside a package or protective sleeve. Alternatively, the sensors are deployed separately, but are in communication with the acoustic telemetry modules 104. At least some of the data collected by such sensors can be transmitted periodically by the acoustic telemetry modules 104 along with other uplink data (e.g., from the downhole tool 106). As needed, uplink data and sensor data can be buffered or combined using packets håving a predetermined format to convey information from the downhole tool 106 and/or sensors deployed along a drill string or casing.

FIG. 5 is a flowchart showing an illustrative downhole acoustic telemetry method 400. In method 400, a tool is deployed downhole (block 402). The downhole tool may correspond to part of a BELA or sensors/actuators positioned along a drill string or casing as described herein. At block 404, acoustic telemetry modules are deployed downhole, where each of the modules supports multiple communication modes. The acoustic telemetry modules may be separate from the downhole tool or, alternatively, one of the acoustic telemetry modules may be included with the downhole tool. As described herein, in at least some embodiments, each of the acoustic telemetry modules supports a first communication mode in which its transducers simultaneously convey uplink data and downlink data and a second communication mode in which its transducers simultaneously convey only uplink data or only downlink data. At block 406, the acoustic telemetry modules convey uplink data or downlink data between the tool and a surface controller. In some embodiments, the uplink data corresponds to survey data collected by one or more survey tools of a BHA, and the downlink data corresponds to directional drilling commands. In alternative embodiments, the uplink data corresponds to sensor data collected by one or more sensors deployed along a drill string or casing, and the downlink data corresponds to commands for actuators deployed along a drill string or casing (e.g., to move a valve or screen). As another example, downlink data may correspond to commands to direct operations of a well completion tool (e.g., a perforator) or a well intervention tool (e.g., to "fish" an object or fix a degraded or improper seal).

Embodiments disclosed herein include:

A: A system that comprises a downhole tool configured to transmit uplink data. The system also comprises a surface controller configured to receive the uplink data and to transmit downlink data to the downhole electronics. The system also comprises a plurality of acoustic telemetry modules deployed downhole, wherein each of the modules selectively operates in a first communication mode in which its transducers simultaneously convey uplink data and downlink data and a second communication mode in which its transducers simultaneously convey only uplink data or only downlink data.

B: A method that comprises deploying a tool downhole and deploying a plurality of acoustic telemetry modules downhole. Each of the modules supports a first communication mode in which its transducers simultaneously convey uplink data and downlink data and a second communication mode in which its transducers simultaneously convey only uplink data or only downlink data. The method also comprises using the plurality of acoustic telemetry modules to convey uplink data or downlink data between the tool and a surface controller.

Each of the embodiments, A and B, may have one or more of the following additional elements in any combination. Element 1: wherein the second communication mode provides an increased uplink data rate or an increased downlink data rate relative to the first communication mode. Element 2: wherein the second communication mode provides an increased uplink data redundancy or an increased downlink data redundancy relative to the first communication mode. Element 3: wherein each of the modules is configured to convey uplink data or downlink data using both compressional waves and shear waves. Element 4: wherein each of the modules comprises transducers positioned on different sides of a ring or tubular. Element 5: wherein each of the modules further comprises acoustic dampening material surrounding at least one of its transducers. Element 6: wherein each of the modules further comprises acoustic dampening material integrated with the ring or tubular, and positioned between adjacent transducers. Element 7: wherein each of the modules attach to an interior of a drill string or casing. Element 8: wherein each of the modules attach to an exterior of a drill string or casing. Element 9: wherein each of the modules is integrated with a drill string or casing coilar. Element 10: further comprising short hop telemetry modules between the downhole tool and the surface controller. Element 11: wherein each of the modules is configured to use a drill string or casing as an acoustic channel for conveying the uplink data or downlink data. Element 12: wherein the downhole tool is part of a BHA, wherein the uplink data corresponds to MWD or LWD data, and wherein the downlink data corresponds to steering commands for the BHA.

Element 13: further comprising switching between the first communication mode and the second communication mode based on a trigger event. Element 14: further comprising selecting a switching schedule for the first communication mode and the second communication mode. Element 15: further comprising adjusting the switching schedule for the first communication mode and the second communication mode. Element 16: wherein using the plurality of acoustic telemetry modules to convey uplink data or downlink data comprises using a drill string or casing as an acoustic channel and providing acoustic dampening between or around acoustic transducers of each module. Element 17: wherein using the plurality of acoustic telemetry modules to convey uplink data or downlink data involves use of both compressional waves and shear waves. Element 18: further comprising attaching each module along a drill string or casing.

Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such variations and modifications.

Claims (20)

1. A system that comprises: a downhole tool configured to transmit uplink data; a surface controller configured to receive the uplink data and to transmit downlink data to the downhole tool; and a plurality of acoustic telemetry modules deployed downhole, wherein each of the modules selectively operates in a first communication mode in which its transducers simultaneously convey uplink data and downlink data, and in a second communication mode in which its transducers simultaneously convey only uplink data or only downlink data.

2. The system of claim 1, wherein the second communication mode provides an increased uplink data rate or an increased downlink data rate relative to the first communication mode.

3. The system of claim 1, wherein the second communication mode provides an increased uplink data redundancy or an increased downlink data redundancy relative to the first communication mode.

4. The system of claim 1, wherein each of the modules is configured to convey uplink data or downlink data using both compressional waves and shear waves.

5. The system of claim 1, wherein each of the modules comprises transducers positioned on different sides of a ring or tubular.

6. The system of claim 5, wherein each of the modules further comprises acoustic dampening material surrounding at least one of its transducers.

7. The system of claim 5, wherein each of the modules further comprises acoustic dampening material integrated with the ring or tubular, and positioned between adjacent transducers.

8. The system in accordance with any one of claims 1 to 7, wherein each of the modules attach to an interior of a drill string or casing.

9. The system in accordance with any one of claims 1 to 7, wherein each of the modules attach to an exterior of a drill string or casing.

10. The system in accordance with any one of claims 1 to 7, wherein each of the modules is integrated with a drill string or casing coilar.

11. The system in accordance with any of claims 1 to 7, further comprising short hop telemetry modules between the downhole tool and the surface controller.

12. The system in accordance with any of claims 1 to 7, wherein each of the modules is configured to use a drill string or casing as an acoustic channel for conveying the uplink data or downlink data.

13. The system in accordance with any of claims 1 to 7, wherein the downhole tool is part of a bottomhole assembly (BHA), wherein the uplink data corresponds to measurement-while-drilling (MWD) or logging-while-drilling (LWD) data, and wherein the downlink data corresponds to steering commands for the BHA.

14. A method that comprises: deploying a tool downhole; deploying a plurality of acoustic telemetry modules downhole, wherein each of the modules supports a first communication mode in which its transducers simultaneously convey uplink data and downlink data and a second communication mode in which its transducers simultaneously convey only uplink data or only downlink data; using the plurality of acoustic telemetry modules to convey uplink data or downlink data between the tool and a surface controller.

15. The method of claim 14, further comprising switching between the first communication mode and the second communication mode based on a trigger event.

16. The method of claim 14, further comprising selecting a switching schedule for the first communication mode and the second communication mode.

17. The method of claim 16, further comprising adjusting the switching schedule for the first communication mode and the second communication mode.

18. The method in accordance with any one of claims 14 to 17, wherein using the plurality of acoustic telemetry modules to convey uplink data or downlink data comprises using a drill string or casing as an acoustic channel and providing acoustic dampening between or around acoustic transducers of each module.

19. The method in accordance with any one of claims 14 to 17, wherein using the plurality of acoustic telemetry modules to convey uplink data or downlink data involves use of both compressional waves and shear waves.

20. The method in accordance with any one of claims 14 to 17, further comprising attaching each module along a drill string or casing.