Patent Publication Number: US-9850708-B2

Title: Drill string sub

Description:
BACKGROUND 
     Embodiments of the present disclosure relate generally to the field of drilling and processing of wells. More particularly, present embodiments relate to a system and method for determining the presence of and controlling motion (e.g., rotation) of a drill string in a drilling rig. 
     During a drilling process, the drill string may be supported and hoisted about the drilling rig by a hoisting system for eventual positioning down hole in a well (e.g., a wellbore). As the drill string is lowered into the well, a drive system may rotate the drill string to facilitate drilling. Further, at the end of the drill string, a bottom hole assembly (BHA) and a drill bit of the BHA may press into the ground to drill the wellbore. Maintaining a desired weight on bit (WOB), which is a desired amount of weight on the drill bit, may enhance the drilling processes. In particular, maintaining a high rate of penetration without damaging the BHA is desired. 
     In many drilling processes, the wellbore may include vertical and directional segments. For example, the drill string may initially drill a first vertical segment to a desired depth by utilizing the top drive, the weight of the drill string, and/or a mud motor. In order to drill a directional section or segment, the top drive may be stopped from exerting a force on the drill string, but may be used to hold a position of the drill string. The mud motor of the drill bit may then be adjusted to drill a directional segment at a desired angle, e.g., a horizontal segment. Unfortunately, once the drill string is in the directional (e.g., horizontal) segment in particular, and in the vertical segment to an extent, the drill string may be susceptible to resting against or contacting sides of the wellbore, which may increase a frictional force against the drill string, causing the drill string to stick against the sides of the wellbore. As more weight is added to the drill string by lowering a drawworks of the drilling rig, the drill string may break free from the sides of the wellbore and fall into and contact an end of the wellbore, which may overload the drill bit proximate the end of the wellbore. 
     Thus, drilling the directional (e.g., horizontal) segment in particular, and the vertical segment to an extent, may be enhanced by inducing a rocking motion (e.g, alternating clockwise and counterclockwise rotations about a longitudinal axis of the drill string) in the drill string to reduce frictional forces between the sides of the wellbore and the drill string. The rocking motion may be induced by exerting a torque (e.g., rotation) at a top of the drill string via a top drive disposed on the drilling rig proximate the top of the drill string. Providing torque to the drill string in alternating clockwise and counterclockwise directions about the longitudinal axis, for a certain amount of turns (e.g., a certain amount of 360° rotations) in each direction, may decrease frictional forces between the drill string and the sides of the wellbore, particularly proximate directional (e.g., horizontal) segments, which may reduce a likelihood that the drill string slips. 
     It should be noted that the amount of rotation applied to the drill string at the top drive generally does not propagate all the way down the drill string. In other words, elasticity of the drill string, among other factors, causes the rotation to “dissipate” as rotation travels down the drill string. Thus, determining how far down the well bore the drill string actually rotates may not be trivial. Further, providing too many turns to the drill string via the top drive may result in adverse effects. For example, providing too many turns to the drill string may result in an undesired altered drilling angle. Conversely, applying too few turns to the drill string may result in inefficient drilling and may increase susceptibility of the drill string to frictionally engage with the wellbore and, ultimately, slip, as previously described. Thus, traditionally, operators have (a) determined a desired location (known as a “neutral point”) on the drill string to which rotation of the drill string is intended to reach, and (b) employed engineering calculations to determine how many turns must be applied via the top drive to reach the neutral point. Unfortunately, such engineering calculations may be estimates, which, when applied, may result in an undesired altered drilling angle and/or slippage of the drill string. Accordingly, it is now recognized that there is a need for improved detection and maintenance of motion (e.g., rotation) of the drill string with respect to WOB. 
     BRIEF DESCRIPTION 
     In a first embodiment, a drilling system includes a drill string with two or more drill pipes (e.g., tubular), a drive system configured to rotate the drill string, and a neutral point sub disposed proximate a neutral point of the drill string, where the neutral point sub is configured to detect motion of the drill string. 
     In a second embodiment, a method of controlling rotation of a drill string includes detecting rotation of the drill string at a neutral point of the drill string in a first circumferential direction about a longitudinal axis of the drill string via a neutral point sub disposed on the drill string. The method also includes instructing a drive system, via a controller, to stop rotating the drill string in the first circumferential direction after detecting the rotation of the drill string at the neutral point. The method also includes instructing the drive system, via the controller, to start rotating the drill string in a second circumferential direction substantially opposite to the first circumferential direction after stopping the rotation of the drill string in the first circumferential direction. 
     In a third embodiment, a method of drilling a well includes instructing a top drive, via a controller, to apply a torque to a drill string in a first circumferential direction relative to a longitudinal axis extending through the drill string. The method includes detecting rotation of the drill string at a neutral point of the drill string below the top drive via a neutral point sub, and sending a pulse, via the neutral point sub, to a controller to alert the controller that the neutral point sub has detected rotation of the drill string at the natural point. The method also includes processing the pulse via the controller and instructing the top drove, via the controller, to apply torque to the drill string in a second circumferential direction relative to the longitudinal direction, where the second circumferential direction is substantially opposite the first circumferential direction. 
    
    
     
       DRAWINGS 
       These and other features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein: 
         FIG. 1  is a schematic representation of a drilling rig with a neutral point sub in accordance with present embodiments; 
         FIG. 2  is a schematic representation of a drilling rig with a neutral point sub in accordance with present embodiments; and 
         FIG. 3  is a process flow diagram of a method of detecting and controlling motion of a drill string with a neutral point sub in accordance with present embodiments. 
     
    
    
     DETAILED DESCRIPTION 
     Various drilling techniques can be utilized in accordance with embodiments of the present disclosure. In conventional oil and gas operations, a well is typically drilled to a desired depth with a drill string, which includes drill pipe (e.g., tubular, drill collars, etc.) and a drilling bottom hole assembly (BHA) that includes a drill bit. During a drilling process, the drill string may be supported and hoisted about a drilling rig by a hoisting system for eventual positioning down hole in a well. As the drill string is lowered into the well, a drive system may rotate the drill string to facilitate drilling. The drive system typically includes a rotational feature (e.g., a drive shaft or quill) that transfers torque to the drill string. For example, a top drive may generate torque and utilize a quill to transfer the torque to the drill string. The torque may apply rotation to the drill string, such that the drill string rotates through frictional forces between the drill string and sides of the wellbore. By reducing frictional forces between the drill string and the sides of the wellbore, slippage of the drill string may be reduced or eliminated. 
     As described above, the drive system may operate to rotate the drill string about a longitudinal axis of the drill string by the drive system. For example, the drive system may rotate the drill string in a “rocking motion,” or, in other words, in alternating clockwise and counterclockwise directions about a longitudinal axis extending through the drill string. The drill string may be rotated a certain number of turns (e.g., 360° turns) or a certain number of degrees in the clockwise direction and then a certain number of turns or degrees in the counterclockwise direction. In some embodiments, the number of turns or degrees in the clockwise direction may be substantially the same number of turns or degrees in the counterclockwise direction. 
     In general, the drilling process may be made more effective by ensuring that the drill string does not rotate beyond a neutral point (a point along the drill string where no rotation is desired) of the drill string. If the drill string rotates beyond the neutral point (e.g., as the rotations propogate downward from the top drive above the neutral point), adverse effects may occur. For example, rotating the drill string beyond the neutral point may result in an undesired change in the drilling angle. Alternatively, if rotations of the drill string from above the neutral point do not propagate through the drill string up to the neutral point, the drill string may frictionally engage with sides of the well bore and, eventually, may “slip” from the frictional engagement, causing the drill string to fall down the wellbore and overload the drill bit. 
     Thus, in accordance with the present disclosure, a neutral point sub may be placed at the neutral point of the drill string for detecting motion (e.g., rotation) in the drill string. The neutral point sub may be a threaded connector configured to fit between two pieces of pipe (e.g., two sections of tubular or drill collars) of the drill string. For example, the neutral point may be pre-determined based on a total length of the drill string, among other factors, and the neutral point sub may be placed proximate the neutral point of the drill string between two pipes of the drill string. Additionally, subs may be located between every connection of pipes (or between more than one connection of pipes) of the drill string and may be configured to operate as the neutral point sub when activated or in a similar manner as the neutral point sub at any given time, and the appropriate sub may be activated as the neutral point sub depending on the determined neutral point location at any given time during the drilling process. 
     The neutral point sub in the presently contemplated embodiment is configured to detect rotation of the pipe (e.g., drill string) coupled to the neutral point. Further, the neutral point sub is configured to provide feedback of detected rotation, such that an appropriate amount of rotation may be applied to the drill string in the rocking motion by the top drive. Accordingly, the neutral point sub is configured to enable more efficient drilling (e.g., by allowing the drill string to rotate just up to or slightly beyond the neutral point, as described above) and to enable more accurate drilling (e.g., by ensuring the drill string does not rotate through or excessively beyond the neutral point, as described above). 
     Turning now to the figures,  FIG. 1  is a schematic representation of a drilling rig  10  in the process of drilling a well in accordance with present techniques. The drilling rig  10  features an elevated rig floor  12  and a derrick  14  extending above the rig floor  12 . A supply reel  16  supplies drilling line  18  to a crown block  20  and traveling block  22  configured to hoist various types of drilling equipment above the rig floor  12 . The drilling line  18  is secured to a deadline tiedown anchor  24 , and a drawworks  26  regulates the amount of drilling line  18  in use and, consequently, the height of the traveling block  22  at a given moment. Below the rig floor  12 , a drill string  28  extends downward into a wellbore  30  and is held stationary with respect to the rig floor  12  by a rotary table  32  and slips  34 . A portion of the drill string  28  extends above the rig floor  12 , forming a stump  36  to which another length of tubular  38  may be added. The drill string  28  may include multiple sections of threaded tubular  38  (e.g., pipes, collars, etc.) that are threadably coupled together. It should be noted that present embodiments may be utilized with drill pipe, casing, or other types of tubular. Further, it should be noted that saver subs may be disposed between any two threaded tubular  38  of the drill string  28 . 
     During operation, a top drive  40 , hoisted by the traveling block  22 , may engage and position the tubular  38  above the wellbore  30 . The top drive  40  may then lower the coupled tubular  38  into engagement with the stump  36  and rotate the tubular  38  such that it connects with the stump  36  and becomes part of the drill string  28 . Specifically, the top drive  40  includes a quill  42  used to transfer torque to (e.g., turn) the tubular  38  or other drilling equipment. After setting or landing the drill string  28  in place such that the male threads of one section (e.g., one or more joints) of the tubular  38  and the female threads of another section of the tubular  38  are engaged, the two sections of the tubular  38  may be joined by rotating one section relative to the other section (e.g., in a clockwise direction) such that the threaded portions tighten together. In some embodiments, a sub  44  (e.g., a saver sub) may be placed between the two tubulars  38  for coupling the tubular  38 . Thus, the two sections of tubular  38  may be threadably joined, together or via a sub  44  between the sections of tubular  38 . 
     While  FIG. 1  illustrates the drilling rig  10  in the process of adding the tubular  38  to the drill string  26 , as would be expected, the drilling rig  10  also functions to drill the wellbore  30 . Indeed, the drilling rig  10  includes a drilling control system  50  in accordance with the present disclosure. The control system  50  may coordinate with certain aspects of the drilling rig  10  to perform certain drilling techniques. For example, the drilling control system  50  may control and coordinate rotation of the drill string  28  via the top drive  40  and supply of drilling mud to the wellbore  30  via a pumping system  52 . The pumping system  52  includes a pump or pumps  54  and conduit or tubing  56 . The pumps  54  are configured to pump drilling fluid downhole via the tubing  56 , which communicatively couples the pumps  52  to the wellbore  30 . In the illustrated embodiment, the pumps  54  and tubing  56  are configured to deliver drilling mud to the wellbore  30  via the top drive  40 . Specifically, the pumps  54  deliver the drilling mud to the top drive  40  via the tubing  56 , the top drive  40  delivers the drilling mud into the drill string  28  via a passage through the quill  42 , and the drill string  28  delivers the drilling mud to the wellbore  30  when properly engaged in the wellbore  30 . 
     The control system  50  may also control rotation of the drill string  28  by instructing the top drive  40  to turn the drill string  28  about a longitudinal axis  58  extending through the drill string  28 . For example, the control system  50  may instruct the top drive  40  to turn the drill string  28  a certain number of 360° turns in a circumferential direction  57  about the longitudinal axis  58  in the clockwise direction and then a certain number of 360° turns in the circumferential direction  57  about the longitudinal axis  58  in the counterclockwise direction. In some embodiments, the control system  50  may instruct clockwise and counterclockwise turns of less than 360° (e.g., a fraction of one 360° turn). 
     The control system  50  may interface with a neutral point sub  60  disposed between two sections of tubular  38  at a neutral point  62  of the drill string  28 . It should be noted that the neutral point  62  may actually be a region that extends for some distance along the drill string  28  and that the neutral point sub  60  may be disposed within that region. The neutral point  62  may be a pre-calculated region where, to enhance the drilling process, the drill string  28  should not rotate. 
     The neutral point sub  60 , in the illustrated embodiment, is disposed at the neutral point  62  for detecting rotations of the drill string  28  proximate the neutral point  62 . Rotations may be applied to the drill string  28  via the top drive  40  in, for example, the clockwise direction about the longitudinal axis  58  of the drill string  28 . However, the rotations may dissipate along the drill string  28  into the wellbore  30  as the drill string  28  extends downwardly (e.g., in longitudinal direction  63 ) along the longitudinal axis  58 , due to, e.g., elasticity of the drill string  28 . Accordingly, the drill string  28  may be rotated about the longitudinal axis  58  for a certain number of turns until the neutral point sub  60  first detects the rotation of the drill string  28 . The neutral point sub  60  may, upon detection of rotation from the drill string  28  proximate the neutral point sub  60 , provide feedback through a communication path  64  to the control system  50 . For example, upon detection of rotation, the neutral point sub  60  may send an electric pulse through the communication path  64  to a port  66  disposed on or adjacent to the rotary table  32 , where the port  66  may be electrically coupled to the control system  50 . Alternatively, the neutral point sub  60 , upon detection of rotation of the drill string  28  proximate the neutral point sub  60 , may trigger a mud pulse through the communication path  64 , which is detected by the control system  50 , such that the control system  50  may stop rotation of the drill string  28  and rotate the drill string  28  in the other direction. 
     The control system  50  in the presently contemplated embodiment (e.g., as illustrated in  FIG. 1 ) may receive the pulse from the neutral point sub  60  and instruct the top drive  40  to stop drill string  28  rotation (e.g., in the clockwise direction) and begin rotation in the other direction (e.g., in the counterclockwise direction) about the longitudinal axis  58  extending through the drill string  28 . The process may be repeated for both the clockwise or counterclockwise direction. Accordingly, the neutral point sub  60  located at the neutral point  62  ensures that the drill string  28  rotates up to, but not beyond, the neutral point  62 . Thus, the neutral point sub  60 , together with the control system  50  and the top drive  40 , enables efficient drilling by minimizing stick/slip between the drill string  28  and the sides of the wellbore  30 , while maintaining an appropriate (e.g., desired) drilling angle. 
       FIG. 2  is a schematic representation of the drilling rig  10  during a directional drilling operation. In the illustrated embodiment, the top drive  40  is being utilized to transfer rotary motion to the drill string  28  via the quill  42 , as indicated by arrow  68 . In other embodiments, different drive systems (e.g., a rotary table, coiled tubing system, downhole motor) may be utilized to rotate the drill string  28  (or vibrate the drill string  28 ). Where appropriate, such drive systems may be used in place of the top drive  40 . It should be noted that the illustrations of  FIGS. 1 and 2  are intentionally simplified to focus on particular features of the drilling rig  10 . Many other components and tools may be employed during the various periods of formation and preparation of the well. Similarly, as will be appreciated by those skilled in the art, the orientation and environment of the well may vary widely depending upon the location and situation of the formations of interest. For example, the well, in practice, may include one or more deviations, including angled and horizontal runs. Similarly, while shown as a surface (land-based) operation, the well may be formed in water of various depths, in which case the topside equipment may include an anchored or floating platform. 
     As will be discussed below, the drill string  28  may be rotated based on instructions from the control system  50 , which may include automation and control features and algorithms for addressing static friction issues, such as stick slip, based on measurement data and equipment. For example, the control system  50  may control the rotation of the drill string  28  based on velocity profiles or vibration profiles generated in response to one or more variables including pipe size, size of hole, tortuosity, number of bends, type of bit, rotations per minute, mud flow, torque, bend setting, inclination, length of drill string, horizontal component of drill string, vertical component of drill string, mass of drill string, manual input, WOB, azimuth, tool face positioning, downhole temperature, downhole pressure, or the like. Further, the control system  50  may control the rotation of the drill string  28  based on feedback from the neutral point sub  60  described above and further described below. The control system  50  may include one or more automation controllers (e.g., programmable logic controllers (PLC)) with one or more processors and memories that cooperate to store received data and implement programmed functionality based on the data and algorithms. The control system  50  may communicate (e.g., via wireless communications, via dedicated wiring, or other communication systems) with various features of the drilling rig  10  or drill string  28  (e.g., the neutral point sub  60 ), not limited to the pumping system  52 , the top drive  40 , the drawworks  26 , and downhole features (e.g., a bottom hole assembly  70  (BHA)). 
     In the illustrated embodiment, the drill string  28  includes the BHA  70  coupled to the bottom of the drill string  28 . The BHA  70  includes a drill bit  72  that is configured for directional drilling. The drill bit  72  may include a bent axis motor-bit assembly or the like that is configured to guide the drill string  28  in a particular direction. Straight line drilling may be achieved by rotating the drill string  28  during drilling, and directional drilling may be achieved by adjusting the drill bit  72  such that it guides the drilling process without rotating the drill string  28 . The BHA  70  includes sensors  74  configured to provide data (e.g., via pressure pulse encoding through drilling fluid, acoustic encoding through drill pipe, electromagnetic transmissions) to the control system  50  to facilitate control of this process, including determining whether to rotate the drill string  26  via the top drive  40  and/or pump drilling mud via the pumping system  52 . For example, the sensors  74  may work in conjunction with or separately from the neutral point sub  60  to communicate with the control system  50  for controlling certain aspects of the drilling process, including pumping of mud via the pumping system  52  and rotation of the drill string  28  via the top drive  40 . Thus, the control system  50  may instruct the top drive  40  to rotate the drill string  28  a certain amount of times in the clockwise and/or counterclockwise direction such that adverse force coupling does not occur or is reduced between forces exerted by the drill bit  72  on the drill string  28  and forces exerted by the top drive  40  on the drill string  28 . Further, the pumping system  52  may supply drilling mud to a mud motor  75  (or drilling motor) of the BHA  70 . The mud motor  75 , which may represent multiple such motors, may include a progressive cavity positive displacement pump arranged to generate motion and to power the drill bit  72 . The sensors  74 , which may represent multiple different sensors, may detect upstream and downstream pressures relative to the mud motor  75  and provide related torque data (e.g., via the control system  50 ). It should be noted that, in some embodiments, aspects of the control system  50  may be positioned downhole (e.g., with the BHA  70 ) or integrated with other features (e.g., the top drive  40 ). 
     As illustrated in  FIG. 2 , the top drive  40  is being utilized to rotate the drill string  28 . As noted above, the drill string  28  may frictionally engage with sides of the wellbore  30 . Further, the drill string  28  and threaded connections between separate pipes (e.g., tubulars) of the drill string  28  may experience torsional loading from the top drive  40  and the drill bit  72 , and axial loading from the weight of the drill string  28  (e.g., tubular of the drill string  28 ) and other components of the drilling rig  10 . To reduce friction between the drill string  28  and sides of the wellbore  30 , the top drive  40  may rotate the drill string  28  up to the neutral point  62 . In doing so, susceptibility to slippage may be reduced or eliminated. The neutral point sub  60  may be included in accordance with the discussion above for ensuring that the top drive  40  does not rotate the drill string  28  at a point beyond the neutral point  62 , as measured along the longitudinal axis  58  of the drill string  28  from the top drive  40 , or top of the drill string  28 . Thus, the desired drilling angle may be maintained. 
     In the illustrated embodiment, other subs  44  are included at various points along the drill string  28  between sections of tubular  38  of the drill string  28 . These subs  44  may be capable of operating in the same way as the neutral point sub  60 . In other words, the subs  44  may be capable of detecting rotation of the drill string  28  about the longitudinal axis  58  of the drill string  28  and may also be capable of communicating information related to that rotation to the control system  50 . In some embodiments, the subs  44  may be identical or very similar to the neutral point sub  60 . In this way, in the event the neutral point  62  location changes over time, another one of the subs  44  may be activated to become the neutral point sub  60  and the previous neutral point sub  60  may be deactivated to become another one of the subs  44 . The neutral point sub  60  may be automatically determined from the group of subs  44  based on a length  80  of the drill string  28 , as shown in the illustrated embodiment, among a number of other factors. Alternatively, the neutral point sub  60  may be selected from the group of subs  44  manually by an operator. 
     Including multiple subs  44  which may operate similarly as the neutral point sub  60  may offer certain other advantages as well. For example, in some embodiments, more than one of the subs  44  may be used to detect rotation of the drill string  28  over time. Each successive sub  44  may communicate with the control system  50  when it detects rotation of the drill string  28  such that the propagation of the rotation of the drill string  28  may be tracked over time. Accordingly, operators or the control system  50  may determine certain regions of the drill string  28  through which rotation propagation takes more time than other regions of the drill string  28 . Such information may be processed by the control system  50  or used by an operator to enable a determination of locations or regions along the drill string  28  that experience more friction via engagement with sides of the wellbore  30  relative to other locations along the drill string  28 . 
     Additionally, operators or the control system  50  may determine estimates of when the neutral point sub  60  disposed at the neutral point  62  will detect rotation of the drill string  28  based on feedback received via the subs  44  above the neutral point sub  60 . For example, operators or the control system  50  may calculate a linear relationship, or some other mathematical function, between a number of turns applied to the drill string  28  by the drive system (e.g., the top drive  40 ) and a distance along the drill string  28  from the top drive  40  to the sub(s)  44  detecting rotation of the drill string  28 . In other words, the linear relationship or mathematical function may compare the rotation propogation distance through the drill string  28  with the number of turns applied to the drill string  28  via the top drive  40  to reach said rotation propagation distance in order to determine an estimate of when the rotation will reach or approach the neutral point  62 . Further, some of the subs  44  may be disposed at a point beyond the neutral point  62  (e.g., as measured from the top drive  40  down), such that the subs  44  may detect how far the drill string  28  has rotated beyond the neutral point  62  in the event the neutral point sub  60  malfunctions or some other component involved in the control system  50  malfunctions, or in the event a change in drilling angle is actually desired. 
     Turning now to  FIG. 3 , an embodiment of a method  90  for detecting and controlling rotation of the drill string  28  is shown in a process flow diagram. The method includes coupling the neutral point sub  60  between two sections of tubular  38  on the drill string  28  (block  92 ). For example, the neutral point sub  60  may be threadably engaged on one end to a first section of tubular  38  and on the other end to a second section of tubular  38 . The method  90  also includes positioning the neutral point sub  60  at the neutral point  62  of the drill string  28  (block  94 ). This step may be done in conjunction with the step disclosed in block  92 . For example, the neutral point sub  60  may be threadably engaged between two sections of tubular  38  that are expected to be proximate the neutral point  62 , such that the neutral point sub  60  is disposed at the neutral point  62  of the drill string  28 . The method  90  also includes rotating the drill string  28  at the top of the drill string  28  via the top drive  40  or drive system in a first direction (block  96 ). For example, the top drive  40  may rotate the drill string  28  clockwise such that the rotations propagate through the drill string  28  downward. The method  90  further includes detecting rotation of the drill string  28  via the neutral point sub  60  at the neutral point  62  (block  98 ). For example, the rotation of the drill string  28  propagates through the drill string  28  from the top drive  40 , but may dissipate over time due to elasticity of the drill string  28  and/or due to some frictional engagement of the drill string  28  with sides of the wellbore  30  or with mud flowing through the wellbore  30 . Accordingly, multiple turns of the drill string  28  in, for example, the clockwise direction may take place before the neutral point sub  60  first detects rotation of the drill string  28  at the neutral point  62 . The method  90  also includes communicating with the control system  50 , via the neutral point sub  60 , that rotation of the drill string  28  has occurred at the neutral point  62  (block  100 ). For example, the neutral point sub  60  may send an electric pulse or trigger a mud pulse for communicating with the control system  50 . The method  90  further includes stopping rotation of the drill string  28  in, for example, the first direction (e.g., the clockwise direction) and starting rotation of the drill string  28  in a second direction (e.g., the counterclockwise direction), via communication between the control system  50  and the drive system (e.g., top drive) (block  102 ). 
     While only certain features of the invention have been illustrated and described herein, many modifications and changes will occur to those skilled in the art. It is, therefore, to be understood that the appended claims are intended to cover all such modifications and changes as fall within the true spirit of the invention.