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CROSS-REFERENCE TO RELATED APPLICATIONS 
     The present application is a divisional of U.S. patent application Ser. No. 09/448,645, which was filed on Nov. 24, 1999 now U.S. Pat. No. 6,447,021. 
    
    
     TECHNICAL FIELD 
     The present invention relates to the handling of a tubing string in a well bore and, in particular, to a locking telescoping joint for use in a conduit connected to a wellhead which permits the conduit to be axially displaced to a new position in the well bore without disconnecting the conduit from the wellhead and secured in new positions using the locking telescoping joint. 
     BACKGROUND OF THE INVENTION 
     Downhole operations and the handling of a tubing string in a completed well has always presented a certain challenge, especially when working in wells having a natural pressure. 
     In Applicant&#39;s U.S. Pat. No. 5,957,198 which issued Sep. 28, 1999 and is entitled TELESCOPING JOINT FOR USE IN A CONDUIT CONNECTED TO A WELLHEAD AND ZONE ISOLATING TOOL, the specification of which is incorporated herein by reference, a telescoping joint is described for use in a conduit connected to a wellhead. The telescoping joint is adapted to support downhole well tools and to permit the downhole well tools to be axially displaced in the well bore without disconnecting the conduit from the wellhead. The telescoping joint is freely extendable and retractable. Downhole anchors or packers are used to support the conduit in the well bore. Although the telescoping joint has proven extremely useful and has generated significant commercial interest, it is not ideally suited for all downhole tasks and applications due simply to its freely extendable and retractable features. In order to extend the use of the telescoping joint into yet a broader range of applications, further improvement of the telescoping joint, particularly to enable releasably locking the telescoping joint at a selected extension, is desired. 
     For example, production tubing strings are generally anchored at the bottom end to the cased well bore. The length of the production tubing string is usually between 1,500 and 5,000 m (5,000′-16,000′). Over time, a production tubing string will sag under its own weight because of the significant length. This is a disadvantage if a surface driven reciprocating pump is used for production because a sucker rod used to drive the pump may wear and bind in the sagging production tubing string. In order to overcome this problem, long production tubing strings are usually tensioned before production is started. The tensioning process involves unhooking the production tubing from the tubing hanger; pulling up the production tubing string to tension it to a desired extent; marking the production tubing string where it should be reconnected to the tubing hanger; preparing a pup joint having a length equal to a distance from the mark to a next joint in the tubing string; replacing the top joint with the pup joint and re-connecting the tubing hanger. This is a time consuming and expensive procedure that may require killing the well. It is therefore desirable to provide a tool for tensioning a tubing string without removing the wellhead from the well. 
     There are also times when it is desirable to load a tubing string in compression. For example, if a downhole submersible pump is used for production, equipment costs can be reduced by using a less expensive compression packer to anchor the production tubing above the submersible pump. In order to ensure that the packer does not slip, it must be constantly loaded with compressive force. It is therefore desirable to provide a telescoping joint that permits a production tubing to be locked in compression. 
     Latch assemblies and collet devices for interconnecting tubing members are well known in the art. Examples can be shown in U.S. Pat. No. 4,391,326 entitled STINGER ASSEMBLY FOR OIL WELL TOOL which issued to Dresser Industries, Inc. on Jul. 5, 1983; U.S. Pat. No. 4,513,822 entitled ANCHOR SEAL ASSEMBLY which issued to HUGHES TOOL COMPANY on Apr. 30, 1985; U.S. Pat. No. 4,681,166 entitled INTERNAL NONROTATING TIE-NECK CONNECTOR which issued to Hughes Tool Company on Jul. 21, 1987; and U.S. Pat. No. 4,722,390 entitled ADJUSTABLE COLLET which issued to Hughes Tool Company on Feb. 2, 1988. 
     These patents generally describe an annular latch carried by an inner conduit having collet arms that are radially flexible and adapted to engage a latch point on an outer conduit. A relative axial movement between the two conduits is permitted in one direction only to permit threads of the collet arms to ratchet into or out of engagement with the threads of the outer conduit while the relative axial movement in an opposite direction is generally inhibited by the threaded connection to support a work load unless another manipulation is performed. However, none of these patents suggest a latch assembly to releasably lock a telescoping joint in a relative axial extension. Furthermore, these patents do not show or suggest a latch assembly having a plurality of latch points disposed along a travel length of a telescoping joint. 
     SUMMARY OF THE INVENTION 
     It is an object of the invention to provide a telescoping joint for use in a conduit connected to a wellhead to permit the conduit to be axially displaced and locked in the displaced position in the well bore without disconnecting the conduit from the wellhead. 
     It is another object of the invention to provide a telescoping joint for use in a tubing string in a well bore, which includes a latch assembly for locking the telescoping joint at a predetermined axial extension. 
     It is a further object of the invention to provide an apparatus for use in a tubing string in a well bore to maintain tension or a compression on the tubing string. 
     It is yet a further object of the invention to provide a method of maintaining tension or compression on a tubing string in a well bore. 
     In accordance with one aspect of the invention a locking telescoping joint is provided for use in a conduit connected to a wellhead to permit the conduit to be axially displaced in the well bore without disconnecting the conduit from the wellhead. The locking telescoping joint comprises first and second telescopingly interconnected tubular sections having opposite ends adapted for connection to the conduit. A latch assembly is provided for releasably locking the first and second tubular sections in at least one position between a fully retracted and a fully extended position. 
     Preferably, the latch mechanism comprises a first engaging member affixed to one of the tubular sections, and at least one second engaging member affixed to the other tubular section. The first engaging member is adapted to be releasably received in the second engaging member in order to lock the telescopic tubular sections in an axial position relative to each other. The latch mechanism may be any type of releasable engagement adapted to support the weight of a tubing string. For example, a J-latch, key, collet or slip type latch mechanism may be used. 
     According to a first embodiment of the invention, the latch assembly includes at least one pin radially extending from one of the tubular sections and a plurality of axially spaced-apart slots defined in the other of the tubular sections. The slots are preferably interconnected by an axial groove adapted to serve as a passage route for the pin. 
     According to another embodiment of the invention, one of the tubular sections includes a radially collapsible collet which can be manipulated between a collapsed condition for axial movement of the telescoping joint and an expanded condition for locking the telescoping joint at a predetermined extension, and the other of the tubular sections includes at least one cooperative latch point, the cooperative latch point being adapted to cooperate with the collapsible collet during the manipulation between the collapsed and expanded conditions. 
     More specifically, one embodiment of the collet type latch mechanism includes a traveling collet which is adapted to be collapsed by the at least one cooperative latch point when forcibly moved past the latch point in either axial direction, and a locking collet which is adapted to be manipulated between a collapsed condition for axial movement of the telescoping joint and an expanded condition for locking the telescoping joint at a predetermined extension. 
     In accordance with another aspect of the invention, the telescoping joint enables a method for maintaining tension or compression on a tubing string in a cased well bore. The method comprises the steps of: a) inserting a lift rod string into the tubing string which is attached at a top end to a wellhead and anchored at a bottom end to the cased well bore, the tubing string including a locking telescoping joint in the top end; b) latching the rod to a latch point of the telescoping joint; c) retracting or extending the telescoping joint to tension or compress the tubing string by manipulating the rod; d) and, locking the telescoping joint in the retracted or extended position using a latch assembly in the telescoping joint to maintain the tension or compression on the tubing string. 
     The telescoping joint with the latch assembly in accordance with the invention provides improved functionality compared with the telescoping joint described in Applicant&#39;s issued U.S. Pat. No. 5,957,198 and is adapted for use in each application described in that patent. Furthermore, the selective extension locking feature enables the use of the telescoping joint to be extended to new applications, such as the above-disclosed examples of tensioning or compressing the tubing string in a cased well bore, as well as many others. For example, the locking telescoping joint in accordance with the invention can be used to reposition or otherwise manipulate downhole tools. Such tools include any one of a zone isolation tool, a packer, a hanger, a plug, a subsurface safety valve, and a downhole tool having a slip, collet, threaded or keyed locking engagement that is releasable and resetable by remote manipulation from a surface surrounding the well. Consequently, the time and cost of well completion and well maintenance are reduced as is the cost of production of hydrocarbons in wells with a mobile oil/water interface or other condition that requires periodic downhole maintenance. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The invention will now be explained by way of example only and with reference to the following drawings, in which: 
     FIG. 1 is a cross-sectional view of a telescoping joint including a latch assembly for use in a conduit connected to a wellhead in accordance with one embodiment of the invention; 
     FIGS. 2-5 are schematic views of latch mechanisms in accordance with the first embodiment of the invention; 
     FIG. 6 is a partial cross-sectional view of a latch assembly in accordance with another embodiment of the invention; 
     FIG. 7 is a partial cross-sectional view of the embodiment shown in FIG. 2 illustrating the latch assembly in a locking condition; 
     FIG. 8 is a partial cross-sectional view of another embodiment of a telescoping joint in accordance with the invention; 
     FIG. 9 is a schematic cross-sectional view of a well bore with a hoisting apparatus installed on the wellhead for tensioning a production tubing string using a telescoping joint in accordance with the invention; 
     FIG. 10 is a schematic cross-sectional view of the well bore shown in FIG. 10 with a hoisting apparatus installed on the wellhead for placing a production tubing string in the well bore under compression using a telescoping joint in accordance with the invention; 
     FIG. 11 is a diagram of steps followed to tension a tubing string using the locking telescoping joint in accordance with the invention; and 
     FIG. 12 is a diagram of steps followed to place a tubing string in compression using the locking telescoping joint in accordance with the invention. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The invention provides an apparatus and method for using the apparatus for performing downhole operations in well bores which require the axial displacement of downhole tools and/or the axial displacement of well tubing in the well bore. The invention also provides a practical means for maintaining tension or compression on a tubing string in the well bore. 
     FIG. 1 shows a cross-sectional view of a locking telescoping joint with a latch assembly in accordance with the invention for use in a conduit such as a production tubing connected to a wellhead for permitting the conduit to be axially displaced in the well bore without disconnecting the conduit from the wellhead. The locking telescoping joint, generally indicated by reference numeral  10 , includes a first tubular section  12  and a second tubular section  14  which has a larger diameter than the first tubular section. 
     The first tubular section  12  has a first end  16 , a second end  18  and a polished outer surface  20  which extends between the first end  16  and the second end  18 . The first end  16  is machined with a standard thread  22  which is compatible with standard tubing connectors. The second end  18  of the first tubular section  12  is provided with a radially projecting latch member that engages a complementary latch point on an inner surface of the second tubular section  14 . The latch member and the latch point may have any configuration that permits selective engagement/disengagement and is adapted to support the weight of a tubing string, as will be described in detail below. In the example shown in FIG. 1, a J-latch type of latch assembly includes a pair of latch pins  24  that cooperate with a plurality of spaced-apart latch points to selectively lock the telescoping joint in one of a plurality of predetermined extensions. The latch pins  24  also prevent the first tubular section  12  from being completely withdrawn from the second tubular section  14  within which it reciprocates. 
     The second tubular section  14  includes a first end  26  and a second end  28 . The first end  26  includes inwardly extending seals  30  which cooperate with the polished outer surface  20  of the first tubular section  12  to provide a fluid seal between the first and second sections. The fluid seals  30  are preferably high pressure fluid seals to ensure that high pressure fluids do not escape from the telescoping joint  10 . The second end  28  of the second tubular section  14  is threaded with an internal thread  32  to enable the connection of a production tubing. As will be well understood, the first end  16  of the first tubular section  12  may have an internal thread and the second end  28  of the second tubular section  14  may have an external thread. It is preferable, however, that the opposite ends of the telescoping joint have compatible but opposite threads as is standard for any production tubing section. A plurality of cooperative latch points are provided on the internal surface  34  of the second tubular section for selectively engaging the latch members on the outer surface  20  of the first tubular section. Two pairs of circumferentially extending slots  36   a ,  36   b  serve as latch points that receive the latch pins  24 . Axial grooves  68  (see FIGS. 2-5) are provided between the axially spaced-apart latch points  36   a ,  36   b  for providing a path of travel for the latch pins  24  to permit the first tubular section  21  to travel within the second tubular section  14 . 
     The telescoping joint  10  optionally includes a latch point  38  for the connection of a lift rod (see FIG. 10) which may be used to displace the production tubing string and/or downhole well tools connected to the production tubing string. The latch point  38  may be, for example, an internal thread. While the latch point  38  is shown on an inner surface on the second end  28  of the second tubular section  14 , it may likewise be provided on the second end  18  of the first tubular section if the telescoping joint  10  is oppositely oriented with respect to the wellhead. The orientation of the telescoping joint  10  is a matter of design choice and is only material with respect to the location of the latch point  38  which should be located on the tubular section of the telescoping joint  10  that is remote from the wellhead in order to practice the methods in accordance with the invention, which will be explained below in detail. As will be understood by persons skilled in the art, the lift rod may be latched in the tubing string below the telescoping joint. 
     Circumferential grooves  98  preferably located at opposite ends of the inner surface  34  of the second tubular section  14  permit the second tubular section  14  to be freely rotated with respect to the first tubular section  12  when the telescoping joint is at the limits of its relative travel. This permits the rotary manipulation of downhole components. As will be understood by those skilled in the art, the latch points  70 ,  72  (FIG. 4) may likewise be shaped to permit rotation within any arc up to and including 360°. 
     FIGS. 2 to  5  show variations and details of the J-latch type of latch assembly illustrated in FIG.  1 . The slots  36   a ,  36   b  are machined in the inner surface of the second tubular section  14 , indicated by reference numeral  64   a,b . Accordingly, the latch pin is affixed to the outer surface of the first tubular section  12 , indicated by reference numerals  66   a,b . The latch points can be formed in many different shapes as seen in FIG.  4 . Generally, the groove  68  has a length equal to the travel of the telescoping joint  10  for providing the travel path for the latch pin  24 . A plurality of latch points  70  extend circumferentially from the axial groove  68  in one direction, or in opposite directions and are axially spaced apart from one another to enable the telescoping joint to be locked at any one of a plurality of predetermined axial extensions. Each of the latch points  70  may have a closed end. The closed end may include an axial recess  72 . The latch pin  24  is either a gudgeon pin or lug and can have practically any shape  24   a-   24   f , as shown in FIG.  5 . The shape of the latch pin  24  is preferably compatible with the shape selected for the latch points  70 ,  72 . 
     FIG. 6 shows an alternate latch assembly for the telescoping joint  10  in accordance with another embodiment of the invention. Instead of the latch pins  24  and latch points  36   a ,  36   b  shown in FIGS. 2-4, the latch assembly shown in FIG. 6 is a collet type latch that includes a collapsible traveling collet  52  connected to a traveling sleeve  40  slidably mounted on the first tubular section  12 , and a collapsible collet  42  mounted to the first tubular section  12  above the second end  18 . A plurality of spaced-apart annular engagement ridges  44   a ,  44   b , only two of which are shown, are affixed to the inner surface  34  of the second tubular section  14 . The annular engagement ridges  44   a,b  cooperate with the collet latch to lock the telescoping joint at a plurality of predetermined axial extensions. A collet latch  48  affixed to a top end of the traveling sleeve  40  is used to lock the collet  42  in a closed condition which permits the collet  42  to be moved past an annular engagement ridge  44   a,b.    
     The traveling latch  50  includes a plurality of slots (not shown) which permit it to collapse and slip past the annular engagement ridges  44   a,b  when it is forced against either side of the ridges with enough force. The force required to move the traveling latch  50  past an annular engagement ridge  44   a ,b should be considerably greater than the force required to collapse the collet  42  into the collet latch  48 , or to force the collet  42  past a retainer lip  58  on an inner top surface of the collet latch  48  to free the collet  42  from the collet latch  48 . 
     In operation, in order to shorten the telescoping joint, the first tubular section  12  with the sleeve  40  is able to be freely moved upwardly until the traveling latch  50  on the traveling sleeve  40  contacts an annular retainer ridge  44   b  if the collet  42  is locked in the collet latch  48 . When the traveling latch  50  abuts the annular retainer ridge  44   a,b , further movement of the first section  12  of the telescoping joint is inhibited until adequate pressure (e.g. 2,000-3,000 kg) is applied to force the traveling latch  50  past the annular retainer ridge. When the upward force is applied (by the lift rod, not shown) the collet  42  is first forced out of the collet latch  48 , as shown in dashed lines in FIG. 7, because the force required to move the collet  42  in and out of the collet latch is much less (e.g. 500-1,000 kg) than the force required to collapse the traveling latch, as described above. With the application of adequate force, the traveling latch is forced past the annular retainer ridge  44   a . As shown in FIG. 7, the collet  42  will stop against the annular retainer ridge  44   a  unless it is forced back into the collet latch  48  by downward pressure on the first tubular section  12 . 
     As is well understood in the art, the notches  54  in the collet  42  permit the collet to be collapsed into the collet latch  48 . When the collet  42  is expanded, a top edge  56  of the collet  42  rests against an annular retainer ridge  44   a,b  and will support the weight of a tubing string and associated downhole equipment. In order to move the collet latch upwardly past the annular retainer ridge  44   a  shown in FIG. 7, downward pressure is first applied using the lift rod (not shown). The applied force is adequate to force the collet  42  into the collet latch  48 , but inadequate to force the traveling latch  50  past the annular retainer ridge  44   b . When the collet  42  is locked in the collet latch  48 , the collet latch can be freely moved past the annular retainer ridge  44   a  and the series of steps described above is repeated until the traveling latch is forced past the annular retainer ridge  44   a . This process may be repeated as many times as required, or until the limit of travel is reached. 
     In order to extend the length of the telescoping joint shown in FIGS. 6 and 7, the first tubular section  12  is simply forced downwardly using the lift rod (not shown) until the traveling latch is forced past the desired number of annular retainer ridges  44   a,b , or the end of travel is reached. During the downward movement, the collet  42  remains locked in the collet latch  48 . 
     As will be understood by those skilled in the art, the collet  42  shown in FIGS. 6 and 7 prevents extension of the telescoping joint. It therefore permits tubing strings to be placed in tension to prevent downhole tubing string sag when a reciprocal pump is driven from the surface using a sucker rod string. As is also well understood in the art, it is sometimes desirable to use inexpensive compression packers downhole, especially when a submersible production pump is used. However, even when a compression packer is used, the entire weight of the production tubing string is not permitted to rest on the packer. There is therefore still some tension on the tubing string at the wellhead and the collet shown in FIGS. 6 and 7 can be used to place an appropriate amount of weight on the downhole compression packer (not shown). 
     In another embodiment of the invention shown in FIG. 8, the latch assembly is a threaded collet. The threaded collet includes male threads  74  on the outer surface  20  of the first tubular section  12  at the second end  18 . Elongated slots  76  extend axially from the second end  18  of the first tubular section  12  and are circumferentially spaced apart from one another to provide a radial flexibility for the male threads  74 . A plurality of corresponding female threads  78 , only two of which are shown in FIG. 8, are provided on the inner surface  34  of the second tubular section  14  and are axially spaced-apart to serve as latch points for engaging the male threads  76 . Each of the respective male threads  74  and female threads  78  has an upper side  80 ,  82  that is substantially perpendicular to a longitudinal axis of the telescoping joint, so that the upper side  80  of the male threads  74  mesh with the upper side  82  of the female threads  78 . Thus, the male threads  74  cannot ratchet upwardly past the female threads  78 . On the other hand, the male threads can be forced down past the female threads  78  because the mating lower sides of the male and female threads are angularly oriented with respect to the axis of the telescoping joints. 
     In order to move the first tubular section  12  upwardly with respect to the second tubular section  14 , the first tubular section  12  must be rotated to disengage the threaded connection. After disengagement, the collet is in a collapsed condition and the male threads  74  ride against the inner surface  34  of the second tubular section  14 . The female threads  74  may alternatively have a square or rectangular cross-section. If the male threads  74  have complementary square or rectangular cross-sections, however, the second tubular section must be rotated through each latch point, regardless of the direction of travel. Triangular male threads configured as described above are therefore preferred. 
     The latch assembly shown in FIG. 8 is used to lock the telescoping joint  10  at a predetermined axial extension against a workload in one direction only. However, as described above even if compression packers are used, the full weight of the tubing string is not permitted to rest on the packer. The telescoping joint shown in FIG. 8 is therefore adapted for use in placing a tubing string in either tension or compression. 
     The latch assembly shown in FIG. 8 is used to lock the telescoping joint  10  at a predetermined extension to prevent the telescoping joint from further extension under a workload. If it is desired to use the telescoping joint locked at a predetermined extension against a compression workload, the triangular cross-section of the threads should be oppositely oriented. That is, the perpendicular side  80  of the male threads  74  should be reversed from the orientation shown in FIG.  8 . The female threads  82  are, of course, likewise reversed in their axial orientation. 
     As noted above, the telescoping joint with the latch assembly in accordance with the invention is adapted to perform any function described in the Applicant&#39;s U.S. Pat. No. 5,957,198, plus many new applications enabled or facilitated by the ability to lock the telescoping joint at a plurality of predetermined axial extensions. Therefore, the telescoping joint with the latch assembly in accordance with the invention is adapted to be used in any downhole application in which downhole well tools are advantageously axially displaced in the well bore without disconnecting the tubing string from the wellhead, including, for example: 
     displacement of a zone isolating tool in a production zone which produces both oil and water; 
     barefoot completion of a well bore, in which the telescoping joint permits a hydraulic motor driven drill bit attached to the bottom end of the tubing string to complete the drilling of a well bore from the bottom of the casing to a target depth for the completed bore; 
     for logging a producing formation, in which the production tubing string is retracted above the perforated zone so that a logging tool may be lowered to log the production zone; and 
     any downhole manipulation of tubulars or tools connected to tubing strings. 
     FIG. 9 is a cross-sectional view of a telescoping joint  10  with a latch assembly in accordance with the invention being used to tension a production tubing string in a well bore. A long production tubing string tends to sag under its own weight. This is disadvantageous if a surface-driven reciprocating pump is used to recover hydrocarbons from the well, as explained above. Such tubing strings  84  are anchored at their bottom end by an anchor member  86 , such as a packer connected to the bottom of the production tubing string  84 . A top of the production tubing string  84  includes the telescoping joint  10  and is connected to a tubing hanger, not shown, in a wellhead  88 . A lifting mechanism is temporarily installed on the wellhead  88  to enable the telescoping joint  10  to be retracted until the tubing string is under a desired tension to prevent undesirable sag as hydrocarbon is produced from the well. 
     The lift mechanism shown in FIG. 10 is preferably an apparatus for axially displacing a downhole tool or a tubing string in a well bore as described in applicant&#39;s co-pending U.S. Pat. No. 6,009,941, the specification of which is incorporated herein by reference. As shown in FIG. 11, the apparatus  90  is connected to a lift rod string  94  which runs through an annular seal  92  for containing well pressure and down through the wellhead  88  and the telescoping joint  10  to the latch point  38  (see FIG. 1) in step  100 . The lift rod string  94  connects to the latch point  38  to permit the production tubing string  84  to be raised or lowered as required when the production tubing string is suspended from the wellhead (step  102 ). When the bottom end of the production tubing string  84  is anchored by anchor member  86  (a packer, for example) to the casing of the well bore, the retraction of the telescoping joint  10  using the lift rod string  94  will tension the production tubing string  84  (step  104 ). When the production tubing string  84  is tensioned to a desired extent, the telescoping joint  10  is latched to an appropriate latch point (step  106 ), as described above. The lift rod string is then disconnected and removed (step  108 ). 
     The telescoping joint used for tensioning a production tubing string advantageously simplifies the conventional method in which a pup joint having a desired length has to be prepared to replace a top production tubing joint. As is well known, it is a time-consuming, expensive and potentially hazardous operation to determine a required length for the pup joint, and to install it. However, with a locking telescoping joint in accordance with the invention, the operation is quickly, easily and inexpensively done without removing the wellhead or danger of working over an open well bore. The locking telescoping joint  10  also permits the tubing string to be re-tensioned without removing the wellhead or killing the well if, over time, the tubing string loses its tension. 
     Another example of a new application for the telescoping joint is the use of the telescoping joint for setting a production tubing string under compression, the procedure for which is shown in FIG.  12 . This is desirable in circumstances when an economical compression packer is used to anchor a bottom of a production tubing string, as is common practice when hydrocarbons are produced using a submersible pump  96 . As described above with reference to FIG. 10, the telescoping joint  10  is included in the top of the production tubing string  84 , which is attached to a Tubing hanger (not shown) in the wellhead  88 . The apparatus  90  is mounted to the wellhead (step  110 ) and the lift rod string  94  is connected at the bottom end to the latch point  38  of the locking telescoping joint  10  (step  112 ). The apparatus  90  is operated to set the compression packer  86  and to release a recommended portion of the weight of the tubing string onto the compression packer (step  114 ). When a required portion of the tubing string weight is supported by the compression packer, the locking telescoping joint  10  is locked at an appropriate latch point (step  116 ) and the lift rod string is removed (step  118 ). 
     The locking telescoping joint  10  can also be used for other downhole operations which involve the selective repositioning or manipulation of tubing to set packers, plugs, subsurface safety valves or any other tool that includes a slip, collet, threaded or locking key or other locking or engagement device in the tubing string. Using the locking telescoping joint, such operations are quickly and easily accomplished without removing the wellhead or killing the well. Modifications to the preferred embodiments may occur to persons skilled in the art. For example, the telescoping joint  10  could designed to reciprocate under hydraulic pressure in wells having larger diameter casings. The hydraulically-powered cylinder could be equipped with hydraulic lines from the wellhead and be operated to reposition the downhole well tools without any lifting equipment on the surface. 
     Other modifications or variations may also become apparent to those skilled in the art. The scope of the invention is therefore intended to be limited solely by the scope of the appended claims.

Summary:
A locking telescoping joint is for use in a conduit connected to a wellhead, which permits the conduit to be axially displaced to a new position in the well bore without disconnecting the conduit from the wellhead, and secured in the new position. The locking telescoping joint includes two telescopically interconnected tubular sections which are relatively movable between a fully retracted and a fully extended position and can be locked in a desired position. In contrast with telescoping joints without the locking function which is useful to axially display downhole tools attached to the bottom end of the conduit. The locking telescoping joint enables the use of the telescoping joint to be extended into new applications, such as placing and maintaining a tubing string in tension or compression. The use of the locking telescoping joint reduces the time and cost of many well completion and maintenance operations and thereby reduces the cost of producing hydrocarbons.