Patent Publication Number: US-8967266-B2

Title: Protection of casing lowside while milling casing exit

Description:
BACKGROUND 
     The present invention relates generally to milling a casing exit for a lateral borehole, and more particularly to systems and methods of protecting the lowside of the casing from wear while milling a casing exit for a lateral borehole. 
     Hydrocarbons can be produced through relatively complex wellbores traversing a subterranean formation. Some wellbores can include multilateral wellbores and/or sidetrack wellbores. Multilateral wellbores include one or more lateral wellbores extending from a parent (or main) wellbore. A sidetrack wellbore is a wellbore that is diverted from a first general direction to a second general direction. A sidetrack wellbore can include a main wellbore in a first general direction and a secondary wellbore diverted from the main wellbore in a second general direction. A multilateral wellbore can include one or more windows or casing exits to allow corresponding lateral wellbores to be formed. A sidetrack wellbore can also include a window or casing exit to allow the wellbore to be diverted to the second general direction. 
     The casing exit for either multilateral or sidetrack wellbores can be formed by positioning a casing joint and a whipstock in a casing string at a desired location in the main wellbore. The whipstock is used to deflect one or more mills laterally (or in an alternative orientation) relative to the casing string. The deflected mill(s) penetrates part of the casing joint to form the casing exit in the casing string. Drill bits can be subsequently inserted through the casing exit in order to cut the lateral or secondary wellbore. 
     While milling the casing exit, however, and during drilling of the subsequent lateral wellbore, significant wear can result on the lowside of the parent wellbore casing at or near the tip of the whipstock. The wear on the lowside of the wellbore is partly generated by the mills as a reactive force while cutting the exit in the casing or while trying to exit into the formation. Considerable wear is also generated by the drill pipe as it lays and rotates on the lowside of the parent wellbore at or near the tip of the whipstock. 
     In applications where the casing joint is made of softer casing materials, such as aluminum, the resulting wear can be significant. However, in instances where it is difficult for the casing exit to be milled, or there is a significant amount of time spent rotating the drill pipe at or near the tip of the whipstock, there can be significant wear even in steel casing (e.g., low alloy steel or 13Cr). This wear oftentimes results in the formation of a ledge on the inner surface of the casing which can cause problems with other bottom hole assemblies (BHAs) transversing the whipstock and entering the lateral borehole. The damaging wear can also create problems when trying to recover the whipstock, or it could create problems for subsequent operations below the milled casing exit after the whipstock has been recovered. 
     Previous attempts to prevent wear on the lowside of the wellbore have focused on reducing friction with the introduction of drilling fluids or drill pipe centralizers. The success of friction reducers in drilling fluids, however, can be costly and may be environmentally prohibited depending on geographic location. Moreover, the use of centralizers can vastly increase operational time as the centralizers must be added to each stand, thereby greatly increasing trip-in time. 
     SUMMARY OF THE INVENTION 
     The present invention relates generally to milling a casing exit for a lateral borehole, and more particularly to systems and methods of protecting the lowside of the casing from wear while milling a casing exit for a lateral borehole. 
     In some embodiments, a well system subassembly is disclosed. The subassembly may include a casing joint coupled to a casing string and defining a lowside therein. The casing joint may be made of a first material that is softer than that of the casing string. The subassembly may also include a whipstock assembly arranged within the casing joint and having a deflector surface operable to direct a drilling assembly into a sidewall of the casing joint to create a casing exit. The subassembly may further include a wear sleeve coupled to and extending axially from the whipstock assembly. The wear sleeve may define a throat that extends along an axial length of the wear sleeve and transitions into the deflector surface. The axial length of the wear sleeve may extend across a point of contact where the drilling assembly would otherwise engage the lowside of the casing joint, whereby the wear sleeve protects the lowside of the casing joint from wear caused by the drilling assembly. 
     In some embodiments, a method for protecting a lowside of a casing joint coupled to a casing string is disclosed. The method may include arranging within the casing joint a whipstock assembly having a deflector surface. The casing joint may be made of a material that is softer than that of the casing string. The method may also include arranging a wear sleeve axially adjacent and coupled to the whipstock assembly. The wear sleeve may define a throat that extends along an axial length of the wear sleeve and transitions into the deflector surface. The method may further include directing with the throat and deflector surface a drilling assembly into a sidewall of the casing joint to create a casing exit within the casing joint, and protecting with the wear sleeve the lowside of the casing joint from wear caused by the drilling assembly as the drilling assembly rotates. The axial length of the wear sleeve may extend across a point of contact where the drilling assembly would otherwise engage the lowside. 
     In some embodiments, another well system subassembly is disclosed. The subassembly may include a casing joint coupled to a casing string and defining a lowside therein. The casing joint may be made of a first material that is softer than that of the casing string. The subassembly may also include a whipstock assembly arranged within the casing joint and having an uphole tip and a deflector surface operable to direct a drilling assembly into a sidewall of the casing joint to create a casing exit. The subassembly may further include a wear bushing coupled to the drilling assembly and removable from the drilling assembly upon engaging a stationary wellbore object. The wear bushing may be configured to protect the lowside of the casing joint from damaging wear caused by the drill string assembly. 
     In some embodiments, another method for protecting a lowside of a casing joint coupled to a casing string is disclosed. The method may include arranging within the casing joint a whipstock assembly having an uphole tip and a deflector surface. The casing joint may be made of a material that is softer than that of the casing string. The method may also include advancing a drilling assembly within the casing string, the drilling assembly having a wear bushing coupled thereto, and disengaging the wear bushing from the drilling assembly by contacting the wear bushing with a stationary wellbore object. The method may further include directing with the deflector surface a drilling assembly into a sidewall of the casing joint to create a casing exit within the casing joint, and protecting with the wear bushing the lowside of the casing joint from wear caused by the drilling assembly as the drilling assembly rotates. The wear bushing may have an axial length that extends across a point of contact where the drilling assembly would otherwise engage the lowside. 
     The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure. 
         FIG. 1  illustrates an offshore oil and gas platform using an exemplary well system subassembly, according to one or more embodiments disclosed. 
         FIG. 2  illustrates an enlarged view of the well system subassembly of  FIG. 1 . 
         FIG. 3  illustrates a horizontal, cross-sectional view of the well system subassembly of  FIG. 1 , according to one or more embodiments disclosed. 
         FIG. 4  illustrates another horizontal, cross-sectional view of the well system subassembly of  FIG. 1  as a drilling assembly advances in the wellbore, according to one or more embodiments disclosed. 
         FIG. 5   a  illustrates another exemplary well system subassembly, according to one or more embodiments disclosed. 
         FIG. 5   b  illustrates an exemplary wear sleeve that can be used in conjunction with the well system subassembly of  FIG. 5   a , according to one or more embodiments. 
         FIG. 6  illustrates another exemplary well system subassembly, according to one or more embodiments disclosed. 
         FIG. 7  illustrates another exemplary well system subassembly, according to one or more embodiments disclosed. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention relates generally to milling a casing exit for a lateral borehole, and more particularly to systems and methods of protecting the lowside of the casing from wear while milling a casing exit for a lateral borehole. 
     The present invention provides systems and methods for reducing wear on casing joints where a casing exit or window is to be drilled into a casing string in order to form a lateral or a secondary borehole. The disclosed embodiments may be particularly advantageous for use with recently developed casing joints made from softer materials, such as aluminum. While softer casing joints allow the casing exit to be created or milled more easily, substantial wear on the casing joint often results. The disclosed embodiments may be configured to protect softer casing joints from this damaging wear. The present invention also reduces wear damage that may result on the casing string as caused by drill pipe contacting the inner wall of the casing string during drilling operations. The disclosed embodiments may prove especially advantageous in applications where long lateral legs are being drilled. 
     Referring to  FIG. 1 , illustrated is an offshore oil and gas platform  100  that uses an exemplary well system subassembly  128 , according to one or more embodiments of the disclosure. Even though  FIG. 1  depicts an offshore oil and gas platform  100 , it will be appreciated by those skilled in the art that the exemplary well system subassembly  128 , and its alternative embodiments disclosed herein, are equally well suited for use in or on other types of oil and gas rigs, such as land-based oil and gas rigs or any other location. The platform  100  may be a semi-submersible platform  102  centered over a submerged oil and gas formation  104  located below the sea floor  106 . A subsea conduit  108  extends from the deck  110  of the platform  102  to a wellhead installation  112  including one or more blowout preventers  114 . The platform  102  has a hoisting apparatus  116  and a derrick  118  for raising and lowering pipe strings, such as a drill string  120 . 
     As depicted, a main wellbore  122  has been drilled through the various earth strata, including the formation  104 . The terms “parent” and “main” wellbore are used herein to designate a wellbore from which another wellbore is drilled. It is to be noted, however, that a parent or main wellbore does not necessarily extend directly to the earth&#39;s surface, but could instead be a branch of yet another wellbore. A casing string  124  is at least partially cemented within the main wellbore  122 . The term “casing” is used herein to designate a tubular string used to line a wellbore. Casing may actually be of the type known to those skilled in the art as “liner” and may be made of any material, such as steel or composite material and may be segmented or continuous, such as coiled tubing. 
     The well system subassembly  128  may be installed in or otherwise form part of the casing string  124 . The subassembly  128  may include a casing joint  126  interconnected between elongate portions or lengths of the casing string  124 . The well system subassembly  128  may further include a whipstock assembly  130  positioned within the casing string  124  and/or the casing joint  126 . As will be described in greater detail below, the whipstock assembly  130  has a deflector surface that may be circumferentially oriented relative to the casing joint  126  such that a casing exit  132  can be milled, drilled, or otherwise formed in the casing joint  126  in a desired circumferential direction. As illustrated, the casing joint  126  is positioned at a desired intersection between the main wellbore  122  and a branch or lateral wellbore  134 . The terms “branch” and “lateral” wellbore are used herein to designate a wellbore which is drilled outwardly from its intersection with another wellbore, such as a parent or main wellbore. Moreover, a branch or lateral wellbore may have another branch or lateral wellbore drilled outwardly therefrom. 
     It will be appreciated by those skilled in the art that even though  FIG. 1  depicts a vertical section of the main wellbore  122 , the present disclosure is equally applicable for use in wellbores having other directional configurations including horizontal wellbores, deviated wellbores, slanted wellbores, combinations thereof, and the like. Moreover, use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole, and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well. 
     Referring now to  FIG. 2 , illustrated is an enlarged view of the exemplary well system subassembly  128 , according to one or more embodiments. The well system subassembly  128  may include various tools and tubular lengths interconnected in order to form a portion of the casing string  124 . For example, the subassembly  128  may include a latch coupling  202  having a profile and a plurality of circumferential alignment elements operable to receive a latch assembly therein and locate the latch assembly in a particular circumferential orientation. The subassembly  128  may also include an alignment bushing  204  having a longitudinal slot that is circumferentially referenced to the circumferential alignment elements of the latch coupling  202 . Positioned between the latch coupling  202  and the alignment bushing  204  is a casing alignment sub  206  that is used to ensure proper alignment of the latch coupling  202  relative to the alignment bushing  204 . It will be understood by those skilled in the art that the well system subassembly  128  may include a greater or lesser number of tools or a different set of tools that are operable to enable a determination of an offset angle between a circumferential reference element and a desired circumferential orientation of the casing exit  132 . 
     The casing joint  126  may be coupled to and otherwise interposing separate elongate segments of the casing string  124 . In some embodiments, each end of the casing joint  126  may be threaded to the corresponding elongate lengths of the casing string  124 . In other embodiments, however, the casing joint  126  may be coupled to the casing string  124  via couplings  207  made of, for example, steel or a steel alloy (e.g., low alloy steel). 
     The casing joint  126  may be made of a softer material or otherwise a material that provides easy milling or drilling therethrough. In one or more embodiments, the casing joint  126  is made of aluminum or an aluminum alloy. In other embodiments, however, the casing joint  126  may be made of various composite materials such as, but not limited to, fiberglass, carbon fiber, combinations thereof, or the like. The use of composite materials for the casing joint  126  may prove advantageous since cuttings resulting from the milling of the casing exit  132  through the casing joint  126  will not produce magnetically-charged debris that could magnetically-bind with downhole metal components or otherwise be difficult to circulate out of the well. 
     In some embodiments, the whipstock assembly  130  may be coupled to or otherwise engage the latch coupling  202  through the use of a latch assembly (not shown) having an outer profile that is operable to engage an inner profile and circumferential alignment elements of the latch coupling  202 . As illustrated, the whipstock assembly  130  may include a deflector surface  208  operable to direct a milling or drilling tool into the sidewall of the casing joint  126  to create the casing exit  132  therethrough. 
     Referring now to  FIG. 3 , illustrated is a horizontal view of a portion of the well system subassembly  128  before the casing exit  132  is formed or otherwise defined in the casing joint  126 , according to one or more embodiments. As illustrated, a milling or drilling assembly  304  may be coupled to the end of the drill string  120  and extended into the main wellbore  122  until locating the whipstock assembly  130 . The whipstock assembly  130  may be tapered from its downhole end (not shown) to an uphole tip  302  thereby defining the deflector surface  208 . In operation, the deflector surface  208  is operable to direct the drilling assembly  304  in the desired circumferential orientation in order to form the casing exit  132  ( FIG. 2 ) in the casing joint  126 . As used herein, the term “drilling assembly” can refer to both milling and drilling assemblies, or refer to either assembly individually. 
     The drilling assembly  304  may include one or more mills, such as a first mill  306  and a second mill  308 . It will be appreciated, however, that more or less than two mills  306 ,  308  may be used in the drilling assembly  304 , without departing from the scope of the disclosure. The first mill  306  may be characterized as a lead mill having a partially tapered profile configured to engage and ride up the deflector surface  208  as the drilling assembly  304  advances within the casing joint  126 . The second mill  308  may be axially spaced from the first mill  306  along the drill string  120  and be characterized as a watermelon mill having an outer diameter that is equal to or greater than the outer diameter of the first mill  306 . 
       FIG. 4  shows the drilling assembly  304  as it advances within casing joint  126  and the first or lead mill  306  begins to climb the deflector surface  208  of the whipstock  130 . As the lead mill  306  climbs the angled whipstock  130 , the central axis  402  of the drilling assembly  304  is correspondingly angled such that portions of the drilling assembly  304  following the lead mill  306  are forced into contact with the lowside  404  of the casing joint  126 . As used herein, the term “lowside” refers to the portion of the inner wall of the casing joint  126  (or casing string  124 ) that is located about 180° from the casing exit  132  ( FIG. 2 ). 
     As illustrated, a point of contact  406  may be located or otherwise determined where the drilling assembly  304  generally contacts the lowside  404  of the casing joint  126 . The point of contact  406  may be determined by knowing the angle of the deflector surface  208  with respect to the casing joint  126  and the corresponding diameters of the second mill  308  and the remaining portions of the drill string  120  ( FIG. 3 ). In some embodiments, the point of contact  406  may apply to both the second mill  308  and the drill string  120  ( FIG. 3 ) such that both the second mill  308  and the drill string  120  following the second mill  308  will respectively rotate and wear at or near the same point of contact  406  with the casing joint  126  as the drilling assembly  304  advances within the wellbore  122 . 
     As illustrated, the uphole tip  302  of the whipstock  130  may be arranged along the axial length of the casing joint  126  and axially spaced from the casing string  124  by a first distance  408 . In scenarios where the point of contact  406  falls within the first distance  408 , the second mill  308  and succeeding drill string  120  may detrimentally wear against the lowside  404  of the casing joint  126 . According to at least one embodiment disclosed herein, the damaging wear generated on the lowside  404  by the second mill  308  and succeeding drill string  120  may be eliminated by reducing the axial length of the first distance  408 . By reducing the first distance  408 , the point of contact  406  may fall outside of the first distance  408  and thereby be located at a point located within the casing string  124 . As a result, the second mill  308  and succeeding drill string  120  will not wear against the soft material of the casing joint  126 , but will instead wear against the harder material of the casing string  124  where the damaging wear will be less detrimental to the proper operation of the well system subassembly  128 . 
     In some embodiments, the axial length of the first distance  408  may be reduced by installing or otherwise setting the whipstock assembly  130  in the casing joint  126  closer to the casing string  124 . In other embodiments, the axial length of the first distance  408  may be reduced by simply reducing the overall length of the casing joint  126  such that the uphole tip  302  of the whipstock  130  is required to be closer to the casing string  124  by virtue of the shortened length and thereby locating the point of contact at a location falling within the casing string  124 . 
     Referring now to  FIG. 5   a , illustrated is another exemplary well system subassembly  502 , according to one or more embodiments disclosed. The subassembly  502  may be similar in several respects to the well system subassembly  128  described above with reference to  FIGS. 2 and 3 . Accordingly, the subassembly  502  of  FIG. 5   a  may be best understood with reference to  FIGS. 2 and 3 , where like numerals indicate like components that will not be described again in detail. Similar to the well system subassembly  128  described with reference to  FIGS. 2 and 3 , the well system subassembly  502  may be configured to not only divert a drilling assembly  304  such that one or more mills  306 ,  308  are able to mill out a casing exit  132  ( FIG. 2 ) for the subsequent formation of a lateral borehole  134 , but also protect the lowside  404  of the casing joint  126  (or casing string  124 , when applicable) from damaging wear by the rotating drilling assembly  304 . 
     As illustrated, the well system subassembly  502  may include a wear sleeve  504  extending axially from the whipstock assembly  130 . In some embodiments, the wear sleeve  504  may be coupled or attached to the whipstock assembly  130  with attachment methods such as, but not limited to, mechanical fasteners, welding techniques, brazing techniques, adhesives, combinations thereof, or the like. In other embodiments, however, the wear sleeve  504  may be formed as an integral portion or extension of the whipstock  130  itself. Advantageously, the wear sleeve  504  is coupled directly to the whipstock assembly  130 , thereby being run into the main wellbore  122  along with the remaining components of the whipstock assembly  130 . 
     Referring to  FIG. 5   b , with continued reference to  FIG. 5   a , illustrated is a cross-sectional view of the exemplary wear sleeve  504  as extending from the whipstock  130 , according to one or more embodiments. Without the wear sleeve  504 , the whipstock  130  is essentially a cylinder cut into a wedge shape where the deflector surface  208  defines a chute for the drilling assembly  304  to engage and ride up on. With the wear sleeve  504 , however, the whipstock  130  may provide a throat  506  at its uphole end configured to receive the drilling assembly  304  as it advances in the main wellbore  122 . The throat  506  may extend axially along the length of the wear sleeve  504  and transition gradually into the deflector surface  208  ( FIG. 5   a ) of the whipstock  130 . 
     The wear sleeve  504  may be made of a hard material (e.g., stainless steel or other steel alloys) or hardened through methods such as heat treating or hard coatings, such as ceramics, and/or may be made of the same material as the whipstock  130 . Moreover, the wear sleeve  504  may have an axial length that extends beyond or otherwise across the point of contact  406  ( FIG. 4 ) such that the drilling assembly  304  will engage the throat  506  as it advances in the wellbore  122 , and not the lowside  404  of the casing joint  126 . Consequently, the wear sleeve  504  may be configured to protect the soft material of the casing joint  126  from damaging wear caused by the drilling assembly  304 . 
     In one or more embodiments, as illustrated, the wear sleeve  504  may provide or otherwise define a cylindrical sleeve  508  that circumferentially encloses the throat  506  along a portion of the axial length of the wear sleeve  504 . The cylindrical sleeve  508  may have an inner diameter  510  large enough to not only protect the casing joint  126  (or casing string  124 , when applicable) in the area of the uphole tip  302 , but also allow for the milling assembly  304  to pass therethrough, unobstructed. In some embodiments, however, the inner diameter  510  may be sized such that the second mill  308  is required to mill away a portion of the cylindrical sleeve  508  in order to allow the milling assembly  304  to properly pass therethrough. 
     In other embodiments, the cylindrical sleeve  508  may be omitted and the wear sleeve  504  may instead provide an arcuate member  512  that forms an elongate chute along the axial length of the wear sleeve  504 . The arcuate member  512  may be configured to extend only partially about the inner surface of the casing joint  126  and, with the throat  506 , transition gradually into the deflector surface  208  ( FIG. 5   a ) of the whipstock  130 . In some embodiments, the arcuate member  512  may extend arcuately between about 15° and about 200° about the inner circumferential surface of the casing joint  126  (or casing string  124 , when applicable). Other angular configurations for the arcuate member  512 , however, may be used, without departing from the scope of the disclosure. 
     The wear sleeve  504  may further define one or more apertures  514  defined about its circumference. In operation, the apertures  514  may provide a location where a hydraulic tool, or the like, can latch onto the whipstock  130 . The hydraulic tool may be used to initially run the whipstock  130  into the well and subsequently retrieve the whipstock  130  when milling and drilling operations are complete. 
     Referring now to  FIG. 6 , illustrated is another exemplary well system subassembly  602 , according to one or more embodiments disclosed. The subassembly  602  may be similar in several respects to the well system subassembly  128  described above with reference to  FIGS. 2 and 3  and therefore may be best understood with reference thereto, where like numerals indicate like components not described again. As illustrated, the well system subassembly  602  may include a wear bushing  604  configured to protect the lowside  404  of the casing joint  126  (or casing string  124 , when applicable) from damaging wear by the rotating drilling assembly  304 . To accomplish this, the wear bushing  604  may be made of a hard material (e.g., stainless steel or other steel alloys) or hardened through heat treatment or applications of hard coatings, such as a material that is harder than that of the casing joint  126 , and/or may be made of the same material that the whipstock  130  is made out of. 
     In some embodiments, the wear bushing  604  may be an elongate cylinder of varying length, where the length depends on the application and the eventual location of the point of contact  406  ( FIG. 4 ). In one or more embodiments, the wear bushing  604  may be run into the main wellbore  122  as part of the drilling assembly  304  and be detached therefrom once coming into contact with a stationary wellbore object or “no-go” point, such as the uphole tip  302  of the whipstock assembly  130  or the casing exit  132  ( FIGS. 1 and 2 ). Accordingly, during operation after being appropriately detached from the drilling assembly  304 , the wear bushing  604  may freely rotate within the main wellbore  122  and not be locked rotationally to the drilling assembly  304 , nor locked rotationally to the casing joint  126  (or casing string  124 , when applicable). 
     In at least one embodiment, the wear bushing  604  may be coupled to the outer diameter or outer extent of the lead mill  306  using, for example, one or more shear pins, shear rings, mechanical fasteners, etc. While not illustrated herein, those skilled in the art will readily recognize that the wear bushing  604  may equally be coupled to the outer diameter or outer extent of the second mill  308 , without departing from the scope of the disclosure. Once the wear bushing  604  contacts the uphole tip  302 , or another “no-go” point, the shear pins/rings, mechanical fasteners, etc. may be configured to release or otherwise break, thereby freeing the wear bushing  604  and allowing it to provide wear protection along its axial length. 
     In some embodiments, the inner diameter of the wear bushing  604  may be less than the outer diameter of the second mill  308 . Consequently, the second mill  308  may be used to completely mill up the wear bushing  604  as the drilling assembly  304  advances downhole. In other embodiments, however, the second mill  308  may be configured to mill the inner diameter of the wear bushing  604  to a diameter sufficient for the second mill  308  and succeeding drill string  120  to pass therethrough. Moreover, the wear bushing  604  may have an inner diameter less than the outer diameter of the whipstock assembly  130 , even after being optionally milled to a larger inner diameter with the second mill  308 . Consequently, upon removing the whipstock assembly  130  from the main wellbore  122 , the whipstock assembly  130  may be configured to force or otherwise carry the wear bushing  604  out of the main wellbore  122  also. 
     In other embodiments, the wear bushing  604  may be threaded to the outer diameter or extent of the first and/or second mills  306 ,  308 . Once the wear bushing  604  contacts the uphole tip  302 , or another “no-go” point, and the drilling assembly  304  continues to rotate, the initial resistance to rotation may serve to un-thread the wear bushing  604  from the drilling assembly  304 , thereby allowing it to float on the drill string  120  and provide wear protection. Drill strings  120  are typically rotated to the right (i.e., clockwise) when milling since drill pipe typically has right hand threads. Accordingly, the wear bushing  604  may be configured with left hand threads such that it would loosen and un-thread as the drilling assembly  304  is rotated to the right. Again, the wear bushing  604  may have an inner diameter less than the outer diameter of the whipstock assembly  130 . Consequently, upon removing the whipstock assembly  130  from the main wellbore  122 , the wear bushing  604  may be forced or carried out of the main wellbore  122  also. 
     In yet other embodiments, the wear bushing  604  (shown in dashed lines) may be coupled to the drilling assembly  304  uphole from the second mill  308  using, for example, one or more shear pins, shear rings, mechanical fasteners, etc. Again, once the wear bushing  604  contacts the uphole tip  302 , or another “no-go” point, the shear pins/rings, mechanical fasteners, etc. may be configured to release or otherwise break, thereby freeing the wear bushing  604  and allowing it to provide wear protection along its axial length. The wear bushing  604  in said embodiment may be particularly useful in protecting not only the casing joint  126  from wear, but also the casing string  124 . This may prove advantageous in applications where long lateral wellbores are being drilled and the drill string  120  rides and wears on the casing string  124  over long periods of time. The wear bushing  604  in said embodiment may further exhibit an inner diameter smaller than the maximum outer diameter of one or both of the mills  306 ,  308 . Consequently, when the drilling assembly  304  is pulled out of the main wellbore  122 , the wear bushing  604  may be forced out of the main wellbore  122  also. 
     As can be appreciated, the wear bushing  604  may be run into the main wellbore  122  via various other means or techniques. For example, the wear bushing  604  could be run as part of the casing exit  132  assembly, or with the original drilling assembly in order to protect the main wellbore  122  below the casing exit  132  as the drilling assembly  304  drills the parent borehole deeper, and prior to the insertion of the whipstock assembly. In operation, the wear bushing  604  acts as a bearing and therefore reduces friction. 
     Referring now to  FIG. 7 , illustrated is another exemplary well system subassembly  702 , according to one or more embodiments disclosed. The subassembly  702  may be similar in several respects to the well system subassemblies  128  and  602  described above with reference to  FIGS. 2 ,  3 , and  6  and therefore may be best understood with reference thereto, where like numerals indicate like components not described again. Similar to the well system subassembly  602 , the well system subassembly  702  may include a wear bushing  604  (shown in dashed) configured to protect the lowside  404  of the casing joint  126  (or casing string  124 , when applicable) from damaging wear by the rotating drilling assembly  304  (i.e., including the drill string  120 ). Also similar to the well system subassembly  602 , the wear bushing  604  may be run into the main wellbore  122  by being coupled to any component of the drilling assembly  304  and removably detached therefrom via the several detachment processes described above with reference to  FIG. 6 . 
     Unlike the well system subassembly  602 , however, the well system subassembly  702  may include a coupling  704  such as, but not limited to a latch coupling or depth reference coupling, as known in the art. In some embodiments, as illustrated, the coupling  704  may be formed or otherwise defined on the inner surface of the casing string  124 . In other embodiments, however, the coupling  704  may be formed or otherwise defined on the inner surface of the casing joint  126 , without departing from the scope of the disclosure. As described below, the coupling  704  may be characterized as a stationary wellbore object or “no-go” point as it interacts with the wear bushing  604 . 
     The coupling  704  may have a unique machine coupling profile  706  configured to match a corresponding unique machine bushing profile  708  defined on the outer surface of the wear bushing  604 . Accordingly, as the wear bushing  604  is run into the main wellbore  122 , the coupling and bushing profiles  706 ,  708  may locate each other and thereby be able to set the wear bushing  604  in its proper place. In some embodiments, for example, the wear bushing  604  may be a snap ring device capable of expanding into the coupling  704  once the corresponding profiles  706 ,  708  are mutually located and engaged. 
     Since the coupling  704  may be formed or otherwise defined in the casing string or joint  124 ,  126  at a known depth within the main wellbore  122 , the wear bushing  604  may be designed and installed such that it extends across the point of contact  406  ( FIG. 4 ) and thereby prevents damaging wear from occurring on the lowside of the casing joint  126  (or casing string  124 , where applicable). Advantageously, the use of the coupling  704  helps ensure that the wear bushing  604  is located in the ideal location relative to the uphole tip  302  of the whipstock  130 . Moreover, the wear bushing  604  may have an inner diameter less than the outer diameter of either the whipstock assembly  130  or one or more of the components of the drilling assembly  304 . Consequently, upon removing the whipstock assembly  130  or the drilling assembly from the main wellbore  122 , the wear bushing  604  may be forced out of engagement with the coupling  704  and thereafter removed from the main wellbore  122  also. 
     Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.