US20210189871A1

US20210189871A1 - Downhole communication system

Info

Publication number: US20210189871A1
Application number: US17/123,330
Authority: US
Inventors: Wesley Blackman; David L. Smith
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2019-12-23
Filing date: 2020-12-16
Publication date: 2021-06-24

Abstract

A downhole communication system includes a rebroadcaster. The rebroadcaster includes a receiver configured to receive signals from a surface location. A processor on the rebroadcaster demodulates and converts the signal into a pressure pulse pattern. The pressure pulse pattern is transmitted to a downhole tool as a pressure pulse signal using a mud pulse generator.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. Provisional Application No. 62/952,701, filed on Dec. 23, 2019, the entirety of which is incorporated herein by reference.

BACKGROUND

Downhole drilling systems may include many different downhole tools, sensors, computers, communication systems, and other tools. These downhole tools may receive instructions and/or information from a surface location. Various communication mechanisms, systems, devices, and methods exist. For example, wired drill pipe includes communication wire inside the wall, attached to the outside, or attached to the inside of the drill pipe, and communication may transmit through the communication wire. Wireless communication, such as electromagnetic downlink, may transmit information wirelessly through a formation. Mud pulse telemetry may change the flow rate and/or the pressure of the drilling fluid flowing through the drill pipe.

SUMMARY

In some embodiments, a method for downhole communication includes receiving a signal at a rebroadcaster. The signal is converted to a pressure pulse pattern at a processor on the rebroadcaster. The pressure pulse pattern is then transmitted using a mud pulse generator located downhole.
In some embodiments, a method for downhole communication includes transmitting a signal from a surface location while the pumps are turned off. The signal is received at a rebroadcaster and converted into a pressure pulse pattern. A mud pulse generator then generates pressure pulses in the drilling fluid in the pressure pulse pattern when the pumps are turned back on.
In some embodiments, a system for downhole communication includes a rebroadcaster. The rebroadcaster includes a receiver, a processor, and a pressure pulse generator.
This summary is provided to introduce a selection of concepts that are further described in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 is representation of a drilling system; according to embodiments of the present disclosure;

FIG. 2 is a representation of a downhole communication system, according to embodiments of the present disclosure;

FIG. 3-1 and FIG. 3-2 are schematic representations of a downhole communication system, according to embodiments of the present disclosure;

FIG. 4 is a representation of a method for downhole communication, according to embodiments of the present disclosure; and

FIG. 5-1 and FIG. 5-2 are representations of methods for downhole communication, according to embodiments of the present disclosure.

DETAILED DESCRIPTION

This disclosure relates to devices, systems, and methods for downhole communication. In some embodiments, a rebroadcaster may receive a signal transmitted from the surface, convert the signal to a pressure pulse pattern, and transmit the pressure pulse pattern using a pressure pulse generator. Rebroadcasting the signal may allow downhole tools that may not be configured to receive the signal, but that may receive pressure pulses (e.g., measure changes in pressure and/or changes in flow rate), to receive signals from the surface. In some embodiments, a pressure pulse generator may generate pressure pulses. However, the pressure pulse generator may generate changes in flow rate and/or that the pressure pulses may be measured as either changes in flow rate or changes in fluid pressure. Furthermore, the signal may be broadcast without disrupting drilling activities (e.g., pumping), and the signal may be rebroadcast while drilling. This may decrease the amount of down time experienced by the drilling operation, reduce the wear and tear on the drilling system, and decrease costs. For example, the costs may be decreased by reducing the complexity of the system, including wired connections and receivers that can receive surface signals (e.g., electromagnetic downlink receivers) on multiple downhole tools.
FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102. The drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110, attached to the downhole end of drill string 105.
The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.
The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing. The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. In some embodiments, at least a portion of the RSS (e.g., a roll stabilized platform) may maintain a geostationary position relative to an absolute reference frame while drilling a set trajectory, such as relative to gravity, magnetic north, and/or true north. Using measurements obtained with the RSS tool (e.g., sensors on the roll stabilized platform), the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory.
In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.
The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface or may be allowed to fall downhole.
FIG. 2 is a schematic representation of a downhole drilling system 212, according to at least one embodiment of the present disclosure. The downhole drilling system 212 includes a downhole tool 214. In some embodiments, the downhole tool 214 may be located on a roll stabilized platform, which may include an independently rotatable member. The independently rotating member may rotate generate electricity and/or torque to allow the roll stabilized platform to maintain a geostationary position.
In some embodiments, an operator at a surface location 216 may desire to communicate with the downhole tool 214. For example, the operator may desire to send instructions or information to the downhole tool 214. In some embodiments, these instructions may include directions for directional drilling, instructions for a sensor to perform a measurement, instructions to actuate an expandable tool, other downhole instructions, or combinations thereof.
To communicate with the downhole tool 214 from the surface location 216, a signal 218 may be sent from the surface location 216 to a rebroadcaster 220. Communication methods may include one or more of mud pulse generation, wired electromagnetic communication (e.g., wired drill pipe), wireless electromagnetic communication (e.g., electromagnetic downlink), RFID tags sent through the drilling fluid, drop balls, other communication methods, or combinations thereof.
In some embodiments, electromagnetic downlink to the BHA 206 may include one or more transmitters 222 on the surface (such as metal stakes driven into the ground). For example, the transmitters 222 may be located at the surface location 216, at or near the drilling derrick. In some examples, the transmitters 222 may be located in another wellbore offset from the wellbore shown. In some examples, the transmitters 222 may be located in any other location where the signal 218 may be received by the rebroadcaster 220. An electromagnetic signal 218 may be transmitted into the formation 201 through the transmitters 222. The electromagnetic signal 218 may travel through the formation 201. In some embodiments, the electromagnetic signal 218 may be received by equipment mounted on the length of drill pipe. In some embodiments, at least a portion of the electromagnetic signal 218 may be collected by a length of drill pipe 224 in a wellbore. The electromagnetic signal 218 may be transmitted by the length of drill pipe 224 to a gap sub 226 in the length of drill pipe 224 (such as at the rebroadcaster 220). The gap sub 226 may be located anywhere along the length of drill pipe 224. For example, the gap sub 226 may be located at or near the BHA 206.
The gap sub 226 includes a section of insulating material separating two sections of drill pipe 224. The electric potential across the gap sub 226 may be measured. Because the electromagnetic signal 218 is collected along the length of the drill pipe 224, the electromagnetic signal 218 may be received at the gap sub 226 by recording the electric potential across the gap sub 226. The electromagnetic signal 218 may then be demodulated at the rebroadcaster 220 and the information encoded in the electromagnetic signal 218 retrieved.
The rebroadcaster 220 may convert the information from the electromagnetic signal 218 into a pressure pulse pattern. The rebroadcaster 220 may then generate pressure pulses downhole (e.g., at a downhole location) in the pressure pulse pattern to transmit the converted signal to the downhole tool 214. For example, in some embodiments, the rebroadcaster may generate pressure pulses downhole by modifying fluid pressure and/or flow rate. In some embodiments, the rebroadcaster 220 may be a dual telemetry MWD system that is capable of sending and receiving communications via electromagnetic wired telemetry, electromagnetic wireless telemetry, and/or mud pulse telemetry.
FIG. 3-1 is a representation of a downhole communication system 328, according to at least one embodiment of the present disclosure. The downhole communication system 328 may include a surface transmitter 330. The surface transmitter may transmit a signal 332 (such as an electromagnetic downlink signal) to a rebroadcaster 334. The rebroadcaster 334 may receive the signal 332 from the surface transmitter 330 at a receiver 336. A processor 338 on the rebroadcaster 334 may demodulate and interpret the signal 332. The processor 338 may further convert the signal 332 or a portion of the signal into a pressure pulse signal 342. For example, in some embodiments where the rebroadcaster is an MWD tool, the signal may be demodulated, a portion of it utilized in the MWD tool or other tools in wired communication with the MWD tool, and only a portion of the original signal may be converted into a pressure pulse signal.
In some embodiments, the processor 338 may directly convert the signal 332 into a pressure pulse pattern. In other words, the processor 338 may convert bit-for-bit the signal 332 from the source medium (e.g., electromagnetic downlink, wired communication) to a pressure pulse pattern.
In some embodiments, the processor 338 may include a plurality of pre-determined pressure pulse patterns. In some embodiments, the processor 338 may review the signal 332, compare the signal to the plurality of pre-determined pressure pulse patterns, and select a pre-determined pressure pulse pattern of the plurality of pre-determined pressure pulse patterns to transmit as the pressure pulse signal 342. In some embodiments, the signal 332 may include an indication of which pre-determined pressure pulse pattern is to be transmitted. Using pre-determined pressure pulse patterns may reduce the length and/or complexity of the signal 332, reduce the length and/or complexity of the pressure pulse signal 342, reduce the processing power of the processor 338, provide any other benefit, or combinations thereof.
The rebroadcaster 334 may further include a mud pulse generator 340. The processor 338 may cause the mud pulse generator 340 to generate a pressure pulse signal 342 in the pressure pulse pattern. The pressure pulse signal 342 may then be received and interpreted at the downhole tool 344. As is well known in the art, a mud pulse or pressure pulse is a pressure fluctuation that propagates in the drilling fluid and can be used to convey information. The mud pulse generator may be any suitable type of mud pulse generator, e.g., a positive pulse generator, a negative pulse generator, a continuous wave generator (e.g., a siren type rotary pulse generator), or any other type of pulse generator. Information may be encoded with the mud pulse generator using any known technique, such as amplitude shift keying, frequency shift keying, phase shift keying, other encoding techniques, or any combination thereof.
In some embodiments, the pressure pulse signal 342 may include instructions for the downhole tool 344. For example, the pressure pulse signal 342 may include instructions for the downhole tool 344 to change a drilling parameter. In some examples, the instructions may cause the downhole tool 344 to change a directional drilling parameter, such as trajectory (e.g., azimuth and/or inclination), a steering ratio (e.g., steering at 50% of maximum), or other directional drilling parameter. In some examples, the instructions may cause the downhole tool 344 to take a measurement. In some examples, the instructions may cause the downhole tool 344 to actuate. In some examples, the instructions may include any instructions executable by the downhole tool 344.
In some embodiments, the rebroadcaster 334 may include a separate or independent power source. For example, the rebroadcaster 334 may include power storage, such as a battery or a supercapacitor. In some examples, the rebroadcaster 334 may include a power generator, such as a turbine, mud motor, or other power generator. In some embodiments, the power source may power one or more of the receiver, the processor, or the mud pulse generator. In some embodiments, the rebroadcaster 334 may only include the receiver 336, the processor 338, the mud pulse generator 340, and a power source, without any other elements, instruments, or tools. In some embodiments, the rebroadcaster 334 may be an MWD tool and may include a variety of sensors and measurement devices in addition to the receiver, processor, mud pulse generator, and power source.
FIG. 3-2 is a representation of the downhole communication system 328 of FIG. 3-1 including multiple downhole tools (collectively 344), according to at least one embodiment of the present disclosure. In the embodiment shown, the receiver 336 of the rebroadcaster 334 receives signals 332 transmitted from the surface transmitter 330. A processor 338 processes and/or interprets the signals and converts them into a pressure pulse pattern. The processor 338 may then cause the mud pulse generator 340 to transmit the pressure pulse pattern as a pressure pulse signal 342.
In some embodiments, the pressure pulse signal 342 may be received by a plurality of downhole tools 344. In some embodiments, each downhole tool 344 may receive and process the pressure pulse signal 342. In some embodiments, the pressure pulse signal 342 may be directed to a target downhole tool 344. For example, the pressure pulse signal 342 may be directed to a first downhole tool 344-1. A second downhole tool 344-2 through an nth downhole tool 344-n may receive, process, and ignore the pressure pulse signal 342. For example, the pressure pulse signal may include non-sensical instructions for the nth downhole tool 344-n, such as instructions to take a measurement for which the nth downhole tool 344-n does not have a sensor, or instructions to actuate when the nth downhole tool 344-n is not actuatable.
In some embodiments, the pressure pulse signal 342 may include an identifier, such as a specific pattern unique to each downhole tool 344, transmitted at some point during the pressure pulse signal 342. The identifier may indicate to which downhole tool 344 the information in the pressure pulse signal 342 is directed. The identifier may be configured to identify a target downhole tool 344. The target downhole tool 344 may “listen” for its unique identifier. When the target downhole tool 344 “hears” its unique identifier, the target downhole tool 344 may process the remainder of the pressure pulse signal 342 and analyze the information and/or instructions included therein. If a non-target downhole tool 344 does not hear its unique identifier, the non-target downhole tool 344 may ignore the pressure pulse signal 342. Thus, in some embodiments, the pressure pulse signal 342 may be directed to a single target downhole tool 344. In some embodiments, the pressure pulse signal 342 may be directed at each downhole tool 344 of the plurality of downhole tools 344. In some embodiments, the pressure pulse signal 342 may be directed at two or more of the plurality of downhole tools 344.
FIG. 4 is a representation of a method 446 for downhole communication. The method 446 may include receiving a signal from a surface location at a rebroadcaster at 448. The signal received may be any signal transmitted downhole from a surface location, such as a wired communication, a wireless communication, an electromagnetic downlink, or other signal transmitted downhole. The signal may be converted to a pressure pulse pattern at 450. The signal may be directly converted (e.g., bit-for-bit, direct transcription of the signal from the signal format into a pressure pulse pattern). In some embodiments, the pressure pulse pattern may be transmitted using a mud pulse generator at 452. The pressure pulse signal transmitted by the mud pulse generator may be received downhole at a downhole tool at 454.
FIG. 5-1 is a representation of a method 556 for downhole communication, according to at least one embodiment of the present disclosure. The method 556 may include transmitting a signal downhole while the surface pumps are turned off at 558. The signal may be received downhole at 560. The signal may be converted to a pressure pulse pattern at 562. Pressure pulses in the pressure pulse pattern may be generated at 564.
FIG. 5-2 is a representation of the method 556 of FIG. 5-1 including the act of changing at least one drilling parameter at 566. In some embodiments, the pressure pulse signal transmitted from the rebroadcaster may include instructions to a downhole tool to change at least one drilling parameter. The drilling parameter to be changed may include the drill bit trajectory, measurement of a sensor, actuation of a downhole tool, or any other drilling parameter.
This disclosure generally relates to devices, systems, and methods for downhole communication. In some embodiments, a rebroadcaster may receive a signal transmitted from the surface, convert the signal to a pressure pulse pattern, and transmit the pressure pulse pattern using a pressure pulse generator. Rebroadcasting the signal may allow downhole tools that may not be configured to receive the signal, but that may receive pressure pulses, to receive signals from the surface. Furthermore, the signal may be broadcast without disrupting drilling activities (e.g., pumping), and the signal may be rebroadcast while drilling. This may decrease the amount of down time experienced by the drilling operation and decrease costs.
In some embodiments, a downhole tool may not include a receiver for electromagnetic or other communications from the surface. In some embodiments tools, such as a rotary steerable system (RSS), may include the capability to measure changes in flow rate and/or fluid pressure and/or measure the rotation rate of the drill string. For example, an RSS having a roll stabilized platform may not be able to receive electromagnetic or other communications from the surface and thus it may have the capability to measure changes in flow rate, fluid pressure, and/or rotation rate of a drill string. Communicating a message to a downhole tool via changes in flow rate and/or pressure must be measurable at the downhole tool. To communicate information from a surface location, which may be thousands of feet away from the downhole tool, relatively large changes in flow rate and/or pressure may be needed, which may disrupt drilling activities, increase wear and tear on downhole tools and/or surface equipment, and cause other challenges. This may be, at least in part, because of the distance from the surface location to the downhole tool, head losses during transmission to the downhole tool, processing power at the downhole tool, or combinations thereof.
In some embodiments, a signal may be transmitted to a downhole rebroadcaster without disrupting downhole drilling activities. For example, electromagnetic downlink signals may be transmitted while drilling or while drilling has been paused, such as while adding pipe, while taking measurements, and so forth. In some embodiments, the signal transmitted from the surface may be any signal, including an electromagnetic downlink signal, a wireless signal, a signal transmitted through wired pipe, a signal sent through a cable or wireline, any other signal, or combinations thereof. In some embodiments, the signal may not be varying one or more drilling fluid properties (e.g., flow rate, pressure, fluid density) and/or may not be varying the rotation rate of the drill string.
In some embodiments, the downhole tool may not include a receiver configured to receive the signal from the surface (e.g., the downhole tool may not include a wired or wireless electromagnetic receiver). For example, the downhole tool may only be configured to receive and interpret modified fluid properties (e.g., flow rate, pressure, fluid density) or drill string rotation rate.
In some embodiments, a rebroadcaster may include a receiver. The receiver may be configured to receive the signal from the surface. For example, the rebroadcaster may include an electromagnetic receiver, configured to receive electromagnetic downlink signals. In some examples, the rebroadcaster receiver may be configured to receive wired transmissions, wireless transmission, or any other surface signal. In some embodiments, the rebroadcaster may be located at any downhole location. For example, the rebroadcaster may be located on a BHA, at an MWD, at an LWD tool, or any other downhole location. In some examples, the rebroadcaster may be a separate downhole tool, such as a separate sub. In other words, the rebroadcaster may be located in a housing, and the housing may be connected to other tubular members (e.g., drill pipes) and/or downhole tools. In some embodiments, the rebroadcaster may be the only downhole tool located in a housing. In some embodiments, the rebroadcaster may be located in a housing including more than one downhole tool. In some embodiments, the rebroadcaster may operate only in a rebroadcast mode. In other words, the rebroadcaster may only receive signals transmitted from the surface, convert the signals to pressure pulse patterns, and transmit the pressure pulse patterns to the downhole tool. Thus, in some embodiments the rebroadcaster may include only the rebroadcaster receiver, the processer, a power source, and the mud pulse generator. In some embodiments, the rebroadcaster may be part of an MWD tool that may include sensors and other measurement devices in addition to the receiver, processor, power source, and mud pulse generator, and may be capable of communicating with the surface as a traditional MWD. In some embodiments, the processor may be located at another downhole tool and used by the rebroadcaster.
In some embodiments, the rebroadcaster may include a processor. The processor may be configured to demodulate the signal from the surface. In some embodiments, the processor may then convert the demodulated signal into a pressure pulse pattern. For example, the processor may directly convert the signal into a pressure pulse pattern. Directly converting the signal may include converting the signal bit-for-bit to a pressure pulse pattern. In other words, a direct conversion may convert each element of the data from the originally broadcast format to the pressure pulse pattern. In this manner, the information in the signal may not be modified, interpreted, or otherwise changed during the conversion.
In some embodiments, the rebroadcaster may include a memory. The memory may include a plurality of pre-determined pressure pulse patterns. In some embodiments, the pre-determined pressure pulse patterns may include one or more instructions for a downhole tool, including instructions for a change in bit trajectory (e.g., azimuth and/or inclination), instructions for a survey measurement to be taken, instructions to change any drilling parameter, or combinations thereof. In some embodiments, the pre-determined pressure pulse patterns may include information, such as survey information, wellbore depth information, trajectory information, formation information, downhole tool information, vibration information, any other information, or combinations thereof.
In some embodiments, the processor may convert the signal to one of a plurality of pre-determined pressure pulse patterns. For example, after receiving and demodulating the signal, the processor may interpret the signal, and, based on the content of the signal, determine which pre-determined pressure pulse pattern most closely matches the information contained in the signal. In some embodiments, the signal may include an indication of which pre-determined pressure pulse pattern the rebroadcaster should transmit. Utilizing pre-determined pressure pulse patterns may help to reduce transmission time, reduce the processor power required on the rebroadcaster, reduce the complexity of the rebroadcaster, or combinations thereof.
In some embodiments, the rebroadcaster may include a mud pulse telemetry system. The mud pulse telemetry system may include mud pulse generator. The mud pulse generator may include a flow restrictor configured to periodically restrict flow to the fluid flow flowing therethrough. This may cause changes in the volumetric flow rate and/or the pressure of the fluid flow. The processor may be configured to actuate the mud pulse generator. By actuating the mud pulse generator in the pressure pulse pattern, the mud pulse generator may create pressure pulses in the fluid flow in the pressure pulse pattern.
In some embodiments, a downhole tool may include a mud pulse receiver. The mud pulse receiver may be any instrument, sensor, or tool that may sense variations in the fluid flow, such as a pressure sensor, a turbine, a mud motor, any other mud pulse receiver, or combinations thereof. For example, in some embodiments, the downhole tool could include a turbine generator and the signal could be observed by monitoring the speed of the turbine. In some embodiments, the downhole tool is an RSS with a roll stabilized platform and the mud pulse signal is received by one or more turbines that generate energy and/or provide torque to control the orientation of the roll stabilized platform. In some embodiments, the downhole tool may include a processor that may demodulate (e.g., interpret) the pressure pulse signal. The processor may then analyze the information included in the pressure pulse signal, which may include information and/or instructions. For example, the pressure pulse signal may include instructions for the downhole tool, such as trajectory instructions, sensor measurement instructions, tool actuation instructions, or any other instructions. In some embodiments, the pressure pulse signal may include information, such as survey data, bit location, trajectory information, formation information, rate of penetration, depth, any other information, or combinations thereof. In some embodiments, the processor may analyze the information from the pressure pulse signal and perform an action based on the information provided. For example, the RSS could receive information related to depth and modify the inclination and/or azimuth to follow a planned trajectory.
In some embodiments, the downhole tool may be able to receive a plurality of different signal types, including wired signals, wireless signals, pressure pulse signals, or combinations thereof. In some embodiments, the downhole tool may only be able to receive pressure pulse signals. In some embodiments, the downhole tool may be located on roll stabilized platform. For example, the downhole tool may include a roll stabilized platform. The roll stabilized platform may not include a wired connection to the rebroadcaster and/or the signal receiver. However, the roll stabilized platform may be able to receive and interpret pressure pulse signals. Thus, an operator at a surface location may be able to transmit signals, information, and/or instructions to the roll stabilized platform.
In some embodiments, the rebroadcaster may be located close to the downhole tool. For example, the rebroadcaster may be located within 500 feet, 400 feet, 300 feet, 200 feet, 150 feet, 100 feet, 50 feet, or closer to the downhole tool. Because of the proximity to the downhole tool, the mud pulse generator may transmit pressure pulses that have low amplitude and/or high frequency relative to the fluid variations transmitted from the surface described above (e.g., pressure and/or flow variations). The mud pulse receiver at the downhole tool may be able to receive and interpret the low amplitude and/or high frequency pressure pulses because the pressure pulses have had less distance to degrade relative to traditional signals from the surface (e.g., pressure and/or flow variations). Low amplitude and/or high frequency pressure pulses may not significantly interrupt drilling activities (e.g., interrupt drilling activities such that the performance of one or more downhole tools is impaired).
In some embodiments, the amplitude of the pressure pulse signal (e.g., the signal from the rebroadcaster to the downhole tool) may be in a range having an upper value, a lower value, or upper and lower values including any of 5 psi (34.5 kPa), 10 psi (68.9 kPa), 25 psi (172 kPa), 50 psi (345 kPa), 75 psi (517 kPa), 100 psi (689 kPa), 150 psi (1,050 kPa), 200 psi (1,380 kPa), 250 psi (1720 kPa), 300 psi (2,070 kPa), 350 psi (2,410 kPa), 400 psi (2,760 kPa), 450 psi (3,100 kPa), 500 psi (3,450 kPa), 600 psi (4,140 kPa), 700 psi (4,830 kPa), 800 psi (5,520 kPa), 900 psi (6,210 kPa), 1,000 psi (6,700 kPa), or any value therebetween. For example, the amplitude may be greater than 100 psi (689 kPa). In another example, the amplitude may be less than 1,000 psi (6,700 kPa). In yet other examples, the amplitude may be any value in a range between 100 psi (689 kPa) and 1,000 psi (6,700 kPa). In some embodiments, it may be critical that the amplitude is between 200 psi (1,380 kPa) and 500 psi (3,450 kPa) to be sensed and demodulated by the downhole tool without interrupting drilling activities.
In some embodiments, the frequency of the pressure pulses (e.g., from the rebroadcaster to the downhole tool) may be in a range having an upper value, a lower value, or upper and lower values including any of 0.1 Hz, 0.2 Hz, 0.3 Hz, 0.4 Hz, 0.5 Hz, 0.75 Hz, 1.0 Hz, 2.0 Hz, 3.0 Hz, 4.0 Hz, 5.0 Hz, or any value therebetween. For example, the frequency may be greater than 0.1 Hz. In another example, the frequency may be less than 5.0 Hz. In yet other examples, the frequency may be any value in a range between 0.1 Hz and 5.0 Hz.
In some embodiments, the surface bit period, or the time it takes to transmit one bit from the surface to the rebroadcaster, may be in a range having an upper value, a lower value, or upper and lower values including any of 0.1 seconds (s), 0.2 s, 0.3 s, 0.4 s, 0.5 s, 0.075 s, 1 s, 2 s, 3 s, 4 s, 5 s, or any value therebetween. For example, the surface bit period may be greater than 0.1 s. In another example, the surface bit period may be less than 5 s. In yet other examples, the surface bit period may be any value in a range between 0.1 s and 5 s.
In some embodiments, the rebroadcaster bit period, or the time it takes to transmit one bit from the rebroadcaster to the downhole tool, may be in a range having an upper value, a lower value, or upper and lower values including any of 1 s, 2 s, 3 s, 4 s, 5 s, 6 s, 7 s, 8 s, 9 s, 10 s, 11 s, 12 s, 13 s, 14 s, 15 s, 17 s, 18 s, 19 s, 20 s, or any value therebetween. For example, the rebroadcaster bit period may be greater than 1 s. In another example, the surface bit period may be less than 20 s. In yet other examples, the rebroadcaster bit period may be any value in a range between 1 s and 20 s.
In some embodiments, the command period is the amount of time it takes to transmit a signal from the rebroadcaster to the downhole tool. In some embodiments, the command period may be in a range having an upper value, a lower value, or upper and lower values including any of 5 s, 10 s, 15 s, 20 s, 25 s, 30 s, 35 s, 40 s, 45 s, 50 s, 55 s, 1 minute (min), 1.5 min, 2.0 min, 3 min, 4 min, 5 min, 10 min, 15 min, 20 min, 25 min, 30 min, or any value therebetween. For example, the command period may be greater than 5 s. In another example, the command period may be less than 30 min. In yet other examples, the command period may be any value in a range between 5 s and 30 min.
In some embodiments, the signal may be transmitted to the rebroadcaster receiver when the pumps are turned off. This may be during pipe change, during tripping in/out of the wellbore, when the pumps are specifically turned off for transmission, or any other reason the pumps are switched off. In some embodiments, the rebroadcaster may then transmit the information to the downhole tool when the pumps are turned back on. This may allow the transmission to occur while downhole activities are occurring. Furthermore, because the transmission to the downhole tool does not require interrupting or otherwise operating the surface pumps, communication with the downhole tool may not contribute to wear and tear on the drilling system and drilling may not need to be delayed. In some embodiments, the signal may be transmitted to the rebroadcaster receiver while the pumps are turned on, e.g., while drilling.
In some embodiments, a plurality of downhole tools may receive and interpret the pressure pulse signal. In some embodiments, each downhole tool may process the pressure pulse signal, analyze the information contained therein, and determine, based on the information, if it should perform an operation. In some embodiments, the pressure pulse signal may include an identifier, such as a specific pattern unique to each downhole tool, transmitted at some point during the pressure pulse signal. The identifier may indicate to which downhole tool the information in the pressure pulse signal is directed. The identifier may be configured to identify a target downhole tool. The target downhole tool may “listen” for its unique identifier. When the target downhole tool “hears” its unique identifier, the target downhole tool may process the remainder of the pressure pulse signal and analyze the information and/or instructions included therein. Thus, in some embodiments, the pressure pulse signal may be directed to a single target downhole tool. In some embodiments, the pressure pulse signal may be directed at each downhole tool of the plurality of downhole tools. In some embodiments, the pressure pulse signal may be directed at two or more of the plurality of downhole tools.
In some embodiments, the pressure pulse signal prepared at the rebroadcaster may be received and interpreted at a surface location. In some embodiments, the surface of a drilling operation may include sensors that are more sensitive than those located downhole. Furthermore, in some embodiments, the surface may include computers that are more powerful than those located downhole. Thus, the surface may be able to sense and/or process pressure pulse signals that are weaker and/or harder to process than those received downhole. Thus, the surface location may be able to verify and/or validate (e.g., check) the signal transmitted to the downhole tool from the rebroadcaster. In this manner, an operator at the surface may be able to ensure that the information transmitted downhole was received and rebroadcast successfully.
In some embodiments, a method for downhole communication may include receiving a signal at a rebroadcaster. The signal may be converted to a pressure pulse pattern. The pressure pulse pattern may be transmitted with a pressure pulse generator located downhole. In some embodiments, the signal may be directly converted to the pressure pulse pattern. In some embodiments, the signal may be converted into one of a plurality of pre-determined pressure pulse patterns. In some embodiments, one or more of a plurality of downhole tools may receive the pressure pulse pattern.
In some embodiments, a method for downhole communication may include transmitting a signal downhole while surface pumps are turned off. The signal may be received at a rebroadcaster. The signal may be converted to a pressure pulse pattern. Pressure pulses may be generated in the pressure pulse pattern when the surface pumps are turned on. In some embodiments, at least one drilling parameter may be changed based on the information in the pressure pulse pattern.
The embodiments of the downhole communication system have been primarily described with reference to wellbore drilling operations; the downhole communication system described herein may be used in applications other than the drilling of a wellbore. In other embodiments, downhole communication systems according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, downhole communication systems of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.
One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.
A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.
The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.
The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

What is claimed is:

1. A method for downhole communication, comprising:

receiving a signal at a rebroadcaster;

converting the signal to a pressure pulse pattern; and

transmitting the pressure pulse pattern with a pressure pulse generator located downhole.

2. The method of claim 1, wherein transmitting the pressure pulse pattern includes transmitting the pressure pulse pattern from a pressure pulse generator located in a bottomhole assembly.

3. The method of claim 1, wherein converting the signal to the pressure pulse pattern includes directly converting the signal to the pressure pulse pattern.

4. The method of claim 1, wherein receiving the signal at the rebroadcaster includes receiving the signal at a measurement while drilling tool.

5. The method of claim 1, further comprising receiving the pressure pulse pattern at a rotary steerable system.

6. The method of claim 1, further comprising transmitting the signal downhole via a wired connection.

7. The method of claim 1, wherein converting the signal includes interpreting the signal and converting the signal into one of a plurality of pre-determined pressure pulse patterns.

8. The method of claim 1, comprising receiving the pressure pulse pattern at a plurality of downhole tools.

9. The method of claim 8, wherein the pressure pulse pattern includes an identifier, the identifier indicating a target downhole tool of the plurality of downhole tools to which the pressure pulse pattern is directed.

10. The method of claim 1, wherein the signal includes instructions for a downhole tool.

11. The method of claim 1, comprising receiving the pressure pulse pattern at a surface location and checking the pressure pulse pattern against the signal.

12. A method for downhole communication, comprising:

transmitting a signal downhole;

receiving the signal at a rebroadcaster;

converting the signal to a pressure pulse pattern; and

generating pressure pulses downhole in the pressure pulse pattern.

13. The method of claim 12, comprising receiving the pressure pulse pattern at a downhole tool.

14. The method of claim 13, comprising changing at least one drilling parameter based on the received pressure pulses.

15. The method of claim 12, wherein the rebroadcaster is located within 200 feet of a pressure pulse generator that transmits the pressure pulse pattern.

16. The method of claim 12, wherein transmitting the signal downhole includes transmitting the signal via electromagnetic downlink.

17. The method of claim 12, wherein the signal is transmitted downhole while the surface pumps are turned off and wherein pressure pulses are generated downhole in the pressure pulse pattern when the surface pumps are turned on.

18. A system for downhole communication, comprising:

a rebroadcaster, including:

a receiver configured to receive a signal from a surface location;

a processor configured to convert the signal to a pressure pulse pattern; and

a pressure pulse generator configured to transmit the pressure pulse pattern.

19. The system of claim 18, wherein the rebroadcaster is configured to operate only in a rebroadcast mode.

20. The system of claim 18, wherein the receiver is configured to receive electromagnetic downlink signals.

21. The system of claim 18, wherein the pressure pulse generator is a low amplitude, high frequency pressure pulse generator.