US20110162891A1

US20110162891A1 - Rotating Drilling Tool

Info

Publication number: US20110162891A1
Application number: US12/985,545
Authority: US
Inventors: David M. Camp
Original assignee: Camp David M
Current assignee: AMKIN TECHNOLOGIES LLC
Priority date: 2010-01-06
Filing date: 2011-01-06
Publication date: 2011-07-07
Also published as: WO2011085059A2; WO2011085059A3; CA2792145A1

Abstract

Embodiments described herein comprise a system and method for controlling directional drilling. The system includes a conveyance for conveying a bottom hole assembly BHA into a wellbore. The BHA may include a bent housing, a drilling tool and a motor for rotating the bent housing in the wellbore. The system further includes a conveyance rotation device for rotating the conveyance in the opposite direction of the bent housing. The direction of the bent housing may be controlled by controlling the rotational speed of the bent housing and the conveyance while drilling.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the priority benefit of US provisional patent application No. 61/292,523, titled “Rotating Drilling Tool,” filed Jan. 6, 2010 with the inventor David Camp. This related application is hereby incorporated by reference in its entirety.

BACKGROUND

Embodiments of the inventive subject matter generally relate to the field of drilling tools, more particularly, to a rotational drilling system configured to control the rotational speed of a bottom hole assembly (BHA) by controlling the rotational speed of a bent housing in a first direction and a conveyance in a second direction.
Conventional directional drilling with jointed pipe is generally accomplished through use of a Bottom Hole Assembly (BHA) consisting of a drilling motor powered by drilling fluids that includes a typical mouniea style or positive displacement type power section along with a bent housing or bent sub, a drill bit, and a directional Measurement While Drilling (MWD) tool. The power section is typically located below the bent housing and the drill bit. The curved portion of the wellbore is drilled by rotationally fixing the drill string at the surface and rotating the drill bit with the power section. The bent housing will slowly cause the wellbore to bend as the drill string is lowered into the Earth with the drill bit rotating and drilling. To control the radial orientation of the wellbore, the rotation of the drill string is controlled and manipulated at the surface. To facilitate straight hole drilling the drill string is rotated from the surface, thereby rotating the entire BHA while the power section is rotating the drill bit.

SUMMARY

Embodiments described herein include a method of controlling the rotational direction of a bottom hole assembly (BHA). The method comprises delivering the BHA into a wellbore on a conveyance wherein the BHA comprises a bent housing and a downhole tool. The method further comprises rotating the bent housing in a first direction and monitoring the rotational speed of bent housing. The method further comprises rotating the conveyance in a second direction and monitoring the rotational speed of the conveyance. The method further comprises controlling the relative rotational speed in the first and second direction and thereby controlling the rotational position of the bent housing and downhole tool.

BRIEF DESCRIPTION OF THE DRAWINGS

The present embodiments may be better understood, and numerous objects, features, and advantages made apparent to those skilled in the art by referencing the accompanying drawings.

FIG. 1 depicts a diagram illustrating a schematic view of a wellbore in an embodiment.

FIGS. 2A-2C depict diagrams illustrating a schematic view of a bottom hole assembly (BHA) in an embodiment.

FIG. 3 depicts a diagram illustrating a schematic of a wellbore management system in an embodiment.

FIG. 4 depicts a diagram illustrating a schematic view of a rotating drilling controller in an embodiment.

FIG. 5 depicts a flow depicting the operation of the rotating drilling system in embodiment.

FIG. 6 depicts a schematic diagram of a computer system in an embodiment of the invention.

DESCRIPTION OF EMBODIMENT(S)

The description that follows includes exemplary apparatus, methods, techniques, and instruction sequences that embody techniques of the present inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.
Embodiments described herein comprise an apparatus and method for detecting, monitoring and controlling the rotational position of a downhole tool during use in a wellbore. The apparatus comprises a conveyance for conveying a bottom hole assembly (BHA) into a wellbore and a conveyance rotation device. The conveyance rotation device is configured to rotate the conveyance and/or the BHA. The BHA may include one or more motors or power sections, a drill bit, a drive train connecting the drill bit to the motor, a bent housing, and one or more monitoring devices. The one or more motors may transfer rotational motion to the drill bit, thereby allowing the BHA to drill the wellbore. The one or more motors may further transfer rotational motion to the bent housing in order to rotate the bent housing relative to the conveyance. The rotation of the bent housing may be in the opposite direction of the rotation of the conveyance. The rotation of the bent housing may allow the operator control the direction of the drilling without needing to pull the entire BHA out of the wellbore. The one or more monitoring devices allow the operator to determine the position of the bent housing as it rotates due to the motor rotation, and/or conveyance rotation. The one or more monitoring devices may send a signal to a controller and/or an operator which allows the operator to determine the position and directional orientation of the bent housing during drilling operations. Due to the opposite directional rotation of the conveyance and the bent housing, the operator, and/or controller, may control the rotational direction of the bent housing relative to the wellbore by controlling the rotational speed of the conveyance and/or the bent housing. Thus, to drill a substantially straight wellbore, the operator may allow the bent housing to rotate with the conveyance as the drill bit rotates. When it is desired to deviate the wellbore the operator may rotate the bent housing at the same speed but in the opposite direction of the conveyance. This opposite rotation of the bent housing and conveyance fixes the position of the bent housing relative to the wellbore. Thus, continued drilling down will deviate the wellbore in the direction of the bent housing.
FIG. 1 depicts a schematic view of a wellbore 100 and a drilling system 102. The drilling system 102 may comprise a drilling rig 104, a conveyance or drill string 106, a conveyance rotation device 108, and a BHA 110. The BHA 110 may comprise a drill bit 112, a bent housing 114, one or more motors 116, and one or more monitoring devices 118. The motor 116, as shown, is located above, or upstream, of the bent housing 114 and the drill bit 112. The motor 116 may transfer rotation to the bent housing 114 and/or the drill bit 112 thereby rotating the bent housing 114 and/or the drill bit 112 about a longitudinal axis of the motor 116. The conveyance rotation device 108 may be configured to rotate the conveyance 106 and the entire BHA 110 in a first direction. The motor 116 may be configured to rotate the bent housing 114 and/or the drill bit 112 in a second direction. The one or more monitoring devices 118 may be configured to measure, and/or detect, the rotational speed of the conveyance 106 and/or the bent housing 114. The one or more monitoring devices 118 may send one or more data signals regarding the rotational speeds of the bent housing 114 and/or the conveyance 106 to a controller 122. The controller 122 may monitor the ratio of rotation between the bent housing 114 and the conveyance 106. The controller 122 may control, and/or manipulate the rotational speed of the motor 116 and/or the conveyance 106. By controlling the rotational speed conveyance 106, the controller 122 may steer, and/or manipulate the rotational direction, of the bent housing 114 and the drill bit 112 relative to the wellbore 100. For example, if the rotational speed of the conveyance 106 in the first direction is equal to the rotational speed of the bent housing 114 in the second direction, the bent housing 114 may remain in a stationary position. The controller 122 may then change the position of the bent housing 114 by varying the rotational speeds of the conveyance 106 and/or the bent housing 114. The rotational speeds of the conveyance 106 may be changed by altering the rotational speed at the surface while the rotational speed of the bent housing 114 and/or the drill bit 112 may be changed by altering the speed of the downhole motor, as will be discussed in more detail below. Thus, the controller 122 may steer the BHA 110 while drilling without the need to remove the BHA 110, or stop the rotation of the conveyance 106 during the drilling process, as will be discussed in more detail below.
The drilling rig 104 may be any suitable device for supporting the conveyance 106 and rotating the conveyance 106. The drilling rig 104 may be an off shore drilling rig for drilling into the sea floor, or an on land drilling rig.
The conveyance 106 may be any suitable conveyance for delivering the BHA 110 into the wellbore. In an embodiment, the conveyance 106 is a drill string consisting of sections of jointed piping coupled together on the drilling rig 104 as it is conveyed into the wellbore 100. When forming a wellbore, a section of jointed piping may be lowered into the wellbore 100 until a top portion of the piping is near a rig floor 124. A gripping device 126 on the rig floor 124 may then grip the piping segment. Another piping segment may be gripped and connected to the top of the pipe segment held in the rig floor 124. The coupled piping segments may then be released by the gripping device 126 and lowered into the wellbore 100. This process may be repeated to extend the length of the conveyance 106 as the wellbore 100 is formed. Although the conveyance 106 is described as a drill string, it should be appreciated that the conveyance 106 may be any suitable system for delivering a BHA 110 into and out of the wellbore 100 including, but not limited to, a casing string, a polyethylene pipe, a polymer drill pipe, a PVC pipe, FIBERSPAR® and the like. Further, the conveyance may be a wired drill pipe having one or more communication lines for transferring data within the conveyance 106.
The conveyance rotation device 108, as shown, is a top drive. The top drive may be configured to grip the conveyance 106, for example a drill string, or a piping segment, and rotate the conveyance 106. The rotation from the top drive allows the operator to couple the conveyance or piping segments together and allows the operator to rotate the entire drill string during drilling and run in. The rotation of the conveyance 106 may rotate the BHA 110. The rotation of the BHA 110 may assist in drilling of straight and deviated wellbores as will be described in more detail below. Further, the rotation of the conveyance 106 reduces the likelihood of differential sticking of the conveyance 106 to the wellbore 100 during drilling. Although the conveyance rotation device 108 is described as being a top drive it should be appreciated that the conveyance rotation device 108 may be any suitable device for rotating the conveyance 106 including, but not limited to a Kelly, a pipe spinner, and the like.
The BHA 110 may connect to the lower end of the conveyance 106 with a connector 200, as shown in FIG. 2A. The connector 200 may be any suitable connector to prevent the BHA 110 from becoming inadvertently disengaged from the conveyance 106. For example, the connector 200 may be a threaded connection having a box end and a pin end. Further, the connector 200 may be a releasable or frangible connection adapted to selectively release the BHA 110 from the conveyance 106 in the event the BHA 110 becomes stuck in the wellbore 100. Although the connector 200 is described as a threaded connection it should be appreciated that the connector 200 may be any suitable connection for coupling the conveyance 106 to the BHA 110 including, but not limited to, a pin connection, a welded connection, and the like.
FIG. 2A depicts a diagram illustrating a schematic view of the bottom hole assembly 110 in an embodiment. The BHA 110 may have the drill bit 112, the bent housing 114, the one or more motors 116, or power sections, the one or more monitoring devices 118 and a communication device 119. The drill bit 112 may be any tool configured to remove rock, soil, sand, and like while boring the wellbore 100. The drill bit 112 may be any suitable type of drill bit including, but not limited to, a roller cone bit, a polycrystialline diamond compact (PDC) drill bit, a coring bit, a drag bit and the like.
The communication device 119 may be any suitable device for communicating data and/or information about the wellsite. For example, the communication device 119 may be a telemetry device, a transceiver and the like. The communication device 119 may send and/or receive any suitable signal to the controller 122 (as shown in FIG. 1) and/or about the wellsite. The communication device 119 may send and/or receive digital signals, electrical signals, acoustic signals, mud pulse signals, wirelesss signals and the like.
The bent housing 114 may be configured to direct the path of the wellbore 100 (as shown in FIG. 1) during directional drilling operations. The bent housing 114 typically has a slight angled bend O. When the bent housing 114 is maintained in a rotationally stationary position, the wellbore 100 may be drilled at a slight angle, from the direction of the conveyance 106. Thus, as drilling is continued with the bent housing 114 substantially in one rotational position, the wellbore 100 will be directed, or deviated, in one direction. To drill in another direction, the bent housing 114 may be rotated relative to the longitudinal axis of the conveyance 106 to a second position. The operator may then drill in the second direction in a similar manner as described herein. To drill in a substantially straight line, the bent housing 114 may be rotated while rotating the drill bit 112, thereby continuously changing the direction the drill bit 112 drills. The continuous directional change of the drill bit 112 causes the drill bit 112 to bore, or drill out, a larger diameter wellbore corresponding to the rotation of the bent housing 114. Further, to drill in a straight line, the BHA 110 may be removed from the wellbore 100 and the bent housing 114 may be removed, or the BHA 110 may be replaced with a straight BHA 110, not shown. Further still, the bent housing 114 may be configured to straighten downhole automatically, and/or in response to instructions from the controller 122 or operator.
The BHA 110 may further include the one or more motors 116, or power sections. The motor 116 may be configured to produce torque, or rotational power, downhole in the BHA 110. In an embodiment, the motor 116 is a mud motor of a mouniea style. The mud motor produces rotational power from the flow of drilling fluid, or mud, through a fluid flow passage in the motor 116. The mud motor may include a rotor and a stator to produce the rotational power. Although the motor 116 is described as a mud motor, it should be appreciated that the motor 116 may be any suitable motor, or device for producing torque, or rotational power in the BHA 110 including, but not limited to, an electric motor, an electric motor powered by an electric generator coupled to a downhole fluid motor, a turbine, an air motor, and the like.
In an embodiment, one motor 116 located above the bent housing 114 is configured to rotate the bent housing 114 and orient the bent housing 114 relative to the conveyance 106. A second motor 116 may be located below the bent housing 114 for rotating the drill bit 112.
In an additional embodiment as shown in FIG. 2B, one motor 116 may be configured to rotate both the bent housing 114 and the drill bit 112. The motor 116 may be configured to rotate the bent housing 114 in the opposite direction of the conveyance 106. In this embodiment, the motor 116 may be located above the bent housing 114 and the drill bit 112. The location of the motor 116 above the bent housing 116 may require rotation to be transferred to the drill bit 112 through and independent of the bent housing 114 via a drive train 202. Thus, the motor 116 above the bent housing 114 may rotate the drill bit 112 while the bent housing 114 remains in a rotationally stationary position relative to the motor 116. Further, the BHA 110 may be configured to selectively engage the bent housing 114 thereby transferring torque to the bent housing 114. A shifting apparatus 201 or clutch may be used to selectively engage the bent housing 114 with the motor 116 thereby rotating the bent housing 114. It should be appreciated that the motor 116 may be located at any location above the BHA 110 so long as the motor 116 is capable of transferring torque to the BHA 110. Further, the motor 116 may be configured to continuously rotate both the bent housing 114 and the drill bit 112. In this instance, no shifting apparatus 201 would be required to selectively disengage the bent housing 114 from the motor 116.
In yet another alternative embodiment, there may be one motor 116 located between the bent housing 114 and the drill bit 112, as shown in FIG. 2C. In this example, the motor 116 may be adapted to rotate the drill bit 112 and selectively engage the bent housing 114 thereby rotating the bent housing 114 relative to the conveyance 106. The drive train 202 in this embodiment may extend toward the conveyance 106 and/or connector 200 in order to rotate the bent housing 114 relative to the conveyance 106.
The motor 116 as shown in FIGS. 2A-2C may be configured to spin in an opposite direction of the conveyance rotation device 108. The conveyance rotation device 108 may be configured to spin the conveyance in the first direction, for example clockwise. The conveyance joints (not shown) are typically threaded in a manner that may prevent them from coming uncoupled when the conveyance rotation device 108 rotates the conveyance in the first direction. Typical downhole motors, or mouniea style are also configured to rotate the BHA 110 in the first direction. The motor 116; however, may be designed to operate with reverse rotation of the typical mud motors. Thus, the motor 116 may spin the bent housing 114 in the second direction.
In another embodiment, the motor 116 may spin in the first direction and a gear box 203 may be configured to reverse the rotation applied to the bent housing 114. The gear box 203 may also change the speed of the rotation applied from the motor 116. It should be appreciated that the gear box 203 may be used to change the speed of any of the motors 116 described herein.
The BHA 110 may be similar to the BHA as described in (U.S. patent application Ser. No. 12/428,455 which is herein incorporated by reference in its entirety. Therefore, the BHA 110 may have a fixed clutch system that transfers rotational torque from the motor 116 to the drive train 202, or primary drive shaft. The drive train 202 may rotate the drill bit 112. The clutch system may be used to rotate the bent housing 114 using the motor 116, the drive train 202 and/or a gear box 203.
The BHA 110 may include the drive train 202. The drive train 202 may be configured to transfer torque from the motor 116 to the drill bit 112 as shown in FIGS. 2A and 2B, or from the motor 116 to the bent housing 114 as shown in FIG. 2C. The drive train 202 may be any component, or combination of components, capable of transferring torque to the drill bit 112. In an embodiment, the drive train 202 may be one or more shafts or pipes coupled together. A portion of the shaft may be coupled directly to the motor 116, or there may be an intermediate component between the shaft and the motor 116. The intermediate component may allow for a more flexible connection between portions of the drive train 202. For example, it may be necessary to transfer rotation from a rotor of the motor 116 to the drive train 202. The rotor may rotate and move slightly in the longitudinal and/or radial direction as it rotates, such as a rotor moves in a stator. The intermediate component in this case dampens the longitudinal and/or radial movement to the shaft while still transferring the rotation, or torque. Further, the intermediate component may allow for the transfer of rotation in components which are not straight, for example the bent housing 114. Thus, the intermediate component may bend within the bent housing 114 thereby allowing rotation to be transferred from the top end of the bent housing 114 to the bottom end. The intermediate component may be any component suitable for transferring rotation from the motor 116 to the shaft, for example a splined connection, a universal joint, a CV joint and the like. The drive train 202 may include any number of intermediate components between the drill bit 112 and the motor 116 so long as the torque from the motor 116 is transferred to the drill bit 112 and/or to the bent housing 114.
The drive train 202 may be configured to continuously transfer torque to the drill bit 112 when the motor 116 is rotating in an embodiment. Further, the drive train 202 may be configured to selectively transfer rotation to the bent housing 114. In an alternative embodiment, the drive train 202 may be configured to selectively disengage from the motor 116, and/or the drill bit 112 in order to halt drilling operations if necessary.
The BHA 110 may further include the one or more monitoring devices 118. One of the monitoring devices 118 located in the BHA 110 may be a bent housing rotation indicator 204, shown schematically. The bent housing rotation indicator 204 may be configured to measure the rotational speed of the bent housing 114 relative to the conveyance 106 in one embodiment. In this embodiment, the bent housing rotation indicator 204 may measure the rate at which the bent housing 114 rotates as it spins relative to the conveyance 106. In one instance, the bent housing rotation indicator 204 may consist of one or more nodes rotationally connected to the bent housing 114 which can be detected as they rotate past another portion of the BHA 110. The rate at which the nodes pass the detector is the speed of rotation of the bent housing 114. In this instance, the bent housing rotation indicator 204 may be the position indicator as described in (U.S. patent application Ser. No. 12/428,455 which is herein incorporated by reference in its entirety. Although the bent housing rotation indicator 204 is described as a series of nodes that are detected to determine the rotational speed and/or position of the bent housing 114, it should be appreciated that any suitable device for detecting the rotational speed of the bent housing 114 including, but not limited to, a gyroscope, a measurement while drilling tool (MWD) having an azimuth and/or inclination components, and the like.
The bent housing rotation indicator 204 may be configured to measure the rotational speed of the bent housing 114 relative to the wellbore 100 in an alternative embodiment. In this embodiment, the bent housing rotation indicator 204 measures only the rotational speed of the bent housing 114 relative to the earth. Thus, if the bent housing rotation indicator 204 indicates that there is no rotation of the bent housing 114, it could mean that the conveyance 106 and the motor 116 are stationary, or that the conveyance 106 is rotating at an equal but opposite rotational speed as the bent housing 114. In this embodiment, the bent housing rotation indicator 204 may be any suitable tool for measuring the global rotation of the bent housing 114 such as the MWD tool.
In addition to the bent housing rotation indicator 204, the BHA 110 may include any number of sensors, monitors and measuring tools in the one or more monitoring devices 118. For example, the one or more monitoring tools 118 in the BHA 110 may include a measure while drilling tool (MWD), an accelerometer, and the like. These tools may be used to determine any number of conditions in the BHA 110 including but not limited to, the drilling direction, the bit load, the rotational speed of the drill bit, the condition of the formation that is being drilled through, the rotational speed of the conveyance 106 downhole, and the like.
Each of the monitoring devices in the one or more monitoring devices 118 of the BHA 110 may independently send a data signal from the BHA 110 to the controller 122. Further the monitoring devices of the BHA 110 may send the data signal to a module, not shown, in the BHA 110. The module may then perform any number of operations to the data signal including, but not limited to, converting the data signals from analog to digital signals, sending the data signals to the controller 122, performing algorithms with data from the data signal in order to determine a downhole condition, and the like. In an embodiment, the data signals is sent via a wired connection to the controller 122. The data signal may be sent outside of the conveyance 106, inside the conveyance 106, in a wall of the conveyance 106 and/or any combination thereof. Although the data signal is described as a wired connection to the surface, it should be appreciated that the data signal may be any signal capable of communicating to the controller 122 including, but not limited to, a hydraulic signal, a pneumatic signal, mud pulse telemetry, telemetry, an electromagnetic signal, an RF signal, an acoustic signal, a wireless signal, a fiber optic signal, analog signals and the like.
In addition to the one or more monitoring devices 118 located in the BHA 110, there may be any number of sensors, monitors and measuring tools located on the conveyance 106, and/or drilling rig 104 for monitoring the condition of the drilling operation. In one embodiment, one of the one or more monitoring devices 118 is a conveyance rotation indicator 120, shown schematically in FIG. 1. The conveyance rotation indicator 120 may measure the rotational speed of the conveyance 106 at one or more locations on the conveyance 106. For example, there may be one conveyance rotation indicator 120 located near the earth's surface for measuring the rotational speed of the conveyance 106 at the Earth's surface. Further, there may any number of conveyance rotation indicators 120 located down hole, including proximate the BHA 110. As the conveyance 106 grows in length, the actual rotational speed of the conveyance 106 at the BHA 110, may be different than the rotational speed of the conveyance at the Earth's surface due to pipe spring. Thus, the conveyance rotation indicator 120 proximate the BHA 110 may allow the operator and/or controller 122 to measure the rotational speed of the conveyance 106 at the BHA 110 without the need to account for pipe spring. The conveyance rotation indicator 120 may be any suitable tool for determining the rotational speed of the conveyance 106 including, but not limited to, a tachometer on the top drive, a MWD tool, a gyroscope, and the like. The rotational speed of the conveyance 106 may be sent to the controller 122 by any suitable method described herein, including by wired and wireless transmission. In addition to the conveyance rotation indicator 120 there may be any number of devices for detecting conditions of the conveyance 106 and/or drilling system including flow meters for determining flow of fluid pump into and/or our of the wellbore, strain gauges to detect the strain in the conveyance 106 as it is rotated, weight on bit monitors, and the like.
The controller 122 may send and receive data signals to and from the one or more monitoring devices 118. Further, the controller 122 may send data signals to and from the conveyance rotation device 108, the gripping apparatus 126, the pumps (not shown) for pumping fluid into the conveyance 106, a computer network, or server, any number of client computers, and the like. The controller 122 may be configured to manipulate the data sent from the various wellbore components. The data may be used to determine the condition of the drilling systems during the drilling operation. The controller 122 may then manipulate various drilling components based on the data, and/or an operator's instructions in order to manipulate the drilling systems in response to the data, as will be described in more detail below. To this end the controller 122 may include one or more displays, one or more i/o devices, for example a keyboard, a mouse, a voice recognition system, and the like.
FIG. 3 depicts a schematic view of a wellbore management system 300. The wellbore management system 300 may take the form of an entirely hardware embodiment, an entirely software embodiment (including firmware, resident software, micro-code, etc.) or an embodiment combining software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” Furthermore, embodiments of the wellbore management system 300 may take the form of a computer program product embodied in any tangible medium of expression having computer usable program code embodied in the medium. The described embodiments may be provided as a computer program product, or software, that may include a machine-readable medium having stored thereon instructions, which may be used to program a computer system (or other electronic device(s)) to perform a process according to embodiments, whether presently described or not, since every conceivable variation is not enumerated herein. A machine readable medium includes any mechanism for storing or transmitting information in a form (e.g., software, processing application) readable by a machine (e.g., a computer). The machine-readable medium may include, but is not limited to, magnetic storage medium (e.g., floppy diskette); optical storage medium (e.g., CD-ROM); magneto-optical storage medium; read only memory (ROM); random access memory (RAM); erasable programmable memory (e.g., EPROM and EEPROM); flash memory; or other types of medium suitable for storing electronic instructions. In addition, embodiments may be embodied in an electrical, optical, acoustical or other form of propagated signal (e.g., carrier waves, infrared signals, digital signals, etc.), or wireline, wireless, or other communications medium.
Computer program code for carrying out operations of the embodiments may be written in any combination of one or more programming languages, including an object oriented programming language such as Java, Smalltalk, C++ or the like and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code may execute entirely on a user's computer, partly on the user's computer, as a stand-alone software package, partly on the user's computer and partly on a remote computer or entirely on the remote computer or server. In the latter scenario, the remote computer may be connected to the user's computer through any type of network, including a local area network (LAN), a personal area network (PAN), or a wide area network (WAN), or the connection may be made to an external computer (for example, through the Internet using an Internet Service Provider).
FIG. 3 depicts a schematic diagram of the wellbore management system 300 according to some embodiments. The wellbore management system 300 may include the controller 122, the one or more monitoring devices 118, the BHA 110, the conveyance 106, the conveyance rotation device 108, a communication network 302, or server, and one or more communication clients 304, or clients. The communication network 302 may allow for communication about the well site for example, between the one or more monitoring devices 118, the controller 122 and the one or more communication clients 304. The communication client(s) 304 may be any combination of devices which allow a user, or operator, or other entity to send and/or receive communications, and/or data, to and from the wellbore systems. For example, the communication clients 304 may include a computer located at the wellbore, an offsite computer, a remote computer at a home office, a desktop computer, a laptop computer, a handheld device, a cell phone, a personal digital assistant, a telephone, and the like. The communications may be any communication capable of relaying data and/or information to a message receiver, or operator. The communication network 302 may include any combination of computer networks and/or data transmission devices, including but not limited to wired connections, wireless connections, infrared, and the like.
The wellbore management system 300 may be configured to control the direction of drilling of the wellbore 100 in an embodiment. In this embodiment, the wellbore management system 300 may receive data from at least one of the one or more monitoring devices 118 regarding the rotational speed of the bent housing 114. The wellbore management system 300 may further receive data regarding the rotational speed of the conveyance 106. The conveyance 106 may be rotating in the first direction, for example clockwise, while the motor 116 may be rotating the bent housing 114 in a second direction opposite to the conveyance 106 rotation, for example counterclockwise. Although the first direction is described as being clockwise, while the second direction is counterclockwise, it should be appreciated that the first direction may be counterclockwise, while the second direction is clockwise. The wellbore management system 300 may then control the direction of the drill bit 112 by controlling the relative speed of rotation of the bent housing 114 and the conveyance 106. For example, if the bent housing 114 is rotating in the second direction at the same speed as the conveyance 106 is rotating in the second direction, the bent housing 114 will remain in a relative rotationally fixed position. In the rotationally fixed position the operator, and/or controller 122, may drill a deviated wellbore. If the operator, and/or controller 122 wish to change the direction of the drill bit, the controller 122 may instruct the conveyance 106 rotational speed to change, the bent housing 114 rotational speed to change, both the conveyance 106 rotational speed and the bent housing 114 rotational speed to change, and/or the weight on the drill bit to change, until the bent housing 114 is in the desired rotational direction. Increasing or decreasing the weight on the drill bit may effect the rotational speed of the conveyance 106 near the BHA 110 by changing the pipe spring dynamic of the conveyance 106. With the bent housing 114 in the desired direction, the operator, and/or controller 122 may then maintain the rotational speeds of the conveyance 106 and the bent housing 114 in the first and second direction to substantially equal one another in order to drill in the new direction.
The controller 122 may include a rotating drilling controller 400 as shown in FIG. 4. The rotating drilling controller 400 may include a storage device 402, a bent housing rotation unit 404, a conveyance rotation unit 406, a drill bit position unit 408, a global position unit 410, and a transmission receiver unit 412. The storage unit 400 may store any suitable data, and/or information, relating to the wellbore management system 300 including, but not limited to, the location of the BHA 110, rotational speed of the bent housing 114, rotational speed of the conveyance 106, historical data regarding drill path, drill bit loading, weight on bit, drilling direction, global location of BHA, formation types, user/operator information, data about current and historic communications, and the like.
The bent housing rotation unit 404 may determine the rotational speed of the bent housing 114. In one embodiment, the bent housing rotation unit 404 receives data from the one or more monitoring devices 118 regarding the rotational speed of the bent housing 114. For example, the bent housing rotation indicator 204 may send a data signal regarding the rotational speed of the bent housing 114 to the bent housing rotation unit 404. The data from the bent housing rotation indicator 204 may be analyzed by the bent housing rotation unit 404 in order to determine the rotational speed of the bent housing 114 in the wellbore 100. In one embodiment, the data regarding the rotational speed of the bent housing 114 is a relative rotational speed of the bent housing 114. Thus, in this embodiment, the rotational speed would be the rotational speed in which the bent housing 114 rotates relative to another downhole item for example the conveyance 106, the motor 116, the drive shaft, and the like.
In another embodiment, the rotational speed of the bent housing 114 determined by the bent housing rotation unit 404 is the global rotational speed of the bent housing 114. Thus the bent housing rotation unit 404 may determine the global rotational speed of the bent housing 114 relative to the wellbore 100, or other fixed item.
The conveyance rotation unit 406 may determine the rotational speed of the conveyance 106. In one embodiment, the conveyance rotation unit 406 receives data from the one or more monitoring devices 118, including the conveyance rotation monitor(s) 120. The conveyance rotation monitors 120 may measure the rotational speed of the conveyance 106 at one or more locations on the conveyance 106. The data collected regarding the rotational speed of the conveyance 106 may then be sent to the conveyance rotation unit 406. The conveyance rotation unit 406 may then analyze the data in order to determine the rotational speed of the conveyance 106 at one or more locations on the conveyance 106. For example, the conveyance rotation unit 406 may determine the rotational speed of the conveyance 106 near the bottom of the conveyance 106. The rotational speed of the conveyance 106 may vary at different locations on the conveyance 106 due to the length of the conveyance 106, lag, torque build up, or twist, in the conveyance 106. Thus, the rotational speed of the conveyance 106 at any location on the conveyance 106 may need to be calculated by analyzing any number of conditions in the conveyance 106. For example, it may be necessary to calculate the rotational speed of the conveyance 106 at the connector 200 by rectifying a number of factors in the conveyance 106 including, but not limited to, the load in the conveyance, weight on the drill bit, the length of the conveyance, the strain the conveyance, and the rotational speed of the conveyance at one or more locations. The conveyance rotation unit 406 may then analyze the data and determine the rotational speed of the conveyance 106.
The drill bit position unit 408 may receive data regarding the rotational speed of the bent housing 114 and/or the rotational speed of the conveyance 106. Because the bent housing 114 rotates in the opposite direction of the conveyance 106, it is possible to rotate the bent housing 114 and the conveyance 106 at equal but opposite speeds. This opposite rotation may allow the controller 122 and/or the operator to maintain the global position of the bent housing 114 and the drill bit 112 in a substantially rotationally fixed position. The drill bit position unit 408 may determine the global rotational speed of the bent housing 114 and the drill bit, by analyzing the rotational speed of the bent housing 114 and the conveyance 106. The drill bit position unit 408, may then determine the global rotational speed of the bent housing 114 relative to the wellbore 100.
In another embodiment, the drill bit position unit 408 may determine the rotational speed of the bent housing 114 and therefore the drill bit, by analyzing only the global rotational speed of the bent housing 114 received from the bent housing rotational unit 404.
The drilling position unit 410 may determine the drilling direction of the drill bit 112 and/or bent housing 114 by receiving the global rotational speed of the bent housing 114. The drilling position unit 410 may control the drilling direction by controlling the rotational speed of the conveyance 106 and/or the bent housing 114. In order to control the global rotational speed of the bent housing 114, the drilling position unit 410 may vary the rotational speed in the conveyance 106, the motor 116, the weight on the drill bit, or any combination thereof. For example, if the operator wants the bent housing 114 to be rotationally fixed and the drilling position unit 410 indicates that the bent housing is rotating slightly in the first direction, the direction the conveyance 106 is rotating, the drilling position unit 410 may decrease the rotational speed of the conveyance 106, may increase the rotational speed of the motor 116, or any combination thereof to obtain rotational speeds that substantially fixes the rotation of the bent housing 114. Thus, the drilling position unit 410 may continually monitor and control the rotational position of the bent housing 114 and the drill bit 112 by controlling the rotational speed of the conveyance 106 and/or the bent housing 114.
The global position unit 412 may receive data regarding the position of the BHA 110 and control the direction of the drilling operation. The global position unit 412 may receive data regarding the position of the bent housing 114, the drill bit 112 and the wellbore 100, from any one of the one or more monitoring devices 118. The global position unit 412 may identify the position of the bent housing 114, and/or the location of the BHA 110 in the Earth. The global position unit 412 may then compare the position of the bent housing 114 and/or the BHA 110 with a desired drilling path. The desired drilling path may be programmed in the rotating drilling controller 400 prior to drilling, or the operator may input the drilling direction as the BHA 110 travels in the wellbore 100. If the actual direction of the bent housing 114, and/or BHA 110 are not traveling along the desired drilling direction, the global position unit 412, may correct the drilling direction by changing the rotational speed of the conveyance 106 and/or the motor 116. Further, the global position unit 412 may change any number of drilling factors in order to obtain the substantially correct drilling path.
The transceiver unit 410 may allow the rotating drilling controller 400 to send and receive information or data. The information and/or data may be any suitable information related to the wellbore management system 300.
Although the rotating drilling controller 400 is shown as one unit in a server client model, it should be appreciated that the rotating drilling controller 400 may be included wholly or partially on any number of the communication clients 304, the network 302, in the BHA 110, in the conveyance rotation device, and/or any of the one or more monitoring devices 118. Further, it should be appreciated that the components of the rotating drilling controller 400, such as the bent housing rotation unit 404, the conveyance rotation unit 404, a global BHA unit 406, a drilling position unit 408 and/or the transmission receiver unit 410, may be included wholly or partially in other components of the drilling management system 300.
FIG. 5 depicts a flow diagram illustrating the operations of the wellbore management system 300 (as shown in FIG. 3), according to some embodiments of the invention. The flow begins at block 502, where a desired drill path is selected. The desired drill path may be predetermined before the drilling operation begins. Further, the desired drill path may be selected while drilling. Further, the desired drill path may be a combination of a predetermined drill path and a drill path that is selected while drilling. The desired drill path may be determined based on geological data of the region to be drilled, or based on any other data regarding the region. Thus, the operator may desire to drill to a certain formation under the Earth's surface. The operator may then set the desired drill path in the controller 122 in order to reach the formation. The operator may set the desired drill path at the drilling rig, or at a remote location, for example an office and send the desired drill path to the controller 122. Once the desired drill path is determined the drilling operation may commence. The drilling operation may commence by lifting a portion of the conveyance 106 above the rig floor and coupling the BHA 110 to the bottom of the portion of the conveyance 106.
The conveyance rotation device 108 may then begin to rotate the conveyance 106 and the BHA 110. The motor 116 may then be activated to rotate the drill bit 112, and possibly the bent housing 114. The motor 116, or the gear box, may be configured to rotate the bent housing 114 in the opposite rotational direction as the conveyance rotation device 108 rotates the conveyance 106. The wellbore 100 may be drilled straight by allowing the bent housing 114 either not be rotated by the motor 116, or by rotating the bent housing 114 at a speed that is not substantially equivalent to the conveyance 106 rotational speed. In this examples, as the conveyance 106 is rotated the bent housing 114 rotates within the wellbore 100 thereby creating a substantially straight wellbore 100. When the predetermined path needs the wellbore 100 to change directions, or deviate, the conveyance 106 will be rotated at a substantially equal but opposite speed as the bent housing 114 thereby substantially fixing the rotational position of the bent housing 114. Continued drilling with the bent housing 114 in the substantially fixed rotational position will bend, or deviate, the wellbore 100.
The flow continues at block 504, where the rotational speed of the bent housing 114 is determined. The rotational speed of the bent housing 114 may be determined by the bent housing rotational unit 404. For example, the rotational speed of the bent housing 114 may be measured by the bent housing rotation indicator 204 and/or any of the suitable one or more monitors 118. The bent housing rotation indicator 204 may send a data signal to the bent housing rotation unit 404 in order to determine the rotational speed of the bent housing 114.
The flow continues at block 506, where the rotational speed of the conveyance 106 is determined. The rotational speed of the conveyance 106 may be determined by the conveyance rotation unit 406. For example, the conveyance rotation unit 406 may receive data signals from the conveyance rotation indicator(s) 120 and/or the one or more monitoring devices 118. The conveyance rotation unit 406 may then determine the rotational speed of the conveyance 106.
The flow continues at block 508, where the rotational position of the bent housing and/or the drill bit is determined. The global position unit 410 may determine the rotational position of the bent housing 114 and/or the drill bit. Further, the global position unit 410 may determine the global position of the BHA 110 beneath the Earth's surface. With the rotational position of the bent housing 114 and the global position of the BHA 110 known, the global position and direction of the wellbore 100 may be determined and logged while the wellbore 100 is formed.
The flow continues at block 510, where it is determined if the bent housing 114 and/or the BHA 110 are in position to drill along the desired drill path. In this step, the global position of the bent housing 114 is compared to the desired drilling direction. The global position unit 410 may receive data signals from the one or more monitoring devices 118, the bent housing rotation unit 404, the conveyance rotation unit 406 and/or the drill bit position unit 408 in order to determine the global and rotational position of the BHA 110 and bent housing 114. The global position unit 410 may compare the rotational direction of the bent housing 114 and/or drill bit 112, with the desired drilling path to determine if drilling is continuing substantially along the desired drill path. Further, the global position unit 410 may compare the global location of the BHA 110 with the desired drill path to determine if the BHA 110 needs to deviate from its current course.
If the global position unit 410 determines that the global position of the BHA 110 and the rotational position of the bent housing 114 are positioned to drill along the desired drill path, the flow continues at block 512. At block 512 drilling operations are continued along the desired drilling path.
If the global position unit 410 determines that the global position of the BHA 110 and the rotational position of the bent housing 114 are not positioned to drill along the desired drill path, the flow continues at block 514. At block 514, the position of the bent housing 114 is adjusted in order to reorient the BHA 110 along the desired drill path. The global position unit 410 may adjust the BHA 110 position by changing the rotational speed of the bent housing 114, varying the weight on the drill bit, and/or changing the rotational speed of the conveyance 106 in order to change the global rotational position of the bent housing 114, as described herein. Once the global position unit 410 changes the course of the BHA 110 to the desired drill path, the flow continues at block 512, where drilling is continued.
FIG. 6 depicts an example computer system. A computer system includes a processor unit 602 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer system includes memory 630. The memory 630 may be system memory (e.g., one or more of cache, SRAM, DRAM, zero capacitor RAM, Twin Transistor RAM, eDRAM, EDO RAM, DDR RAM, EEPROM, NRAM, RRAM, SONOS, PRAM, etc.) or any one or more of the above already described possible realizations of machine-readable media. The computer system also includes a bus 624 (e.g., PCI, ISA, PCI-Express, HyperTransport®, InfiniBand®, NuBus, etc.), a network interface 620 (e.g., an ATM interface, an Ethernet interface, a Frame Relay interface, SONET interface, wireless interface, etc.), and a storage device(s) (e.g., optical storage, magnetic storage, etc.). The system memory 630 embodies functionality to implement embodiments described above. The system memory 630 may include one or more functionalities that facilitate drilling along a desired path by controlling the rotational speed of the bent housing 114 and the conveyance 106. To this end the memory 630 may include the rotating drilling controller 400, the bent sub rotation unit 404, the conveyance rotation unit 406, the drill bit position unit 408, and/or the global position unit 410. Any one of these functionalities may be partially (or entirely) implemented in hardware and/or on the processing unit 602. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processing unit 602, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 5 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor unit 602, the memory 630, and the network interface 620 are coupled to the bus 624. Although illustrated as being coupled to the bus 624, the memory 630 may be coupled to the processor unit 602.
While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.
Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.

Claims

1. A drilling tool, comprising:

a conveyance for delivering a bottom hole assembly into a wellbore;

a conveyance rotation device configured to rotate the conveyance in a first direction;

the bottom hole assembly comprising:

a drill bit;

a bent housing; and

a motor configured to rotate the bent housing in a second direction relative to the conveyance;

one or more monitor devices configured to monitor the rotational speed of the bent housing; and

a controller configured to control the relative rotational speed in the first direction and the second direction and thereby control the rotational direction of the bent housing during drilling.

2. The drilling tool of claim 1, wherein the one or more monitoring devices further comprises a bent housing rotation indicator.

3. The drilling tool of claim 2, wherein the bent housing rotation indicator further comprises a plurality of upsets coupled to a portion of the mandrel and a sensor configured to detect each of the upsets as the upset rotates past the sensor.

4. The drilling tool of claim 1, wherein the one or more monitoring devices further comprises a measurement while drilling tool.

5. The drilling tool of claim 1, wherein the one or more monitoring devices further comprises a conveyance indicator.

6. The drilling tool of claim 5, wherein the conveyance indicator is a measurement while drilling tool located proximate the bottom hole assembly.

7. The drilling tool of claim 1, wherein the conveyance is a drill string.

8. The drilling tool of claim 1, wherein the conveyance rotation device is a top drive.

9. A method of forming a wellbore, comprising:

selecting a desired drill path;

drilling the wellbore with a bottom hole assembly (BHA) coupled to a conveyance, the bottom hole assembly comprising:

a drill bit;

a bent housing;

a motor;

rotating the conveyance in a first direction;

rotating the bent housing in a second direction opposite to the first direction;

determining the rotational position of the bent housing in the wellbore using one or more monitors proximate the BHA;

adjusting the rotational position of the bent housing; and

drilling along the desired drill path.

10. The method of claim 9, wherein determining the rotational position of the bent housing further comprises monitoring the rotational speed of the conveyance proximate the BHA.

11. The method of claim 10, wherein determining the rotational position of the bent housing further comprises monitoring the rotational speed of the bent housing.

12. The method of claim 10, further comprising comparing the rotational speed of the bent housing with the conveyance.

13. The method of claim 9, wherein adjusting the rotational position of the bent housing further comprising changing the rotational speed of the conveyance.

14. The method of claim 9, wherein adjusting the rotational position of the bent housing further comprising changing the rotational speed of the bent housing.

15. The method of claim 9, wherein adjusting the rotational position of the bent housing further comprising changing the weight on the drill bit.

16. A method of controlling the rotational direction of a bottom hole assembly (BHA), comprising:

delivering the BHA into a wellbore on a conveyance wherein the BHA comprises

a bent housing and a downhole tool;

rotating the conveyance in a first direction;

monitoring the rotational speed of the conveyance;

rotating the bent housing in a second direction;

monitoring the rotational speed of bent housing; and

controlling the relative rotational speed in the first and second direction and thereby controlling the rotational position of the bent housing and downhole tool.

17. The method of claim 16, wherein monitoring the rotational speed of the bent housing further comprising sending a signal from a bent housing rotation indicator in the BHA to a controller.

18. The method of claim 16, wherein monitoring the rotational speed of the bent conveyance further comprising sending a signal from a monitoring device proximate the BHA.

19. The method of claim 16, further comprising comparing the rotational speed in the first direction and the second direction in a rotating drilling controller.

20. The method of claim 16, further comprising determining a global rotational position of the bent housing in the wellbore.