Abstract:
An orientation and locator system including a receiver sub disposed in and installed with a casing string in the borehole. The receiver sub has azimuth and depth profiles for positively locating a predetermined position within the borehole. The profiles are within the inside diameter of the casing string and do not restrict the flowbore of the casing. The orientation and locator system further includes a coupling sub attached to a well tool and adapted to engage the receiver sub to orient and locate the well tool within the borehole for conducting a well operation. The coupling sub has an alignment key and a plurality of dogs for engaging the azimuth and depth profiles, respectively. Further, the coupling sub may pass completely through the receiver sub en route to another receiver sub located in the casing string further downhole. The coupling sub and receiver sub are configured such that they may be engaged whether the coupling sub is passing upstream or downstream through the casing string.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not applicable 
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention generally relates to an orientation and locator system including a coupling sub to secure a tool within a receiver sub previously disposed within a string of casing installed in the borehole and more particularly, to a coupling sub that is installed and removed from the receiver sub in the casing string. Furthermore, the present invention relates to, a coupling sub for securing, positioning, and removing a whipstock at a known location within in a cased borehole. 
     2. Description of the Related Art 
     It is common for well operations to be conducted at a known location within the bore of a well. This location may be relative to a formation, to a previously drilled well bore, or to a previously conducted well operation. For example, it is important to know the depth of a previous well operation. However, measurements from the surface are often imprecise. Although it is typical to count the sections of pipe in the pipe string as they are run into the borehole to determine the depth of a well tool mounted on the end of the pipe string, the length of the pipe string may vary due to stretch under its own weight or due to downhole temperatures. This variance is magnified when the pipe string is increased in length, such as several thousand feet. It is not uncommon for the well tool to be off by several feet when depth is measured from the surface. 
     Many well operations require locating a particular depth and azimuth in the borehole for conducting a new well operation. One such well operation is the drilling of one or more lateral boreholes. One typical sidetracking operation for drilling a lateral wellbore from a new or existing wellbore includes running a packer or anchor into the wellbore on wireline or on coiled tubing and then setting the packer or anchor within the wellbore. The packer or anchor is set at a known depth in the well by determining the length of the wireline or coiled tubing run into the wellbore. A second run or trip is made into the wellbore to determine the orientation of the packer or anchor. Once this orientation is known, a latch and whipstock are properly oriented and run into the wellbore during a third trip wherein the latch and whipstock are seated on the packer or anchor. One or more mills are then run into the wellbore on a drill string to mill a window in the casing of the wellbore. The whipstock is then retrieved. Subsequent trips into the wellbore may then be made to drill the lateral borehole or to install a deflector or other equipment for down hole operations. 
     In conventional sidetracking operations, although the depth of the packer or anchor used to support the whipstock is known, the orientation of the packer or anchor within the wellbore may not be known. Thus, a subsequent trip must be made into the wellbore to determine the orientation of the packer or anchor using an orientation tool. The packer or anchor has a receptacle with an upwardly facing orienting surface which engages and orients the orientation tool stabbed into the packer or anchor. The orientation tool then determines the orientation of the packer or anchor within the wellbore. Once the orientation of the packer or anchor has been established, the orientation of the latch, whipstock and mill to be subsequently disposed in the wellbore is then adjusted at the surface so as to be properly oriented when run into the wellbore. The latch, whipstock and mill are then run into the wellbore and stabbed and latched into the packer or anchor such that the face of the whipstock is properly directed for milling the window and drilling the lateral borehole. 
     Since the packer or anchor are not oriented prior to their being set, the receptacle having the orienting surface and a mating connector may have an orientation that could lead to the receptacle being damaged during future operations. If the receptacle is damaged, it will not be possible to use it for orientation and latching of a subsequent well operation. 
     It is preferred to avoid numerous trips into the wellbore for the sidetracking operation. A one trip milling system is disclosed in U.S. Pat. Nos. 5,771,972 and 5,894,889. See also, U.S. Pat. No. 4,397,355. 
     In a sidetracking operation, the packer or anchor serves as a downhole well tool which anchors the whipstock within the cased borehole against the compression, tension, and torque caused by the milling of the window and the drilling of the lateral borehole. The packer and anchor have slips and cones which expand outward to bite into the cased borehole wall to anchor the whipstock. A packer also includes packing elements which are compressed during the setting operation to expand outwardly into engagement with the casing thereby sealing the annulus between the packer and the casing. The packer is used for zone isolation so as to isolate the production below the packer from the lateral borehole. 
     An anchor without a packing element is typically used where the formation in the primary wellbore and the formation in the lateral wellbore have substantially the same pressure and thus the productions can be commingled since there is no zone pressure differentiation because the lower zone has substantially the same formation pressure as that being drilled for the lateral. In the following description, it should be appreciated that a packer includes the anchoring functions of an anchor. 
     The packer may be a retrievable packer or a permanent big bore packer. A retrievable packer is retrievable and closes off the wellbore while a permanent big bore packer has an inner mandrel forming a flowbore through the packer allowing access to that portion of the wellbore below the packer. The mandrel of the big bore packer also serves as a seal bore for sealing engagement with another well tool, such as a whipstock, bridge plug, production tubing, or liner hanger. The retrievable packer includes its own setting mechanism and is more robust than a permanent big bore packer because its components may be sized to include the entire wellbore since the retrievable anchor and packer does not have a bore through it and need not be a thin walled member. 
     One apparatus and method for determining and setting the proper orientation and depth in a wellbore is described in U.S. Pat. No. 5,871,046. A whipstock anchor is run with the casing string to the desired depth as the well is drilled and the casing string is cemented into the new wellbore. A tool string is run into the wellbore to determine the orientation of the whipstock anchor. A whipstock stinger is oriented and disposed on the whipstock at the surface, and then the assembly is lowered and secured to the whipstock anchor. The whipstock stinger has an orienting lug which engages an orienting groove on the whipstock anchor. The whipstock stinger is thereby oriented on the whipstock anchor to cause the face of the whipstock to be positioned in the desired direction for drilling. The whipstock stinger may be in two parts allowing the upper part to be rotated for orientation in the wellbore. The anchor portion of the apparatus of the &#39;046 patent is structured such that it restricts the flowbore of the casing string. Furthermore, because of this restriction, if subsequent anchors are to be set beyond a primary anchor, they must accommodate progressively smaller gauges. There is no provision in the &#39;046 patent to allow a latching tool engage one anchor, and then pass through en route to engagement with another anchor further downhole. 
     U.S. Pat. No. 5,467,819 describes an apparatus and method which includes securing an anchor in a cased wellbore. The anchor may include a big bore packer. The wall of a big bore packer is roughly the same as that of a liner hanger. The anchor has a tubular body with a bore therethrough and slips for securing the anchor to the casing. The anchor is set by a releasable setting tool. After the anchor is set, the setting tool is retrieved. A survey tool is oriented and mounted on a latch to run a survey and determine the orientation of the anchor. A mill, whipstock, coupling and a latch or mandrel with orientation sleeve connected to the lower end of the whipstock are assembled with the coupling allowing the whipstock to be properly oriented on the orientation sleeve. The assembly is then lowered into the wellbore with a lug on the orientation sleeve engaging an inclined surface on the anchor to orient the assembly within the wellbore. The window is milled and then the lateral is drilled. If it is desirable to drill another lateral borehole, the whipstock may be reoriented at the surface using the coupling and the assembly lowered into the wellbore and re-engaged with the anchor for drilling another lateral borehole. 
     U.S. Pat. No. 5,592,991 discloses another apparatus and method for installing a whipstock. A permanent big bore packer having an inner seal bore mandrel and a releasable setting tool for the packer allows the setting tool to be retrieved to avoid potential leak paths through the setting mechanism after tubing is later sealingly mounted in the packer. An assembly of the packer, releasable setting tool, whipstock, and one or more mills is lowered into the existing wellbore. The packer may be located above or below the removable setting tool. A survey tool may be run with the assembly for proper orientation of the whipstock. A lug and orienting surface are provided with the packer for orienting a subsequent well tool. The packer is then set and the window in the casing is milled. The whipstock and setting tool are then retrieved together leaving the big bore packer with the seal bore for sealingly receiving a tubing string so that production can be obtained below the packer. One disadvantage of the big bore packer is that its bore size will not allow the next conventional smaller sized casing to be run through its bore requiring an even smaller sized casing. 
     Furthermore, U.S. Pat. No. 5,592,991 describes the use of a big bore packer as a reference device. However, once the releasable setting tool and whipstock are removed from the big bore packer, the packer no longer has sealing integrity. The big bore packer only seals the wellbore after another assembly is lowered into the well and a stinger is received by the big bore packer to create or establish sealing integrity. The big bore packer does double duty, first it serves as the anchor for the milling operation and then it becomes a permanent packer for the completion. 
     In both the &#39;819 and &#39;991 patents, the whipstock assembly must latch into the packer or anchor to anchor the whipstock and withstand the compression, tension, and torque applied during the milling of the window and the drilling of the lateral borehole. Further, the use of a big bore packer requires a packer assembly which can withstand a 5,000 psi pressure differential and thus all of its components must have a minimum 5,000 psi burst and collapse capability. 
     The big bore packer has the additional disadvantage of having a mandrel extending through it and on which is mounted the cones for activating the slips of the packer. The mandrel is subsequently used as a seal bore which is then used for sealing with a tubing string. This mandrel is not only an additional mechanical part but requires a reduction in the diameter of the bore of the packer. Furthermore, to remove restrictions from the borehole following operations, an additional trip downhole to retrieve the anchor or packer is required. 
     When sidetracking operations are conducted using systems of the &#39;819 and &#39;991 patents, numerous trips are required into the wellbore. A packer is first run into the wellbore on wireline or on coiled tubing and then is set within the wellbore. A second run or trip is made into the wellbore to determine the orientation of the packer. Once this orientation is known, a latch and whipstock are properly oriented and run into the wellbore during a third trip wherein the latch and whipstock are seated on the packer. At this point, a window is milled in the casing of the wellbore. The whipstock is then retrieved. Subsequent trips into the wellbore are then made to install a deflector or other equipment to drill a rat hole to initiate the drilling of the lateral borehole. 
     Further, in conventional sidetracking operations, the packer or anchor, used to support the whipstock, are run and set in the wellbore without knowing their orientation within the wellbore. Thus, a subsequent trip must be made into the wellbore to determine the orientation of the packer or anchor using an orientation member. The packer or anchor has a receptacle with an upwardly facing mule shoe orienting surface to orient a subsequent apparatus stabbed into the packer or anchor. Once the orientation of the packer or anchor has been established, a latch, whipstock and mill can be run into the wellbore and stabbed and latched into the packer or anchor. 
     Since the packer or anchor is not oriented prior to being set, the receptacle, having the mule shoe orienting surface and a mating connector, may have an orientation that could lead to the receptacle being damaged during future operations. If the receptacle is damaged too badly, then it will not be possible thereafter to use it for orientation and latching of additional well tools. 
     A well orientation and depth location device is disclosed in U.S. patent application Ser. No. 09/575,091 filed May 19, 2000 and entitled Anchor Apparatus and Method, which corresponds to UK Patent Application GB 2 351 303, published Dec. 27, 2000, hereby incorporated herein by reference. The &#39;091 application discloses a well location anchor that is deployed upon a tool string and is set at a desired depth and azimuth to properly locate any well operations that may subsequently occur. The anchor includes an integral means to resist any axial or rotational loads that may be transmitted to it during any operations that may utilize the anchor&#39;s location capabilities. Because the anchor is run following drilling and casing operations, it is set within the existing borehole or casing string and restricts the movement of large gage tools or drillstring therethrough. Because of this, the anchor locator of the &#39;091 application significantly limits further exploration and production of wells in which it is used. 
     The present invention overcomes the deficiencies of the prior art. 
     BRIEF SUMMARY OF THE INVENTION 
     An orientation and locator system including a receiver sub disposed in and installed with a casing string in the borehole. The receiver sub has azimuth and depth profiles for positively locating a predetermined position within the borehole. The profiles are within the inside diameter of the casing string and do not restrict the flowbore of the casing. The orientation and locator system further includes a coupling sub attached to a well tool and adapted to engage the casing receiver sub to orient and locate the well tool within the borehole for conducting a well operation. The coupling sub has an alignment key and a plurality of dogs for engaging the azimuth and depth profiles, respectively. Further, the coupling sub may pass completely through the receiver sub en route to another receiver sub located in the casing string further downhole. The coupling sub and receiver sub are configured such that they may be engaged whether the coupling sub is passing upstream or downstream through the casing string. 
     The present invention overcomes the deficiencies of the prior art by providing a location system incorporating a receiver sub that is disposed upon and installed with the casing string. Other objects and advantages of the invention will appear from the following description. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a more detailed description of the preferred embodiment of the present invention, reference will now be made to the accompanying drawings, wherein: 
     FIGS. 1A-B are a sectioned side view of a coupling sub and a corresponding receiver sub in accordance with a preferred embodiment of the present invention in the engaged position; 
     FIG. 2 is a cross-sectional view of the key of FIG. 1A in an extended position; 
     FIG. 3 is a cross-sectional view of the dogs of FIG. 1B in an extended position; 
     FIG. 4 is a cross-sectional view of the dogs of FIG. 1B in a retracted position; 
     FIGS. 5A-B are a sectioned side view of the coupling sub and corresponding receiver sub of FIG. 1A-B prior to engagement; 
     FIGS. 6A-B are a sectioned side view of the coupling sub and corresponding receiver sub of FIGS. 1A-B in the immediately following disengagement; 
     FIGS. 7A-C are a partially sectioned view of the coupling sub assembly of FIGS. 1A-B in a running position; 
     FIGS. 8A-C are a schematic representation of the coupling sub of FIGS. 1A-B and an attached whipstock prior to engagement with a receiver sub; 
     FIGS. 9A-C are a schematic representation of the coupling sub of FIGS. 1A-B and an attached whipstock in engagement with a receiver sub; 
     FIGS. 10A-C are a schematic representation of the coupling sub of FIGS. 1A-B and an attached whipstock in engagement with a receiver sub during an window milling operation; and 
     FIGS. 11A-C are a schematic representation of the coupling sub of FIGS. 1A-B and an attached whipstock during to following retrieval from a receiver sub. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     Referring initially to FIGS. 1A and 1B, an orientation and locator system  11  is shown for a casing string  16 . The orientation and locator system  11  includes a coupling or receiver sub  10  and a coupling sub  50 . Receiver sub  10  has female ends  12 ,  14  threadingly disposed in casing string  16 . Casing string  16  is connected to each end  12 , 14  of receiver sub  10  by male rotary threaded connections  18 ,  20  and has a flowbore  22  therethrough. Receiver sub  10  includes a primary inner bore  24 , an interior azimuth profile  26 , and a depth location profile  28 . Azimuth profile  26  includes upper and lower muleshoes  30 ,  32  that meet at a central key slot  34 . Profile  28  is preferably an annular groove cut within the inner bore  24  of receiver sub  10  so as to not restrict flow therethrough or project into the flowbore  22  of casing string  16 . Depth location profile  28 , includes a location bore  36  and upper and lower annular chamfered shoulders  38 , and  40 . 
     The double muleshoe  30 ,  32  of receiver sub  10  allows coupling sub  50  to be oriented either as it is being lowered downwardly through receiver sub  10  or being pulled upwardly from below and through sub  10 . It should be appreciated that a double muleshoe is not required. In fact, in one embodiment, upper muleshoe  30  is eliminated to shorten the length of receiver sub  10 . In that embodiment, the coupling sub  50  passes through casing receiver sub  10  and then is pulled back up so as to latch into lower muleshoe  32  to orient coupling sub  50 . 
     Receiver sub  10  with locator profiles  26  and  28  is installed in the well bore as a part of casing string  16  following borehole drilling. Because casing string  16  is typically cemented within the borehole, receiver subs  10  in accordance with the present invention are deployed almost exclusively in new wells as they must be installed with casing string  16 . Inner bore  24  of receiver sub  10  is preferred to be the same size and configuration as flowbore  22  of casing string  16 . Receiver sub  10  preferably has a larger wall thickness than the remainder of casing string  16  to allow profile  26  to be machined within bore  24  without penetrating completely through the wall of receiver sub  10 . 
     Coupling sub  50  includes upper and lower sections  52 ,  54 , each configured to have an end connected to a work string (not shown) by threaded rotary “box” connections  56  and  58 , respectively. Threadably disposed between upper and lower sections  52 ,  54  is a latch mandrel  60  upon which a latch system  62  is disposed. A flowbore  64  extends from upper section  52 , through mandrel  60 , and to lower section  54  of coupling sub  50 . It is preferred that flowbore  64  approximate the through bore of required for the passage of well tools (not shown) within the work string so that flow therethrough is not restricted. 
     Referring now to FIGS. 1A-B and  2 , upper section  52  of coupling sub  50  includes a key  66  adapted to ride within azimuth profile  26  so as to properly angularly orient coupling sub  50  within receiver sub  10 . FIG. 2 shows a cross sectional top view of key  66  extending from the upper section  52  of coupling sub  50  into receiver sub  10 . As shown in FIGS. 1A-B, key  66  is preferably spring biased outwardly by springs  68  and is retained within a recess  65  in the wall  71  of upper section  52  by retainer flanges  70  which engage tangs  73 ,  75  to prevent key  66  from moving out of the recess  65  cut within upper section  52 . Tang  75  includes a member releasably fastened to upper section  52  for assembly purposes. Key  66  includes upstream and downstream tapered surfaces  67 ,  69  respectively, to facilitate engagement and disengagement with profile  26 . Key  66  acts within the channels formed by muleshoes  30 ,  32  to apply an angular moment to coupling sub  50  and orient it to the desired azimuth as defined by profile  26 . When removal is desired, an upward or downward force is applied to coupling sub  50  and taper ends  67 ,  69 , depending on direction, cams key  66  into upper section  52  against the bias of spring  68 . With key  66  compressed within recess  65  of upper section  52 , the angular orientation of coupling  50  is no longer restricted. 
     Referring now to FIGS. 1A-B,  3  and  4 , because azimuth profile  26  is provided to locate sub  50  to the proper azimuth with respect to receiver sub  10 , profile  26  must allow a slight amount of lateral movement between subs  10 ,  50 . Depth location profile  28  acts in conjunction with azimuth profile  26 . Latch system  62  is preferably located on mandrel  60  below alignment key  66  and includes a plurality of dogs  72 , preferably three, each disposed in a window  83  in a sleeve  108  disposed on the exterior surface  77  of mandrel  60 . Dogs  72  are retained in windows  83  by retainers  79 ,  81 . Retainers  79 ,  81  are releasably attached to sleeve  108 . Dogs  72  are configured to engage depth location profile  28  in receiver sub  10  when coupling sub  50  is at the proper depth. When actuated, dogs  72  expand outward radially into annular depth location profile  28  to secure sub  50  within receiver sub  10 . FIGS. 3 and 4 show cross-sectional details of an array of dogs  72  with FIG. 3 showing the dogs  72  in the expanded position and FIG. 4 showing the dogs  72  in the contracted position. 
     As best shown in FIGS. 1A-B, dogs  72  include an engagement surface  74 , upper and lower wedge profiles  76 ,  78 , and at least one inwardly projecting arcuate member  80 . Inwardly projecting members  80  of dogs  72  are configured to ride up on corresponding outwardly projecting annular members  82  of mandrel  60 . Camming surfaces  84 ,  86  of members  80  coact with corresponding camming surfaces  88 ,  90  of members  82  to drive dogs  72  into engagement with profile  28 . When dogs  72  are fully extended, as shown in FIGS. 1A-B, members  80  and  82  meet at surfaces  92  to secure dogs  72  in their extended and locked position 
     A carriage assembly  94  is mounted on the lower end of sleeve  108  by interlocking shoulders  85 ,  87 . An annular chamber  98  is formed by an inner sleeve  100  having a downwardly facing annular shoulder  106  and an outer sleeve  102  having a retainer member  89  forming an upwardly facing annular shoulder  118  to house Belleville springs  96  comprising a stack of Belleville washers. Retainer member  89  also includes a downwardly facing shoulder  104  which engages the upper end of lower section  54 . If sleeve  108  with dogs  72  moves upwardly, shoulder  87  of outer sleeve  102  engaging shoulder  85  on sleeve  108  causes outer sleeve  102  and retainer member  89  to move upwardly whereby upwardly facing shoulder  118  compresses springs  96  against downwardly facing shoulder  106 . If sleeve  108  with dogs  72  moves downwardly, then the lower end  112  of sleeve  108  engages the upper end  110  of inner sleeve  100  causing downwardly facing shoulder  106  to move downwardly to compress springs  96  against shoulder  118 . Thus, carriage  94  and belleville stack  96  are constructed to bias dogs  72  against movement either upstream or downstream from an equilibrium point. 
     In FIGS. 1A-B Belleville spring washers  96  are shown at their most relaxed, or de-energized, state. Spring stack  96  is preferably configured to be slightly compressed in this configuration so that axial play in the carriage  94  is minimized, with shoulder  104  engaging lower section  54  and shoulders  110 ,  112  engaging thereby preventing stack  96  of washers from slackening. Furthermore, having spring stack  96  energized in it&#39;s base state, requires a relatively higher load to be applied to carriage  94  before displacement up or down the axis of the borehole is possible. Belleville stack  96  can exert as much as 20,000 pounds per square inch of pressure upon the carriage  94  and engaged sleeve  108  with dogs  72 . This amount of elevated spring energy enables the latching action of coupling sub  50  to be much more controlled and predictable than with other systems. Furthermore, a high energy latch has a much greater chance of being “felt,” or noticed, by the operator during engagement than a lower energy counterpart. 
     Referring now to FIGS. 5A-B, the coupling sub  50  is shown during a trip into casing string  16  extending into the borehole and prior to engagement with receiver sub  10 . While tripping in, projecting members  80  of dogs  72  are upstream of the projecting members  82  on mandrel  60 . As shown, sleeve  108  with dogs  72  is “dragged” rather than “pushed” by mandrel  60  and carriage  94  while sub  50  is tripped into casing string  16 . This configuration allows the free movement of coupling sub  50  within casing string  16  without the worry that dogs  72  will snag an obstruction that will stop or restrict movement of coupling sub  50 . A clearance gap  114  is created between shoulders  110 ,  112  of sleeve  108  and inner sleeve  100 , respectively. Gap  114  is created when sleeve  108  and outer sleeve  102  compress spring  96  by pulling up on shoulder  118  with sleeve  100  held in place by shoulder  112 . 
     Once coupling sub  50  is aligned at the proper depth with profile  28 , Belleville spring  96  of carriage  94  will pull projecting members  80  of dogs  72  up camming surface  88  of projecting members  82  of mandrel  60  and force dogs  72  into the engaged position as shown in FIGS. 1A-B. Before dogs  72  engage profile  28 , key  66  will engage profile  26  so that coupling sub  50  is properly angularly aligned. As coupling sub  50  is engaged within receiver sub  10 , key  66  engages muleshoe  30 ,  32  and guides coupling sub  50  into angular alignment toward profile  26 . Once in alignment and at proper depth, coupling sub  50  is configured in accordance with receiver sub  10  so that dogs  72  and key  66  engage their respective profiles  28 ,  26  at substantially the same time. 
     Upon engagement with profiles  26 ,  28 , key  66  and dogs  72  snap into place. Once the projecting members  80 ,  82  are back to back as shown in FIGS. 1A-B, dogs  72  are prevented from retracting out of profile  28  unless a load large enough to compress spring  96  is applied in the upward or downward directions. Since the latching engagement between coupling sub  50  and receiver sub  10  is only intended to locate the desired downhole position, an anchor or a retrievable packer will need to be set to allow the string to withstand any heavy axial loading. 
     When coupling sub  50  is to be retrieved, the anchor must be retracted and any packer released. Once all anchor devices are retracted, coupling sub  50  can be retrieved by applying a relatively large upward or downward axial load to the drill string. Axial load causes key  66  and dogs  72  to be retracted and disengaged from their respective profiles  26 ,  28 . As described above, tapers  67 ,  69  compress key  66  into recess  65  of upper section  52  of coupling housing  50 . Dogs  72  are displaced axially into windows  83  from their equilibrium positions shown in FIGS. 1A-B when taper  76  or  78  encounters chamfers  38  or  40 . When enough axial displacement has occurred, dogs  72  are then able to be retracted closer to mandrel  60  by traveling down camming surface  88  or  90 , depending upon the direction traveled. 
     Referring now to FIGS. 6A-B, coupling sub  50  is shown tripping out (upward travel) of the borehole with projecting members  80  on dogs  72  below and abutting camming surfaces  90  of projecting members  82  of mandrel  60 . In this position, the upper shoulder  112  of inner sleeve  100  is shouldered against shoulder  110  of sleeve  108 . Note that annular shoulders  85 ,  87  are not in engagement in FIG. 6B but shoulder  112  is in engagement with shoulder  110 . A gap exists at  116  between shoulders  85 ,  87 . This gap  116  represents the amount of compression on springs  96  to maintain dogs  72  in the position shown in FIGS. 6A and 6B. Dogs  72  compress spring  96  by pushing sleeve  108  downward. 
     Referring now to FIGS. 7A-11C in series, there is shown an example of the use of orientation and locator system  11  for drilling a side-tracked hole  224  using a one-trip milling system in accordance with a preferred embodiment of the present invention. Referring initially to FIGS. 7A-C, one-trip milling tool string  200  is shown as it is run through a string of casing  202 . Tool string  200  includes coupling sub  50 , a spline sub  204 , a releasable anchor  206 , a debris barrier  208 , a whipstock  210 , and a window mill  212  attached to a whipstock  210  at  214 . Tool string  200  is engaged within casing  202  until coupling sub  50  latches and engages with receiver sub  10  disposed in casing string  202  as described above. Key  66  engages the muleshoe  30  and orients the coupling sub  50  and related tool string  200 . Coupling sub  50  is then latched within receiver sub  10  and anchor  206  is set. 
     Referring now to FIGS. 8A-C, tool string  200  is shown with coupling sub  50  oriented, engaged and latched within receiver sub  10  of casing string  202 . Once engaged, anchor  206  is set. The setting of anchor  206  ensures that any axial forces associated with the milling or any other operations does not displace sub  50  from its oriented position within sub  10 . Debris barrier  208  prevents any cuttings or other objects from reaching coupling sub  50  and receiver sub  10  while the milling and drilling operations are being performed. In this position, whipstock  210  is oriented such that window mill  212  will cut a window in casing  202  in the direction orthogonal to the inclined face of whipstock  210 . To set the orientation, operators adjust the azimuth of spline sub  204  prior to deployment. Spline sub  204  is thereby set so that whipstock  210  will be in the proper orientation for the desired window when coupling sub  50  engages receiver sub  10 . 
     Referring now to FIGS. 9A-C, window mill  212  is detached from whipstock  210  at  214  and is used to cut a window  220  into casing  202  guided by the inclined surface of whipstock  210 . Window mill  212  is rotated and axially loaded by a drillstring from the surface and cuts a rat hole  224  as it progresses along whipstock  210 . With window  220  cut, the mill  212  and drillstring  222  are retrieved from the side-tracked bore  224  and cased  202  boreholes. 
     Referring now to FIGS. 10A-C, a retrieval tool  226  is deployed on the drillstring  222  and is attached to whipstock  210  at  228 . With retrieval tool  226  attached, anchor  206  is retracted and a large upward load is applied to drillstring  222  to disengage coupling sub  50  from receiver sub  10  as described above. With coupling sub  50  disengaged from receiver sub  10 , drillstring  222  and tool string  200  are retrieved from borehole  202  so that sidetracking equipment can be deployed. 
     Referring finally to FIGS. 11A-C, tool string  200  is again shown with coupling sub  50  engaged and latched within receiver sub  10  of casing string  202 . With tool string  200  installed by a drill string (not shown), anchor  206  is again set to prevent the tool string from deviating from its engaged position. Instead of the whipstock  210  of FIGS. 7A-10C, a deflector  230  is now shown atop toolstring  200  and aligned by spline sub  204 . Deflector  230  acts to deflect drill string components (not shown) into newly milled sidetracked borehole  224  created by the window mill and whipstock operation described above. With deflector  230  in place, side tracked borehole  224  can be drilled into the surrounding formation. 
     A primary benefit of the orientation and locator system  11  presented herein is the ability to accurately and repeatably locate a position by depth and azimuth within a cased borehole. Furthermore, the coupling system of the present invention has the added advantage over those currently available in that the receiver sub  10  does not obstruct the borehole. A coupling sub  50 , or any other tool, is able to pass through receiver sub  10  to deeper depths in the casing string  16  with little or no added assistance force. As such, the existence of receiver sub  10  in a string of casing will not impair further drilling, production, or workover operations in the borehole in which it is installed. Other systems currently available require that smaller gauge tools be used if a locator is to be bypassed. Operations can be even more severely limited if several couplers in series, each with a successively smaller pass through gauge must be bypassed. 
     The orientation and locator system is particularly useful in a new well where the receiver sub is run in with the casing string. Because the orientation and locator system presented herein is substantially non-obstructive, more traditional (and obstructive) couplers may be installed at later dates to accommodate any changes in well design that may be required. Using these types of systems together, although not able to eliminate bore obstructions, should dramatically reduce their numbers. 
     While preferred embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.