Patent Application
20140284104
In the drilling of oil and gas wells, various techniques for providing communication between a surface system and equipment in a borehole have been devised. Such communication is generally directed to providing control over the function of a downhole tool from the surface, and/or providing information indicative of downhole conditions (e.g., borehole environmental conditions, tool conditions, etc.) to the surface. Exemplary downhole communication techniques include modulation of drilling fluid (mud) pressure or flow rate, communication via wireline or wired drill pipe, electromagnetic communication, acoustic communication, etc. Each technique has its advantages and disadvantages. For example, the mud column provides a convenient medium for communication because the circulation of drilling fluid is needed to clean and maintain pressure in the borehole. However, mud pressure modulation can be unreliable because the drilling fluid is susceptible to pressure changes not induced by a modulator of the communication system (e.g., changes in formation pressure). Mud flowrate and pressure are also affected when communication tools are run below a pulsing device, such as a MWD or mud motor, this can make signal decoding less reliable and more complex. Mud pulses also get degraded as the distance from the surface to the tool increases requiring the use of increasing time intervals between commands. Current systems also require the use of many different codes to send specific downlinks to the tool.
A system and method for communicating with a downhole tool are disclosed herein. In one embodiment, a system for downhole communication includes a downhole tool. The downhole tool includes a downlink receiver and a command actuator. The downlink receiver is to receive control information that controls operation of the downhole tool. The control information is encoded in rotation of the downhole tool. The downlink receiver includes a rotation sensor and a decoder. The rotation sensor is configured to sense rotation of the downhole tool about a longitudinal axis of the downhole tool. The decoder is configured to demarcate fields of the control information based on rotation state transitions sensed by the rotation sensor. The rotation state transitions are transitions between a rotating state and a non-rotating state of the downhole tool. The decoder is also configured to decode a control value for controlling the downhole tool based on a duration of a field of the control information. The control value is wholly encoded in the field, and the field is encoded as a non-rotating state of the downhole tool. The command actuator applies the control value to control operation of the downhole tool.
In an embodiment, a method for downhole communication includes rotating a downhole tool at a first rotation rate to place the downhole tool in a rotating state. Rotation of the downhole tool is halted to place the downhole tool in a non-rotating state. Control information for controlling the downhole tool is encoded in a series of transitions between the rotating state and the non-rotating state. The transitions between the rotating state and the non-rotating state are detected by the downhole tool. Fields of the control information are demarcated by the downhole tool based on the detected transitions. A control value for controlling the downhole tool is decoded by the downhole tool based on a duration of a field of the control information. The control value is wholly encoded in the non-rotating state. The control value is applied to control operation of the downhole tool.
In an embodiment, a method for downhole communication includes transmitting control information from a surface location to a downhole tool disposed in a borehole by repetitively raising or lowering a downhole tool in a borehole. Motion of the downhole tool along a longitudinal axis of the downhole tool is detected by the downhole tool. The command information is extracted from the motion, by the downhole tool, by demarcating fields of the control information based on the detected motion of the downhole tool along the longitudinal axis. The control information extracted from the motion is applied by the downhole tool to control the operation of the downhole tool.
In an embodiment, a method for downhole communication includes rotating a drill string in a first direction via a drill string rotation mechanism disposed at a surface location. During the rotating in the first direction, a downhole motor disposed in the drill string is successively engaged and disengaged to cause reversals in direction of rotation of a downhole tool disposed downhole of the downhole motor in the drill string. The timing of the reversals in direction of rotation encodes control information for controlling the operation of the downhole tool. The reversals in direction of rotation are detected by the downhole tool. The control information is extracted from the rotation, by the downhole tool, by demarcating fields of the control information based on the detected reversals in direction of rotation. The extracted control information is applied by the downhole tool to control operation of the downhole tool.
In an embodiment, a system for downhole communication includes a downhole tool. The downhole tool includes a downlink receiver and a command actuator. The downlink receiver is to receive control information that controls operation of the downhole tool. The control information encoded in motion of the downhole tool. The downlink receiver includes a first sensor and a decoder. The first sensor is configured to sense motion of the downhole tool along a longitudinal axis of the downhole tool. The decoder is configured to extract the control information from the motion of the downhole tool, and to demarcate fields of the control information based on sensed motions of the downhole tool along the longitudinal axis. The command actuator applies decoded control information provided by the downlink receiver to control operation of the downhole tool.
The downlink receiver may include a second sensor configured to detect rotation of the downhole tool about the longitudinal axis. The decoder may be configured to extract the control information based on detected rotation of the downhole tool being at a predetermined rate during the sensed motions of the downhole tool along the longitudinal axis.
The downlink receiver may be configured to identify each sensed initiation of axial motion along the longitudinal axis as change of state of the control information.
The downlink receiver may configured to identify a first sensed initiation of axial motion along the longitudinal axis followed by a second sensed initiation of axial motion along the longitudinal axis as initiation of a preamble field of the control information. The downlink receiver may include a second sensor configured to detect rotation of the downhole tool about the longitudinal axis. The decoder may be configured to demarcate fields of the control information based on sensed changes in rate of rotation of the downhole tool.
The downlink receiver may be configured to identify a first sensed initiation of axial motion along the longitudinal axis as initiation of a preamble field of the control information transmission; and to identify a second sensed initiation of axial motion along the longitudinal axis as termination of the control information. The downlink receiver may include a second sensor configured to detect rotation of the downhole tool about the longitudinal axis; wherein the decoder is configured to demarcate fields of the control information based on sensed changes in rate of rotation of the downhole tool.
The system may further include a plurality of joints of drill pipe coupling the downhole tool to surface equipment.
The downhole tool may be a reamer that includes a blade for expanding a diameter of a borehole. The downlink receiver may be configured to decode from axial and rotational motion of the downhole tool, information for controlling a position of the blade.
The downlink receiver may include a timer configured to measure a time duration of each identified field of the control information. The downlink receiver is configured to determine a value of the control information to be applied to control the downhole tool in correspondence to the time duration of a given field of the control information.
In an embodiment, a system for downhole communication includes a downhole tool. The downhole tool includes a downlink receiver and a command actuator. The downlink receiver is to receive control information that controls operation of the downhole tool. The control information is encoded in rotation of the downhole tool. The downlink receiver includes a rotation sensor, and a decoder. The rotation sensor is configured to sense rotation of the downhole tool about a longitudinal axis of the downhole tool. The decoder is configured to demarcate fields of the control information based on reversals of rotational direction sensed by the rotation sensor. The command actuator applies decoded control information provided by the downlink receiver to control operation of the downhole tool.
A drill string may couple the downhole tool to surface equipment. The surface equipment is configured to rotate the drill string in a first direction. The drill string includes a downhole motor disposed in the drill string uphole of the downhole tool. The downhole motor is configured to reverse the rotational direction of the downhole tool by rotating the downhole tool in a second direction that is opposite the first direction while the drill string uphole of the downhole motor rotates in the first direction.
The downlink receiver may include a timer configured to measure a time interval between each reversal of rotational direction. The downlink receiver may be configured to determine a value of the control information to be applied to control the downhole tool in correspondence to the time interval between two predetermined reversals of rotation.
For a detailed description of exemplary embodiments of the invention, reference is now be made to the figures of the accompanying drawings. The figures are not necessarily to scale, and certain features and certain views of the figures may be shown exaggerated in scale or in schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness.
Certain terms are used throughout the following description and claims to refer to particular system components. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through direct engagement of the devices or through an indirect connection via other devices and connections. Further, the term “software” includes any executable code capable of running on a processor, regardless of the media used to store the software. Thus, code stored in memory (e.g., non-volatile memory), and sometimes referred to as “embedded firmware,” is included within the definition of software. The recitation “based on” is intended to mean “based at least in part on.” Therefore, if X is based on Y, X may be based on Y and any number of other factors.
In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals. The present disclosure is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings and components of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results.
The downhole communication systems employed in oil and gas industry applications are subject to varying requirements. Tools that acquire a large volume of data may require a high bandwidth communication link for transfer of data from the tool to surface equipment (uplink). Similarly, a tool that requires real-time control from the surface may require a high-speed communication link for transfer of data from the surface equipment to the downhole tool (downlink). In other applications, reliability and cost are important considerations. For example, downhole tools that do not require real-time control may be managed via a low bandwidth downlink that can preferably be implemented with fewer specialized components and at lower cost than a higher bandwidth communication system.
Embodiments of the downlink communication system disclosed herein provide control of downhole tool functionality without use of specialized communication media that may increase system cost. Embodiments also provide reliable transfer of control information from the surface to a downhole tool that is not subject to interference from outside noise sources and is free from signal degradation due to increasing distance from the surface. The downlink communication system disclosed herein employs drill string rotation and/or axial movement to transfer a command from the surface to the downhole tool. In some embodiments, an analog command signal (with potentially infinite resolution) is transmitted using pulse width modulation of the drill string rotation or pulse modulation for combination of rotation and axial movement signal. Embodiments employ time based commands to make it simple for operators to send commands to the tool without the need to have a database to give them a multitude of command sequences for each input value desired.
The drill string 108 is made up of various components, including drill pipe 118, drill bit 114, and other downhole tools. The drill pipe 118 may be standard drill pipe or wired drill pipe. The drill string 108 includes a downhole tool 126 that receives control information from the surface. The downhole tool 126 may be, for example, a steering tool, such as is described in U.S. Pat. Pub. US2011/0036631a1, a reamer, a circulating sub, a positive displacement motor or turbine, a variable thruster for applying WOB, or any other downhole equipment that receives control information from the equipment disposed at the surface. To enable the transfer of control information from the surface to the downhole tool 126, the downhole tool 126 includes a downlink receiver 128. The downlink receiver 128 detects control information (e.g., commands, parameters, etc.) transmitted from equipment at the surface as disclosed herein. The control information may direct the operation or configuration of the downhole tool 126, transfer operational parameters to the downhole tool 126, etc.
Some embodiments of the downlink receiver 128 detect rotation of the drill string 108 and decode commands based on the duration of rotation of the drill string 108. Some embodiments of the downlink receiver 128 may use a combination of duration of rotation and axial movements or changes in direction or any combination thereof to decode commands. Accordingly, the downlink receiver 128 may interpret a rotation of the drill string 108 for a first duration as a first command, and rotation of the drill string 108 for a second duration (e.g., longer than the first duration) as a second command. Alternatively the downlink receiver 128 may interpret a rotation and axial movement of the drill string 108 for a first duration as a first command, and lack of rotation or movement of the drill string 108 for a second duration (e.g., longer than the first duration) as a second command. Some embodiments may decode commands based on the speed of rotation of the drill string 108, the number of revolutions of the drill string 108, duration of axial motion of the drill string 108, drilling fluid pressure, drilling fluid flow rate, etc. The downlink receiver 128 and the control information transfer techniques disclosed herein allow for reliable transfer of control information from the surface equipment to the downhole tool 126 while using standard (not wired) drill pipe.
While the system 100 is illustrated with reference to an onshore well and drilling system, embodiments of the system 100 are also applicable to control of downhole tools in offshore wells. In such embodiments, the drill string 108 may extend from a surface platform through a riser assembly, a subsea blowout preventer, and a subsea wellhead into the subsea formations.
The preamble portion of the transfer continues in interval 204 with a series of periods of rotation and non-rotation. Rotational periods may be 30 seconds in length, and non-rotational periods may also be 30 seconds in length. The number of sequential periods of rotation and non-rotation and the length of the rotational and non-rotational periods may vary in different embodiments of the system 100. While rotational periods of the interval 204 and other rotational periods of the control transfer are illustrated as being greater than six revolutions-per-minute, embodiments of the downhole tool 126 may deem any rate of rotation greater than a predetermined threshold rate of rotation (e.g., >5 RPM) to constitute a state of rotation.
The preamble is complete at the end of the interval 204, and control information (command, parameters, etc.) is transferred to the downhole tool 126 during rotational period 206. Control information may be transferred to the downhole tool 126 during the rotational period 206 by modulating the pulse width of the signal.
Any number of commands and/or parameters may be transferred to the downhole tool 126 using combinations of pulse width modulated sequences for the rotation levels and/or rotation directions and/or axial movements. For example, if the rotational period 206 is 60 seconds in length the downhole tool 126 may identify a first command, and if the rotational period 206 is 90 seconds in length the downhole tool 126 may identify a second command that is different from the first command. Similarly, parameter values may be transferred based on the length of the rotational period 206. For example, a longer rotational period 206 may indicate a higher parameter value.
The rotational period 206 (and associated control information transfer) ends as the rotation of the downhole tool 126 is halted during interval 208 (e.g., 30 seconds). At the end of interval 208, another transfer of control information may be performed during the rotational period 210, where the duration of the rotational period 210 determines what control information is transferred. Thus, any number of commands and/or parameters may be transferred to the downhole tool 126 following the preamble. In command sequence 200, after rotational period 210, rotation of the downhole tool 126 is halted during interval 212, indicating that the transfer of control information is complete, and the downhole tool 126 executes the received commands, applies the received parameters, etc.
In the command sequence 240, prior to the preamble, the drill string 108 is rotating in the second direction with the downhole motor (e.g., disposed in the downhole tool 126) disengaged. The preamble begins by engaging the downhole motor to rotate the tool 126 and/or the downlink receiver 128 in the first direction for a predetermined interval 242 (e.g., 90 seconds). The preamble continues by repetitively disengaging and engaging the downhole motor to reverse the direction of rotation of the tool 126 and/or the downlink receiver 128. In the command sequence 240, preamble period 244 includes six reversals of rotation direction with rotation in each direction for approximately 30 seconds. Following the preamble, a command value is transferred by disengaging the downhole motor for the interval 246 where the length of the interval 246 defines the command value. Additional command values may be transferred by engaging the downhole motor for an interval 248 and disengaging the downhole motor for an interval 250 that defines the additional value. Following a final motor engagement interval 252, the command sequence is complete.
During interval 262, the preamble portion of a control transfer is initiated by halting rotation of the downhole tool 126 for a pre-determined duration (e.g. 90 seconds). During interval 902, two axial movement pulses are transmitted to the downhole tool 126 by lowering or raising the tool 126 with sudden stop. Accordingly, the downhole tool 126 receives two axial movement pulses during the interval 902. While
In the command sequence 280 the preamble may be further defined by periods of rotation and non-rotation 284. Following the preamble, a command/parameter is defined by the duration of the rotation interval 286. Following an interval 288 of non-rotation, an additional command/parameter may be transferred in rotation interval 290.
During interval 274, the preamble portion of a control transfer is initiated by halting rotation of the downhole tool 126 for a pre-determined duration (e.g., 90 seconds). The preamble portion of the sequence 273 continues with a series of periods of rotation and non-rotation. For example, following interval 274, preamble rotational periods may be 20 seconds in length, and non-rotational periods may also be 20 seconds in length. Thus, the preamble comprises a series of transitions between a rotating state in which the downhole tool 126 is rotated, and a non-rotating state in which rotation of the downhole tool 126 is halted. The preamble is complete at the end of the interval 275.
Following the preamble, a period of rotation 276 indicates to the downhole tool 126 that command/parameter values are to be transferred via intervals of non-rotation (i.e., the tool 126 is to apply active-low logic in interpreting the upcoming command/parameter sequence). That is, equipment at the surface will downlink control information (commands and/or parameters) to the downhole tool 126 by halting rotation of the downhole tool 126 for an interval of time as opposed to rotating the tool 126 for the interval. In some embodiments, the interval of rotation 276 specifies a polarity designation value, that indicates (e.g., by the duration of the interval 276) whether subsequent control transfer will be by rotation or by non-rotation.
In interval 277, control information (commands and/or parameters) is transferred by halting the rotation of the downhole tool 126 (e.g., the duration of the interval 277 defines the value of the command or parameter). In the sequence 273, only one command value is transferred, and the command sequence is terminated with rotation interval 278 followed by non-rotation interval 279. In other control information transfers, the intervals 277 and 278 may be repeated to transfer a plurality of control values (e.g., a command and associated parameters). In some embodiments, the non-rotation in the interval 277 may be defined as a rotation rate lower than a predetermined rate (e.g., <1 RPM). Similarly, rotation in rotation intervals (e.g., 276, 278) may be defined as a rotation rate higher than a predetermined rate (e.g., >10 RPM).
The downlink receiver 128 includes one or more motion sensors 302, sensor processing 304, and a decoder 308. The motion sensors 302 detect movement of the downhole tool 126. The motion sensors 302 may include sensors that detect rotation of the tool 126, and sensors that detect axial movement of the tool 126. For example, the motion sensors 302 may include a gyroscope (e.g., a solid-state gyroscope), accelerometers, magnetometers, or other tachometric device for determining whether and optionally at what rate, the downhole tool 126 is rotating, and also may include an accelerometer or other sensor oriented to detect axial movement of the tool 126. The motion sensors 302 and the sensor processing 304 operate conjunctively to determine whether the downhole tool 126 is rotating and/or moving axially. Some embodiments of the motion sensors 302 and sensor processing 304 also determine at what rate the downhole tool 126 is rotating to allow assessment of rotation based on predetermined rotation rate thresholds as described herein.
The sensor processing 304 may include one or more timers to measure the intervals of rotation and non-rotation and/or intervals between axial motions that define the transfer of control information. For example, a timer can measure duration of non-rotation during the interval 202, measure duration of rotational periods and non-rotational periods in interval 204, duration of rotation in period 206, etc.
The decoder 308 determines whether control information is being transferred from the surface, and identifies the control information based on the motion information, and associated timing, provided by the sensor processing 304. For example, with regard to command sequence 200, the decoder 308 can identify a preamble of a control information transfer by comparing the sequence of rotation/non-rotation time values received from the sensor processing 304 to predetermined rotation/non-rotation time sequence values defining a preamble. Subsequent to identification of a preamble, the decoder 308 can identify a command and/or parameter value transferred based on the time value of the interval 206 received from the sensor processing 304. For example, the decoder 308 may include a table or other structure or information that relates the measured time of the interval 206 to a command/parameter value. The decoder 308 may apply similar decoding operations to decode the sequences 220, 240, 260, and 280.
The decoder 308 provides the identified command/parameter to the command actuator 310. The command actuator 310 implements the received command/parameter to affect the operation of the downhole tool 126. For example, the command actuator 310 may open or close a valve in the downhole tool 126 in response to receiving a valve control command.
As explained above, the sensor processing 304 processes sensor output signals 314 to determine whether the tool 126 is rotating and/or moving axially.
Embodiments of the downhole tool 126 can implement portions of the rotation timer 306, decoder 308, and/or command actuator 310 using dedicated circuitry (e.g., dedicated circuitry implemented in an discrete or integrated circuit). Some embodiments may use a combination of dedicated circuitry and a processor executing suitable software. For example, some portions of the downlink receiver 128 may be implemented using a processor or hardware circuitry. Selection of a hardware or processor/software implementation of embodiments is a design choice based on a variety of factors, such as cost, time to implement, and the ability to incorporate changed or additional functionality in the future.
The processor 502 is a device that executes instructions to perform the command actuation, command decoding, and/or timing functions of the downhole tool 126. Suitable processors include, for example, general-purpose microprocessors, digital signal processors, and microcontrollers. Processor architectures generally include execution units (e.g., fixed point, floating point, integer, etc.), storage (e.g., registers, memory, etc.), instruction decoding, peripherals (e.g., interrupt controllers, timers, direct memory access controllers, etc.), input/output systems (e.g., serial ports, parallel ports, etc.) and various other components and sub-systems.
The storage 504 is a computer-readable storage device that stores instructions to be executed by the processor 502. When executed, the instructions cause the processor 502 to perform the various downhole tool control operations disclosed herein. A computer readable storage device may include volatile storage such as random access memory, non-volatile storage (e.g., FLASH storage, read-only-memory, etc.), or combinations thereof. Instructions stored in the storage 504 may cause the processor 502 identify rotation and/or axial motion based on signals 314, to measure the times of rotation/non-rotation/axial motion intervals, to identify commands/parameters transferred based on the measured times, and to execute the identified commands or apply the identified parameters.
The storage 504 includes a command timing module 508, a command decoding module 510, and a command execution module 512. The command timing module 508 includes instructions that cause the processor 502 to measure the rotation times/non-rotation times/axial motion times associated with control information transfer. The processor 502 may implement the measurement via timer circuitry or instruction-based timing. The command decoding module 510 causes the processor 502 to identify preambles, commands, parameters, etc. based on the rotation/non-rotation/axial motion time sequences and the measured time of control information transfer intervals 206, 210, etc. The command execution module 512 causes the processor 502 to perform operations needed to implement a received command or apply a received parameter. For example, instructions of the command execution module 512 may cause the processor to actuate a valve, a solenoid, or other component of the downhole tool 126 in accordance with the identified command or parameter.
In block 602, the downhole tool 126 is disposed in the borehole 116. The downlink receiver 128 is monitoring rotation/axial motion of the downhole tool 126 to identify a control information transfer sequence initiated by the equipment at the surface. In some embodiments, the rotation processing module 400 of the downlink receiver 128 is processing rotation sensor outputs, and generating a rotation rate value for the tool 126.
In block 604, the surface equipment initiates a control information transfer sequence by manipulating the rotation/non-rotation/axial motion of the downhole tool 126 to transmit a preamble sequence. The preamble sequence may include a period of non-rotation 202 followed by a plurality of subsequent rotation/non-rotation intervals 204, for example, as shown in
In block 606, the downlink receiver 128 detects the preamble sequence indicating initiation of control information transfer, and begins listening for (e.g., timing) the command/parameter that follows the preamble.
In block 608, the surface equipment initiates transmission of a command/parameter (control information) immediately subsequent to the preamble. The value of the command/parameter may be encoded as a duration of rotation of the downhole tool 126, axial motion of the downhole tool 126, etc. Thus, the surface equipment may cause the downhole tool 126 to rotate for a duration and/or speed indicated by the command/parameter to be transmitted to the downhole tool 126.
In block 610, the downlink receiver 128 receives and decodes the control information transferred from the surface. The downhole tool 126 executes a command and/or applies a parameter received with the control information in block 612. Execution of the command and/or application of the parameter may modify or otherwise direct the operation of the downhole tool 126.
As explained above, the downhole tool 126 can be any of various types of downhole equipment whose operation can be facilitated by receiving control information from the surface. For example, the downhole tool 126 may be a reamer. A reamer is a tool that operates by expanding cutters above the drill bit 114 to increase the diameter of the borehole 116 to be equal or larger than the bore created by operation of the drill bit 114. Conventional reamers allow selective activation of cutters and in some cases allow the cutters to be locked from opening with drilling flow rates present, using a ball drop method. In conventional reamers, once the cutters are deactivated or the ball catcher is full the reamer must be withdrawn from the borehole 116 and reset to enable further use.
A reamer including the downlink receiver 128 allows surface equipment to selectively activate and deactivate the reamer an unlimited number of times.
Multiple instances of the reamer 700 can be included in drill string 108 and selectively activated below restrictions that would inhibit operation of ball drop activated tools. The reamer 700 may also allow mechanical deactivation of the cutters 702 by dropping a ball in the event of a failure in the electronics (e.g., battery or circuitry of the downlink receiver 128, etc.). Accordingly, the reamer 700 may include a ball catcher 711 at the top of the control system as shown in
In another embodiment, the downhole tool 126 may be a positive displacement mud motor or turbine. A mud motor or turbine is used in drilling to provide power or rotation of the drill bit by pumping fluid under pressure through the motor. The motor allows the operator to turn the drill bit without having to turn the entire drill string or drill pipe. Conventionally, motors have a set RPM range that is not adjustable without pulling the motor and changing the type of power section being used.
A motor/turbine including the downlink receiver 128 allows surface equipment to selectively change the RPM of the motor at a given flow rate by bypassing a portion of the drilling flow to the annulus above the motor's/turbine's power section. In an alternative embodiment, such RPM control can be accomplished by attaching a control valve similar to the control valve 709 to the rotor of the motor/turbine and bypassing a portion of the flow through a central passage in the rotor. In such an embodiment, fluid can enter the housing of the valve and pass through the rotor of the motor, thus bypassing the Moineau power section and reducing the speed of the rotor. By using rotational and/or axial movement commands from the surface with no flow present, the RPM of the motor can be controlled with simple commands to speed up or slow down the bit as needed to meet the RPM demands of changing rock formation types while drilling.
In a further embodiment, the downhole tool 126 may be a multiple opening circulating sub. A circulating sub is used in drilling to bypass all or a portion of the mud flow to the drill bit. Conventional circulating subs are activated via drop balls or with changes in mud flow. A circulating sub including the downlink receiver 128 allows surface equipment to selectively change the amount of fluid bypassing the bit. Using a valve similar to valve 709 and adding a small nozzle passage through the outer body below the floater piston a circulating sub can be activated or deactivated by sending rotational commands or rotational and axial movement commands to the tool. By attaching the receiver 128 and valve similar to 709 to the lower end of a circulating sub, such as the circulating sub described in WIPO Pub. WO2009/067588, the floater piston can be balanced and unbalanced by shifting valve 709 to allow flow into the chamber below the floater piston. When the valve 709 is open the floater piston sees the tools internal bore pressure and the circulating sub is not allowed to open to the annulus. When the valve 709 is closed (no flow) an additional small bleed passage through the outer body of the circulating sub prevents pressure from building below the floater piston and keeps the chamber at the annulus pressure. When the pumps are turned on, the ported valve piston shifts downward and allows the circulating sub valve to open, thus allowing all or a portion of drilling fluid to flow to the annulus through the body ports.
In a yet further embodiment, the downhole tool 126 may be a thruster. A thruster is a stroking tool used in drilling to maintain weight on bit (WOB) by using the mud pressure generated by pumping the fluid through the drill bit. The thruster allows force to be applied to the drill bit without moving the drill pipe up and down continually. The pressure differential across the tool and drill bit are multiplied by the piston area inside the thruster and provide a WOB force to allow the bit to cut the formation. Conventional thrusters are not variable and provide a set WOB for a given flow rate. A thruster including the downlink receiver 128 and a valve similar to the valve 709 allows surface equipment to selectively change the WOB at the bit by moving the valve to increase or decrease the flow area below the piston of the thruster. By opening the valve the differential pressure across the tool decreases based on the flow area controlled by the valve and can be set to any of a plurality (e.g., any value in a range) of WOB values by sending rotational commands or rotational and axial movement commands to the tool. Similarly, by closing the valve, the resulting differential pressure across the tool increases based on the flow area controlled by the valve thus increasing the WOB applied to the drill bit.
The above discussion is meant to be illustrative of various embodiments of the present invention. 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.
This application is a non-provisional application claiming priority to provisional application Ser. No. 61/803,696, filed on Mar. 20, 2013, entitled “System and Method for Controlling a Downhole Tool,” the entire disclosure of which is incorporated by reference herein.
| Number | Date | Country | |
|---|---|---|---|
| 61803696 | Mar 2013 | US |
