Patent Publication Number: US-8528662-B2

Title: Position indicator for drilling tool

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims the priority benefit of U.S. provisional patent application No. 61/125,193, titled “Radial Position Indicator of Rotating Drilling Tool,” filed Apr. 23, 2008 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 position indicator for determining a position of a downhole tool. 
     Conventional directional drilling with jointed pipe is accomplished through use of a Bottom Hole Assembly (BHA) consisting of a bent housing or bent sub, a power section, a drill bit, and a directional Measurement While Drilling (MWD) tool. The drilling motor is typically located between 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 drilling motor. The bent housing will slowly cause the wellbore to bend as the drill string is lowered into the earth with the 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. 
     SUMMARY 
     Embodiments described herein include a position indicator for use in a downhole tool. The position indicator comprises a mandrel configured to rotate in a wellbore and a plurality of upsets coupled to a portion of the mandrel. The position indicator may further comprise a sensor configured to detect each of the upsets as the upset rotates past the sensor and a signal sent from the sensor to a controller wherein the signal is configured to represent the rotational position of one or more of the upsets. 
     Embodiments described herein include a method for determining the position of a downhole tool. The method comprising rotating a drive train using a downhole motor and rotating the downhole tool with the drive train. The method further comprising sensing the rotation of the downhole tool by determining the position an upset on the downhole tool as the upset rotates past a sensor, and transmitting the rotational position of the downhole tool to a controller. 
    
    
     
       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. 
         FIG. 2  depicts a diagram illustrating a schematic view of a bottom hole assembly (BHA) in an embodiment. 
         FIG. 3  depicts a diagram illustrating a cross sectional view of a portion of the BHA in an embodiment. 
         FIG. 4  depicts a diagram illustrating a cross sectional view of a portion of the BHA in an embodiment. 
         FIG. 5  depicts a diagram illustrating a cross sectional top view of a portion of the BHA in an embodiment. 
         FIG. 6  depicts a diagram illustrating a cross sectional view of a portion of the BHA in an embodiment. 
         FIG. 7  depicts a diagram illustrating a cross sectional view of a portion of the BHA in an embodiment. 
         FIG. 8  depicts a diagram illustrating a cross sectional view of a portion of the BHA in an embodiment. 
         FIG. 9  depicts a geometric representation of the location of upsets detectable by a sensor on the downhole tool. 
     
    
    
     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 and monitoring 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. The BHA may include a motor and/or power section, a drill bit, a drive train connecting the drill bit to the motor, a bent housing, a shifting apparatus, and a position indicator. The motor transfers rotational motion to the drill bit, thereby allowing the BHA to drill the wellbore. The shifting apparatus may allow for rotation to be transferred to the bent housing in order to rotate the bent housing downhole. The rotation of the bent housing allows the operator to change the direction of the drilling without needing to pull the entire BHA out of the wellbore. The position indicator allows the operator to determine the position of the bent housing as it rotates due to the motor rotation. The position indicator may send a signal to a controller and/or an operator which allows the operator to determine the position of the bent housing. When the bent housing is in a desired rotational position the operator may disengage the shifting apparatus from the bent housing thereby fixing the rotational position of the bent housing relative to the motor. The drilling operation may then proceed with the bent housing in the fixed position. As drilling continues with the rotation of the bent housing fixed, a deviated, or directed, wellbore is formed. 
       FIG. 1  depicts a schematic view of a wellbore  100  having a downhole tool  102  according to an embodiment. The downhole tool  102  may include a delivery system  104 , a conveyance  106  and a bottom hole assembly (BHA)  108 . The delivery system  104  delivers the conveyance  106  and the BHA  108  into the wellbore  100 . The conveyance may be any suitable system for conveying the BHA  108  into the wellbore  100 . The BHA  108  may include a motor  110 , a drive train  112 , a drill bit  114 , a bent housing  116 , or bent sub, a shifting apparatus  118  and a position indicator  120  in an embodiment described herein. The motor  110  may rotate the drill bit  114  using the drive train  112 . When the position of the bent housing  112  needs to be adjusted to control the drilling direction, the operator may use the shifting apparatus  118  to rotationally couple the bent housing  116  to the motor  110 . The position indicator  120  may detect the rotational position of the bent housing  116  as the bent housing rotates. The detected rotational position of the bent housing  116  may be sent to a controller  122 , and/or operator via a communication signal  124 . When the bent housing  116  is in the proper position the shifting apparatus  118  may disengage the bent housing  116  from the motor  110  thereby fixing the position of the bent housing  116  relative to the motor  110 . The drilling operation may continue with the bent housing  116  in the fixed position. 
     The conveyance  106  may be any suitable conveyance for delivering the BHA  108  into the wellbore. In an embodiment, the conveyance  106  is a coiled tubing. Coiled tubing is tubing which is wound on a drum, or spool, (not shown). The coiled tubing may be fed into the wellbore  100  as the tubing is unwound from the drum. Coiled tubing is advantageous in that no pipe joints have to be assembled, or disassembled, while the conveyance  106  is being run into or pulled out of the wellbore  100 . The tubing is simply unwound into the wellbore  100 . When forming a wellbore, the use of coiled tubing for drilling saves rig time versus wellbores drilled with jointed pipe. However, it is difficult to transfer rotation to a downhole tool, or BHA  108 , through the coiled tubing due to the continuous nature of the tubing. Although the conveyance  106  is described as a coiled tubing, it should be appreciated that the conveyance  106  may be any suitable system for delivering a BHA  108  into and out of the wellbore including, but not limited to, a drill string, a casing string, a wire line, a slick line, a polyethylene pipe, a polymer drill pipe, a PVC pipe, FIBERSPAR® and the like. 
     The delivery system  104  may be any suitable system for delivering the conveyance  106  and thereby the BHA  108  into and out of the wellbore  100 . In an embodiment, the delivery system  104  is a coiled tubing injection system. The coiled tubing injection system may include a mobile platform for transporting the spool, or drum, and/or the coiled tubing. The injection system may grasp the coiled tubing and exert a linear force on the coiled tubing in order to feed the tubing into the wellbore  100 . Although the delivery system  104  is described as a coiled tubing injection system, it should be appreciated that the delivery system  104  may be any suitable delivery system including, but not limited to, a drilling rig for assembling drill strings and/or casing strings, and the like. 
     The BHA  108  may connect to the lower end of the conveyance  106  with a connector  123 . The connector  123  may be any suitable connector to prevent the BHA  108  from becoming inadvertently disengaged from the conveyance  106 . For example, the connector  123  may be a threaded connection having a box end and a pin end. Further, the connector  123  may be a releasable or frangible connection adapted to selectively release the BHA  108  from the conveyance  106  in the event the BHA  108  becomes stuck in the wellbore  102 . Although the connector  123  is described as a threaded connection it should be appreciated that the connector  123  may be any suitable connection for coupling the conveyance  106  to the BHA  108  including, but not limited to, a pin connection, a welded connection, and the like. 
     The BHA  108  may further include the motor  110 . The motor  110  is configured to produce torque, or rotational power, downhole in the BHA  108 . In an embodiment, the motor  110  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  110 . The mud motor may include a rotor and a stator to produce the rotational power. Although the motor  110  is described as a mud motor, it should be appreciated that the motor  110  may be any suitable motor, or device for producing torque, or rotational power in the BHA  108  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, a top drive for rotating a portion of the conveyance, a pipe spinner, and the like. 
     The motor  110  may be located above the bent housing  112  and the drill bit  114 , in an embodiment described herein. The location of the motor  110  above the bent housing  116  may require rotation to be transferred to the drill bit  114  through and independent of the bent housing  112 . Thus, the motor  110  above the bent housing  116  may rotate the drill bit  114  while the bent housing  116  remains in a rotationally stationary position relative to the motor  110 . Further, the BHA  108  may be configured to selectively engage the bent housing  112  thereby transferring torque to the bent housing  116  as will be described in more detail below. It should be appreciated that the motor  110  may be located at any location above the BHA  108 , including the earth&#39;s surface, so long as the motor  110  is capable of transferring torque to the BHA  108 . 
     In an alternative embodiment, there may be more than one motor  110 . For example, there may be one motor located above the BHA  108  configured to orient the bent housing  116  and one motor located between the bent housing  116  and the drill bit  114  and configured to rotate the drill bit  116 . 
     In yet another alternative embodiment, there may be one motor  110  located between the bent housing  116  and the drill bit  114 . In this example, the motor may be adapted to rotate the drill bit  114  and selectively engage the bent housing thereby rotating the bent housing  116  relative to the conveyance  106 . 
     The BHA  108  may include the drive train  112 . The drive train  112  may be configured to transfer torque from the motor  110  to the drill bit  114 . The drive train  112  may be any component, or combination of components, capable of transferring torque to the drill bit  114 . In an embodiment, the drive train may be one or more shafts or pipes coupled together. A portion of the shaft may be coupled directly to the motor  110 , or there may be an intermediate component between the shaft and the motor  110 . The intermediate component may allow for a more flexible connection between portions of the drive train  112 . For example, it may be necessary to transfer rotation from a rotor to the drive train. 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 connection may allow for the transfer of rotation in components which are not straight, for example the bent housing  116 . Thus, the intermediate component may bend within the bent housing  116  thereby allowing rotation to be transferred from the top end of the bent housing  116  to the bottom end. The intermediate component may be any component suitable for transferring rotation from the motor  110  to the shaft, for example a splined connection, a universal joint, a CV joint and the like. The drive train  112  may include any number of intermediate components between the drill bit  114  and the motor  110  so long as the torque from the motor  110  is transferred to the drill bit  114 . 
     The drive train  112  may be configured to continuously transfer torque to the drill bit  114  when the motor  110  is rotating in an embodiment. Further, the drive train  112  may be configured to selectively transfer rotation to the bent housing  116 , as will be described in more detail below. In an alternative embodiment, the drive train  112  may be configured to selectively disengage from the motor  110 , and/or the drill bit  114  in order to halt drilling operations if necessary. 
     The drill bit  114  may be any tool configured to remove rock, soil, sand, and like while boring the wellbore  100 . The drill bit  114  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 bent housing  116  may be configured to direct the path of the wellbore  100  during directional drilling operations. The bent housing  116  typically has a slight angled bend Θ. When the bent housing  116  is held in a rotationally stationary position the wellbore  100  will be drilled at a slight angle, from the direction of the conveyance  106 . Thus, as drilling is continued with the bent housing  116  in one rotational position, the wellbore  100  will be directed, or deviated, in one direction. To drill in another direction, the bent housing  116  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 above. To drill in a substantially straight line, the bent housing  116  may be rotated while rotating the drill bit  114 , thereby continuously changing the direction the drill bit  114  drills. The continuous directional change of the drill bit  114  causes the drill bit  114  to bore, or drill out, a larger diameter wellbore corresponding to the rotation of the bent housing  116 . Further, to drill in a straight line, the BHA  108  may be removed from the wellbore and the bent housing may be removed, or the BHA  108  may be replaced with a straight BHA  108 , not shown. Further still, the bent housing  116  may be configured to straighten downhole automatically, and/or in response to instructions from the controller or operator. 
     To rotate the bent housing  116  relative to the BHA  108  the shifting apparatus  118 , shown schematically in  FIGS. 1 and 2 , couples the drive train  112  and/or the motor  110  to the bent housing  116 .  FIG. 2  depicts a schematic view of the BHA  108  showing the shifting apparatus  118  and a cross sectional view of one or more mandrels configured to rotate the bent housing  116 . In an embodiment, there may be one or more stationary mandrels  200 . The stationary mandrels  200  remain rotationally stationary relative to the BHA  108  during drilling and orienting of the bent housing  116 . There may be one or more rotating mandrels  202 . The rotating mandrel(s)  202  may be configured to selectively engage the drive train  112  via the shifting apparatus  118 . With the rotating mandrel  202  engaged with the drive train  112 , the motor rotates the rotating mandrel  202 . A portion of the rotating mandrel may  202  be coupled to the bent housing  116 . Thus, the shifting apparatus  118  may selectively engage the rotating mandrel(s)  202  and transfer rotation from the drive train  112  to the bent housing  116 . 
     The rotating mandrel(s)  202  may rotate in close proximity to a portion of the stationary mandrel  200 . For example, a portion of the rotating mandrel  202  is shown located on the interior of a portion of the stationary mandrel  200  in  FIG. 2 . There may be one or more seals  204 , or o rings, between the rotating mandrel  202  and the stationary mandrel  200  to prevent fluid from entering, or leaving the space between the mandrels. The stationary mandrle(s)  200  may serve as a housing for the rotating mandrel(s). Thus, the stationary mandrel  200  may protect the rotating mandrel(s)  202  from exposure to the downhole environment. The rotating mandrel(s)  202  may be connected to the bent housing  116  using any know connection such as a threaded connection, a welded connection and the like. Further, the rotating mandrel(s)  202  may be integral with the bent housing  116 . 
     The position indicator  120  indicates the rotational position of the rotating mandrel  202 , and thereby the bent housing  116 , as the rotating mandrel  202  rotates relative to the stationary mandrel(s)  200 . The position indicator  120  may include one or more upsets  206 , or position marks, which move with the rotating mandrel  202  as the mandrel, and thereby the bent housing  116  rotates. A sensor  208  may be stationary and coupled to the stationary housing  200 . The sensor  208  may detect one or more of the upsets  206  as the upsets rotate past the sensor  208 . Thus, as the rotating mandrel  202  rotates relative to the stationary mandrel  200 , the sensor  208  detects the rotational position of the rotating mandrel  202  by detecting the one or more upsets  206 . Therefore, the sensor  208  detects the rotational position of the bent housing  116  as it rotates by detecting the upsets  206 . Although the upsets  206  are described as being located on the rotating mandrel  202  and the sensor  208  is described is being located on the stationary mandrel  200 , it should be appreciated that the upset  206  may be located on the stationary mandrel  200  and the sensor  208  may be located on the rotating mandrel  202 . Further, the upsets  206  may be located directly on the bent housing  116 . 
     The rotational speed of the motor  110  may be faster than desired for rotating the bent housing  116 . Therefore, there may be one or more speed reducers and/or one or more gears  210  connected to a portion of the rotating mandrel(s)  202 . The one or more gears  210  may be any device suitable for reducing the rotational speed of the rotational mandrel  202 , and/or the bent housing  116  including, but not limited to, a planetary gear, a series of spur gears, a helical gear, and the like. 
     The shifting apparatus  118  may be any device capable of selectively coupling the drive train  112  to the bent housing  116  and/or the rotating mandrel  202 . In an embodiment shown in  FIG. 3 , the shifting apparatus is a clutch  300 , or clutch works. Although the shifting apparatus is described as a clutch  300 , it should be appreciated that the shifting apparatus  118  may be any suitable apparatus for selectively engaging the bent housing  116  including, but not limited to slips, a splined member, and the like. The shifting apparatus  118  may be actuated by any suitable device including but not limited to a mechanical actuator, a hydraulic actuator, a pneumatic actuator, a linear actuator, a solenoid, an electric actuator and the like. 
       FIG. 4  shows a cross sectional view of the BHA  108  near the position indicator  120  according to one embodiment described herein. The upsets  206  are shown as a plurality of nodes coupled to, or integral with the rotating mandrel  202 . The nodes engage a portion of the sensor  208  coupled to the stationary mandrel  200  as the rotating mandrel  202  rotates relative to the stationary mandrel  200 . As shown in  FIG. 4 , the nodes engage a piston  400 . When the nodes engage the piston  400  the piston  400  may move in a piston housing  405 . The movement of the piston may send a signal which indicates the position of the node. The position of the node may be communicated to the controller  122 , and/or the operator, via the communication signal  124 . 
       FIG. 5  shows a cross sectional top view of the rotating mandrel  200  at the location of the upsets  206 , in one embodiment. The upsets  206 , or nodes, shown in  FIG. 5  are equally sized with the exception of a test node  500 . As the sensor  208  engages each of the upsets  206  the signal is sent to the operator, or the controller  122  indicating the presence of the node. When the test node  500  engages sensor  208 , a larger signal may be sent to the controller  122 , and/or operator indicating the sensor  208  has engaged the test node  500 . The test node  500  may indicate to the operator a known position of the rotating mandrel  202  and/or the bent housing  116 . For example, the test node  500  may be aligned with the direction of the bent housing  116 . Thus, when the test node  500  engages the sensor  208 , the operator and/or the controller  122  knows that the direction of the bent housing  116  was in line with the sensor  208 . The test node  500  may have any form so long as it sends a signal that does not conform with the other upsets  206 . For example, the test node  500  may be smaller than the upsets  206 . The controller, and/or operator, may use the test node  500  as a basis for orienting the bent housing  116 . As the rotating mandrel  202  continues to rotate past the sensor, each of the upsets encountered represent a known degree of rotation. Thus, the controller  122 , and/or operator may count each upset as it passes in order to determine the rotational position of the rotational mandrel  202  and the bent housing  116 . Although the upsets  206  are shown as extending radially beyond rotating mandrel  202  it should be appreciated that the upsets may take any shape capable of being detected by the sensor. For example the upsets may be an indent in the rotational mandrel, a boss, a bump, any combination thereof, and the like. 
     In another example, each of the upsets may have a variant size. Thus, each of the upsets  206  would indicate a specific rotational position of the rotating mandrel  202  and the bent housing  116 . The controller  122  and/or operator would know the exact rotational location of the bent sub  116  from the signal received from the specifically sized upset  206 . 
     The sensor  208 , as shown in  FIGS. 4-6 , includes the piston  400  and piston housing  405 , a transmission path  402 , and a gauge  600 . The piston  400  may have a piston surface  404 , an engagement surface  406  and one or more seals  408 . The piston surface  404  may be configured to apply a force to the piston  400  in response to fluid pressure on the piston surface  404 . The force caused by the fluid pressure may bias the piston  400  toward the rotating mandrel  202 . The biasing of the piston  400  toward the rotating mandrel  202  may cause the engagement surface  406  to engage the outer surface of the rotating mandrel  202  and the upsets  206  as the rotating mandrel  202  rotates. Although the piston  400  is described as being biased toward the rotating mandrel  202  with the fluid pressure, it should be appreciated that the piston may be biased using any biasing member including but not limited to, a coiled spring, a leaf spring, an elastic member, and the like. The one or more seals  408  may be any seal so long as they substantially prevent fluid from flowing past the piston trough the piston housing  405 . 
     The transmission path  402  may be any communication path for sending information, including a fluid signal, a fluid path, an electric signal, an optical signal and the like. In one embodiment, the transmission path is a fluid path which may be configured to send a signal to the gauge  600 , shown in  FIG. 6 . The transmission path  402  may be filled with hydraulic, or pneumatic fluid, through which the signal is sent in response to the movement of the piston  400 . As the piston  400  moves in response to engaging the one of the upsets  206 , the fluid pressure in the transmission path  402  will change as a result. For example, if the upsets  206  are configured to move the piston  400  against the biasing force, the fluid pressure in the transmission path  402  will increase in the transmission path  402 . If the upsets  206  are configured to move the piston  400  with the biasing force, the fluid pressure in the transmission path  402  will decrease in the transmission path  402 . The increase, or decrease, in fluid pressure may be configured to travel as a signal through the entire transmission path  402 . 
     The transmission path  402  may include one or more dampers  602 , as shown in  FIGS. 6 and 7 . The dampers  602  may include a damping piston  604  and a biasing member  606 . The biasing member  606  may bias the damping piston toward the transmission path  402 , thereby applying a pressure on the fluid path  402 . The dampers  602  may allow the pressure in the fluid path to adjust to volume, and/or pressure, changes in the fluid as a result of temperature change in the transmission path  402 . Thus, as the temperature in the wellbore increases as the BHA  108  travels downhole, the volume of the fluid in the transmission path  402  may increase. The dampers  602  will adjust to the increase in volume. Further, if the fluid in the transmission path  402  is hydraulic fluid, the dampers  602  may absorb some of the pressure change in the fluid as a result of changes in temperature and/or movement of the piston  400 . 
     The transmission path  402  may further include one or more mandrel interconnectors  608 , as shown in  FIGS. 6 and 8 . The mandrel interconnector  608  allows the transmission path  402  to pass from a first mandrel to a second mandrel. To this effect the mandrel interconnector  608  may include one or more seals. Further, if the first or second mandrel is a rotatable mandrel relative to the mandrel it is connected to there may be a flow path that allows for continuous fluid communication between the first mandrel and the second mandrel through the interconnector  608 . Further, it should be appreciated that any signal may be sent across the interconnector  608 . For example, the interconnector  608  may allow for an electrical signal to be sent through the interconnector  608 . 
     In an embodiment, the transmission path  402  may couple to the gauge  600 , as shown in  FIG. 6 . The gauge  600  may be any gauge capable of detecting pressure changes in the transmission path  402 . Detecting the changes in pressure of the transmission path  402  allows the gauge to detect when the piston  400  engages the upsets  206 . The detection of the upsets  206  may be converted into a signal by the gauge  600  that may be relayed to the controller  122 , and/or the operator. The gauge  600 , as shown in  FIG. 6 , is a gauge transducer. The gauge  600  sends, or transmits, the signal to the controller  122 , and/or operator, via the communication path  124 . Thus, as the bent housing  116  rotates relative to the BHA  108 , the gauge  600  detects each of the upsets  206 . The detection of each of the upsets  206  represents a rotational position of the bent housing  116 . The detected position of the bent housing  116  may be sent to the controller  122 . Although the gauge is described as a gauge transducer, it should be appreciated that the gauge may be any device capable of sending a signal to the controller, including an electric sensor. 
     The signal  124  sent to the controller  122  may be any signal capable of transferring information from the BHA  108  to the surface. In an embodiment, the signal  124  is sent via a wired connection to the surface. The signal  124  may be sent outside of the conveyance  106 , inside the conveyance  106 , in a wall of the conveyance  106  and any combination thereof. Although the signal  124  is described as a wired connection to the surface, it should be appreciated that the signal may be any signal capable of communicating the detection of the upsets  206  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, and the like. 
     There may be a lock system (not shown) configured to lock, or fix the bent housing  116  in a rotational position when the drive train  112  is not rotating the bent housing  116 . The lock system may be any suitable method of securing the rotational position of the bent housing  116  including, but not limited to, a castle system, a ratchet, a pin, a clamp, the shifting apparatus and the like. 
     Although the sensor is describe as the piston  400  connected to the gauge  600  via the transmission path  402 , it should be appreciated that the sensor, and/or position indicator  120  may be any suitable detection device including, but not limited to, an optical sensor, a strain gauge, a hall effect sensor and the like. 
     In operation, the BHA  108  is connected to the end of the conveyance  106 . In one embodiment, the conveyance  106  is coiled tubing. The BHA  108  is lowered into the wellbore  100  until the BHA  108  reaches the bottom of the wellbore  100 . The operator, and/or the controller  122  may then start the motor  110  in order to begin drilling the wellbore  100  deeper. In one embodiment, the operator starts the motor  110  by pumping fluids through the conveyance  106 . The fluids may serve a dual purpose of powering the motor  110  and washing away drilling cuttings located near the drill bit  114 . The motor  110  rotates the drive train  112  of the BHA  108 . The drive train  112  may selectively transfer rotation to the drill bit  114  and/or the bent housing  116 . The drive train may include one or more intermediate components configured to absorb non-rotational forces, and/or transfer rotation in a non-linear manner. If the operator wants to drill the wellbore  100  in a substantially straight line, the operator may rotate both the bent housing  116  and the drill bit  114 . To rotate the bent housing  116 , the shifting apparatus  118  is actuated thereby coupling the drive train  112  to the rotating mandrel  202 . The rotating mandrel  202  may couple to the bent housing  116  thereby rotating the bent housing  116 . The rotational speed of the drive train  112  may be too great for effectively rotating the bent housing  116 . The rotation speed may be reduced in the rotating mandrel  202 , and/or bent housing  116  by using one or more speed reducers, or gears  210 . Thus, a substantially straight borehole may be drilled by continuously rotating the bent housing  116  and the drill bit  114  at the same time. The controller and/or operator may continue drilling in this manner until it is desired to deviate, or direct the wellbore  100  in another direction. 
     In an additional embodiment, the operator may drill in a straight line by indexing the direction of the bent housing  116  during drilling. Thus, the operator would drill with the bent housing  116  in a fixed position. Then after drilling for a distance, the operator may rotate the bent housing slightly and continue drilling with the bent housing in a fixed position. The operator may repeat this procedure during the entire drilling operation, thereby forming a wellbore which travels in substantially one direction. 
     In order to directional drill the bent housing  116  should be stationary and angled toward the desired drilling direction. The controller  122 , and/or operator, may fix the bent housing  116  in a desired direction by using the position indicator  120  to determine the rotational position of the bent housing. As the bent housing  116  rotates, the nodes, or upsets  206 , on the rotating mandrel  202  engage the piston  400 . As the piston  400  moves in response to engaging the nodes, a pressure change is created in the transmission path  402 . The pressure change in the transmission path may be sent to the gauge  600 . The gauge  600  converts the pressure changes in the transmission path  402  into a signal which may be sent to the controller  122 , and/or operator. Thus, the signal represents the rotational position of the bent housing  116  as each of the nodes pass the piston  400 . The signal may be constantly sent to the controller or upon request. Using the signal, the controller  122 , and/or operator, may monitor the rotational position of the bent housing  116  as it rotates downhole. Thus, operator may disengage the shifting apparatus  118  from the rotational mandrel  202 , and/or the bent housing  116  when the signal corresponds to the desired drilling direction. Disengaging the shifting apparatus  118  from the rotating mandrel  202 , and/or the bent housing  116 , will disengage the drive train  112 , and therefore the rotation, from the bent housing  116 . With the bent housing  116  in the desired drilling direction, the operator and/or controller  122  may then continue the directional drilling operation. The drive train  112  rotates the drill bit  114  while the conveyance  106  continues to push the BHA  108  downhole thereby extending the wellbore  100 . The rotationally fixed bent housing  116  directs the wellbore in the direction the operator want the wellbore  100  to be drilled. Upon completing the bend in the wellbore  100 , the operator may continue drilling in a substantially straight line by reengaging the rotational mandrel  202  with the drive train  112 . The operator and/or controller  122  may use the position indicator  120  to direct the wellbore  100  in any desired direction without removing the BHA  108  from the wellbore  100 . 
     Although the BHA  108  is described above having a position indicator  120  for detecting the rotational position of a bent housing  116 , it should be appreciated that the position indicator  120  may be used to rotationally position any downhole tool. For example, the position indicator  120  may be used rotationally position the face of a whipstock, not shown, in a desired direction before a lateral is drilled. Further, the position indicator  120  and portions of the BHA  108  may be used with any suitable downhole operation, or downhole tool including, but not limited to a fishing tool, a hammer, a whipstock, a rotary steerable, and the like. 
       FIG. 9  depicts a geometric representation of the location of upsets detectable by a sensor on the downhole tool. 
     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.