Patent Publication Number: US-4258792-A

Title: Hydraulic tubing tensioner

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention is a tool for applying tension to a tubing string within a well bore. The tool or apparatus allows tension to be applied to the tubing string without the requirement for equipment to raise and lower the tubing string at the well surface. Also, methods are disclosed for using the tool to complete wells. 
     2. Description of the Prior Art 
     Most producing oil and gas wells have a well bore defined by a casing string and tubing disposed within the casing. A packer generally is used to seal between the tubing and casing and to direct formation fluid flow through the tubing to the well surface. 
     The tubing string is frequently placed in tension between the packer and the surface to minimize tubing buckling from pressure and temperature changes, to minimize contact between the tubing and a pump rod, and to allow unrestricted wireline operations through the tubing bore. Also, tension may be applied to the tubing to evenly distribute the weight of the tubing string between a tubing hanger at the well surface and the downhole packer. 
     Tension is commonly placed on the tubing string by engaging the lower end of the tubing with a packer previously installed downhole in the casing, raising the tubing by conventional drawworks until the desired tension is shown on a weight indicator and then setting slips to secure the tubing at the well surface. The sequence of spacing out the tubing at the well surface usually requires the use of one or more short sections of tubing called pup joints. Also, the surface blowout preventers must be removed for considerable lengths of time while installing the pup joints and setting the slips at the well surface. The present invention reduces the amount of tubing manipulation previously required at the well surface to place a tubing string in tension. The present invention can be used in various types of wells including oil and gas, steam and water injection, and geothermal wells. 
     U.S. Pat. No. 2,836,250 to C. C. Brown discloses a sleeve slidably disposed within a housing used to set a packer. Hydraulic fluid pressure acts on a piston carried by the sleeve to extend the sleeve relative to the housing forcing slips to engage the inner wall of the casing. U.S. Pat. No. 2,836,250 does not disclose nor teach using a sleeve and housing to apply tension to a tubing string. 
     SUMMARY OF THE INVENTION 
     The present invention discloses a tool or apparatus for applying tension to a tubing string, comprising: a housing with a longitudinal bore extending therethrough; means for attaching one end of the housing to a tubing string; a sleeve, slidably disposed within the longitudinal bore, having a longitudinal passageway therethrough and one end of the sleeve extending from said longitudinal bore, means for attaching the one end of the sleeve to a tubing string, means for sealing between the longitudinal bore and the sleeve to form a fluid chamber, a piston means carried on the exterior of the sleeve dividing the fluid chamber into two variable volume zones, the housing having a first port communicating the exterior of the housing with one of the variable volume zones, the sleeve having a second port communicating the longitudinal passageway with the other variable volume zone, and means for allowing the sleeve to move in one direction within the longitudinal bore and preventing movement of the sleeve in the other direction within the longitudinal bore. 
     One object of the present invention is to provide a tool for applying tension to a tubing string disposed with in a well. 
     Another object of the present invention is to provide a tubing tensioning tool which can apply tension to a tubing string by increasing the hydraulic fluid pressure within the tubing string. 
     Still another object of the present invention is to provide a hydraulic tubing tensioner which can apply tension to a tubing string communicating between two packers within a well. 
     A further object of the present invention is to disclose a method of applying tension to a tubing string within a well without having to use conventional draw works at the well surface. 
     Still a further object of present invention is to disclose a method for working over a well to install a dual hydraulic packer above a permanently installed packer and to place the tubing string between both packers in tension. 
     These and other objects and advantages of the present invention will become apparent from the following drawings, detailed description, and claims. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     FIGS. 1A and 1B (referred to as FIG. 1) are drawings, partially in section and elevation, showing a typical well installation using the present invention to apply tension to tubing between a surface tubing hanger and a downhole packer. 
     FIGS. 2A, 2B, 2C and 2D are drawings, partially in section, showing the hydraulic tubing tensioner of the present invention in its fully extended position. 
     FIGS. 3A, 3B, 3C, 3D and 3E are drawings, partially in section, showing the hydraulic tubing tensioner of the present invention in its partially retracted position. 
     FIG. 4 is a sectional view taken on line 4--4 of FIG. 3C. 
     FIG. 5 is a sectional view taken on line 5--5 of FIG. 3D. 
     FIG. 6 is a sectional view taken on line 6--6 of FIG. 3E. 
     FIG. 7 is a sectional view taken on line 7--7 of FIG. 3D. 
     FIGS. 8A and 8B are schematic drawings, partially in section, showing the present invention in a typical workover installation to apply tension to a tubing string between two packers downhole. 
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENT 
     Referring to the drawings and particularly to FIG. 1, the hydraulic tubing tensioner 20 of the present invention is shown as part of tubing string 21. The well completion or installation shown in FIG. 1 comprises wellhead 30 supported on casing string 31 and production packer 32 secured within casing 31 intermediate the ends thereof. 
     Packer 32 is used to provide fluid tight seals between casing 31 and the lower portion of tubing 21. Packer 32 directs formation fluids entering casing bore 33 below packer 32 to flow to the well surface through bore 22 of tubing 21. Various types of conventional packers are suitable for use with the present invention. One such packer is disclosed in U.S. Pat. No. 3,398,795 to T. L. Elliston. This type of packer is particularly desirable for use with tubing tensioner 20 because tubing string 21 can be engaged and disengaged from the packer in U.S. Pat. No. 3,398,795 as desired. Also, tension is used to securely anchor the packer within well casing. U.S. Pat. No. 3,398,795 is incorporated by reference for all purposes within this written description. 
     A typical tubing string may contain various well tools such as landing nipples, subsurface safety valves, and/or gas lift valves. These well tools could be added to tubing string 21 as desired. In addition to hydraulic tubing tensioner 20, tubing string 21 has a wireline releasable travel joint 23 and an expendable catcher subassembly 40. The operation and purpose of these two tools will be explained later. 
     Wellhead 30 is supported on casing 31 at the well surface. Surface tubing hanger 34 including slips 34a forms a part of wellhead 30 and engages the upper portion of tubing 21. As shown in FIG. 1, tubing 21 is partially supported by packer 32 and partially by surface tubing hanger 34. Wellhead 30 includes master valve 35 and swab valve 36 which control fluid communication with tubing 21. Wing valve 37 is provided to control flow from pressure source 38 to wellhead 30. 
     Hydraulic tubing tensioner 20 comprises housing 45 with threads 46 at one end providing a means for attaching housing 45 to tubing string 21. A longitudinal bore 47 extends through housing 45 with openings at either end thereof. Sleeve 48 is slidably disposed within bore 47 with one portion 48a extending from bore 47. The one portion 48a has threads 49 providing means for attaching one end of sleeve 48 to tubing string 21. 
     Sleeve 48 is generally cylindrical with its longitudinal axis concentric with the longitudinal axis of bore 47. Sleeve 48 also contains a longitudinal passageway 50 extending therethrough. Hydraulic tubing tensioner 20 is made up as a portion of tubing string 21 by attaching one end of sleeve 48 having threads 49 to tubing 21 and the opposite end of housing 45 to tubing 21 by threads 46. Fluid can communicate between the tubing attached above and below tensioner 20 via longitudinal passageway 50 in sleeve 48. 
     Seal means 51 are carried on the inside diameter of housing 45 within bore 47. The concentric arrangement of sleeve 48 within bore 47 forms an annulus between the outside diameter of sleeve 48 and the inside diameter of housing 45. Seal means 51 are in a fixed position relative to housing 45 and engage the outside diameter of sleeve 48 to form a fluid or piston chamber 52. Piston means 53 is carried on the exterior of sleeve 48 within fluid chamber 52. Piston seals 54, a part of piston means 53, form a fluid tight barrier with the inside diameter of housing 45. Piston means 53 with piston seals 54 attached is moveable with respect to housing 45 and divides chamber 52 into two variable volume zones 55 and 56. 
     First lateral ports 57 penetrate housing 45 to allow fluid communication between the exterior of housing 45 and variable volume zone 55. Second lateral ports 58 penetrate sleeve 48 to allow communication of fluid between longitudinal passageway 50 and variable volume zone 56. 
     Housing 45 contains a recess 59 spaced longitudinally from chamber 52. Slips 60 are secured within recess 59 which is part of longitudinal bore 47 and have teeth which are engageable with the exterior of sleeve 48. Slips 60 provide a means for allowing sleeve 48 to move in one direction within bore 47 and preventing movement of sleeve 48 in the other direction within bore 47. Therefore, when fluid pressure within longitudinal passageway 50 is higher than fluid pressure on the exterior of housing 45, the higher fluid pressure will be transmitted through ports 58 into variable volume zone 56 and applied to piston means 53. The pressure differential across piston means 53 will cause sleeve 48 to slide or contract longitudinally with respect to housing 45. The high pressure in variable volume zone 56 will move piston means 53 to displace any fluid within variable volume zone 55 to the exterior of housing 45 through ports 57. The teeth on slips 60 are aligned to allow movement of sleeve 48 in this one direction. if the fluid pressure within variable volume zone 55 was higher than fluid pressure within variable volume zone 56, sleeve 48 would attempt to move in the other direction. However, slips 60 would engage the exterior of sleeve 48 and prevent movement relative to housing 45. The use of internal slips 60 is disclosed in U.S. Pat. No. 3,398,795 to T. L. Elliston. 
     Various conventional well tools are available to temporarily seal or plug bore 22 of tubing 21 so that fluid pressure within longitudinal passageway 50 can be increased to any desired value. FIG. 1 shows one well tool, catcher subassembly 40, which can provide this function. 
     Catcher sub 40 is made up as part of tubing string 21 by threads 41 and 42. An expendable valve seat 43 is secured to the inside diameter of catcher sub 40 by shear pins 44. A suitable check valve member, such as ball 39, can be pumped through bore 22 of tubing 21 including longitudinal passageway 50 until ball 39 contacts valve seat 43. Ball 39 and seat 43 form a fluid tight barrier within tubing 21 so that fluid pressure within longitudinal passageway 50 can be increased. When the fluid pressure acting on ball 39 exceeds a preselected value, pin 44 will shear releasing seat 43 from the inside diameter of catcher sub 40. Ball 39 and seat 43 will then be expended out the lower end of tubing 21. The value at which pin 44 shears can be preselected such that the desired pressure buildup will occur within variable volume zone 56 to apply a preselected amount of force to sleeve 48 contracting sleeve 48 relative to housing 45. One way to prevent tensioner 20 from over stressing tubing 21 is by proper selection of shear pin 44. 
     During some well maintenance evolutions it may be desirable to release the tension applied to tubing 21 by tensioner 20. One such evolution might be to release tubing 21 from packer 32. Wireline releasable travel joint 23 is made up as part of tubing string 21. Travel joint 23 is shown in FIGS. 1 and 8A comprising an inner mandrel 24 which is attached to tubing string 21 at threads 25. An outer mandrel 26 is slidably disposed surrounding most of inner mandrel 24. Seals are provided to prevent fluid flow between the outside diameter of mandrel 24 and the inside diameter of mandrel 26. Inner mandrel 24 includes collet fingers 27 with collet heads 27a that can flex inwardly. Outer mandrel 26 has a rib 28 formed on its inside diameter which contacts collet heads 27a. Collet heads 27a engage rib 28 to hold travel joint 23 in its collapsed position. Collet cylinder 29 is slidably disposed within the bore of inner mandrel 24 and normally prevents collet fingers 27 from flexing inwardly. Collet cylinder 29 contains an internal profile 29a which can be engaged by a wireline tool (not shown) to shift cylinder 29 upward allowing collet fingers 27 to flex inward and release collet heads 27a from rib 28. Inner mandrel 24 and outer mandrel 26 can then telescope to their fully extended position. An enlarged portion 24a on inner mandrel 24 prevents the two mandrels from fully disengaging. A wireline releasable travel joint satisfactory for use with the present invention is shown in Otis Engineering Corporation Packers Catalog (OEC 5120A) page 48 published during 1978. 
     FIGS. 2A-2D and 3A-3E show a hydraulic tubing tensioner 70 in more detail. FIGS. 2A-2D show tensioner 70 with sleeve 71 extended relative to housing 72. FIGS. 3A-3E show tensioner 70 with sleeve 71 contracted relative to housing 72. Sleeve 71 and housing 72 are assembled from subassemblies for ease of manufacture. Subassemblies are designated with a letter following the number. 
     Housing 72 has seven subassemblies which are generally cylindrical and are attached to each other by threaded connections. Each subassembly has a longitudinal bore which comprises bore 47 within housing 72. Tubing connector subassembly 72a has threads 74 formed at one end to provide a means for attaching housing 72 to a tubing string. Adapter subassembly 72b joins connector sub 72a to fluid chamber subassembly 72c. Adapter subassembly 72b also carries seal mean 75a on its inside diameter to form a fluid tight seal with the exterior of sleeve 71. Adapter subassembly 72b includes shoulder 76 which projects into fluid chamber 52 to provide a mechanical stop limiting the travel of sleeve 71 in one direction relative to housing 72. 
     Fluid chamber subassembly 72c partially defines fluid or piston chamber 52. First lateral ports 57 penetrate subassembly 72c and communicate fluid between the exterior of housing 72 and variable volume zone 55. The inside diameter 77 of subassembly 72c is preferably a honed surface to provide a better fluid tight seal with piston means 80 carried by sleeve 71. Adapter subassembly 72d joins fluid chamber subassembly 72c to transition subassembly 72e and collar subassembly 72f. 
     Adapter subassembly 72d carries seal means 75b on its inside diameter to form a fluid tight seal with the exterior of sleeve 71. Fluid chamber or piston chamber 52 is defined by seal means 75a and 75b, the exterior of sleeve 71 and the inside diameter 77 of housing subassembly 72c. O-ring seals 78 are carried on the exterior of adapter subassembly 72d to form a fluid tight barrier with honed surface 77. Variable volume zone 56 is defined in part by piston means 80, seal means 75b, o-ring seals 78, inside diameter 77 and the exterior of sleeve 71. 
     Housing subassembly 72g connects collar subassembly 72f with alignment and slip subassembly 72h. Retainer means 90 is secured to the inside diameter of housing subassembly 72g by shear pin 91. Opening 124, penetrating the wall of housing subassembly 72g, receives pin 91. As best shown in FIG. 2D retainer means 90 has a shoulder 92 which can engage a matching shoulder 93 on sleeve 71 to prevent movement of sleeve 71 in the one direction relative to housing 72 until enough force has been applied to sleeve 71 to shear pin 91. FIGS. 3D and 5 show retainer means 90 released from housing subassembly 72g. 
     As best shown in FIG. 5, retainer means 90 comprises a cylindrical ring slidably disposed between sleeve subassembly 71b and housing subassembly 72g. Lateral bore holes 105 are provided to receive shear pins 91. 
     Alignment and slip subassembly 72h carries keys 94 and slips 95 within bore 47. Slips 95 have teeth 96 which allow movement of sleeve 71 in the one direction relative to housing 72 and prevents movement of sleeve 71 in the other direction. Sleeve 71 extends from housing 72 through opening 97 in subassembly 72h. 
     Sleeve 71 comprises four subassemblies with each subassembly joined by a threaded connection. Flow adapter subassembly 71a is an end fitting for main subassembly 71b. Flow adapter 71a minimizes flow turbulence and erosion while flowing formation fluids through longitudinal passageway 50. The exterior of main subassembly 71b is preferably a finished surface to provide a fluid tight barrier with seal means 75a and 75b. Piston means 80 is carried on an enlarged outside diameter portion 98 formed on the exterior of subassembly 71b. Enlarged portion 98 has two shoulders 99 and 100 formed thereon to secure piston means 80 to sleeve 71. Piston means 80 comprises piston ring 81 which is a generally cylindrical ring surrounding sleeve 71. The inside diameter of piston ring 81 has a shoulder 82 which matches shoulder 100 of enlarged portion 98. Seal means 83 are also carried on the inside diameter of piston ring 81 to prevent fluid flow between the exterior of sleeve 71 and the inside diameter of piston ring 81. Recess 84 is formed on the outside diameter of piston ring 81. Piston seals 85 are carried within the recess 84 and form a moveable fluid tight barrier with the inside diameter 77 of housing subassembly 72C. Piston cap 86 is a cylindrical ring which can be engaged with piston ring 81 at threads 88. Shoulder 87 is formed on the inside diameter of piston cap 86 and mates with shoulder 99 of sleeve 71. Thus, piston means 80 is secured to sleeve 71 by engaging enlarged portion 98 between shoulders 82 and 87 while connecting piston ring 81 with piston cap 86 at threads 88. Shoulder 89 is formed on the outside diameter of piston cap 86 to secure piston seals 85 within recess 84. Piston means 80 divides the piston chamber or fluid chamber 52 into two variable volume zones 55 and 56. 
     Second lateral ports 58 through main subassembly 71b communicate fluid between longitudinal passageway 50 and variable volume zone 56. Main subassembly 71b is attached to slip engaging subassembly 71d by collar subassembly 71c. Collar subassembly 71c provides shoulder 93 to engage retainer means 90 as previously described. 
     Subassembly 71d has keyways 102 formed in its outside diameter. As best shown in FIG. 6, keys 94 carried by housing subassembly 72h are engaged with keyways 102 of sleeve subassembly 71d to prevent rotation of sleeve 71 relative to housing 72. As previously noted, housing subassembly 72g is engaged by threads with housing subassembly 72h. For ease of manufacture, housing subassembly 72g extends into the bore of subassembly 72h as shown in FIG. 6. Two short, opposing longitudinal slots are cut in the lower portion of subassembly 72g which extends into subassembly 72h. Keys 94 are fitted into these slots as shown in FIG. 6. Therefore, when housing subassemblies 72g and 72h are engaged, keys 94 are prevented from rotating with respect to housing 72. Keys 94 and keyways 102 allow torque to be transmitted from the tubing attached above tensioner 70 to the tubing attached below tensioner 70. 
     Preferably, the outer surface 103 of sleeve subassembly 71d contains fine threads as best shown in FIGS. 2D and 3E. The fine threads allow slips 95 to securely engage outer surface 103 preventing movement of sleeve 71 in the other direction relative to housing 72. Threads 104 are formed on one end of sleeve subassembly 71d to provide a means for attaching sleeve 71 to a tubing string. 
     OPERATING SEQUENCE 
     Hydraulic tubing tensioner 70 is a tool or apparatus for applying tension to a tubing string. Tensioner 70 is made up as a portion of a tubing string by attaching the lower section of the tubing to sleeve 71 at threads 104 and the upper section of the tubing to housing 72 at threads 74. The tubing is initially installed within a well, having a casing string, in its fully extended position as shown in FIGS. 2A-2D. The tubing is secured within the well by suitable means such as packer 32 and tubing hanger 34 as shown in FIG. 1. The pressure of fluid within longitudinal passageway 50 can be increased after sealing the tubing bore with a means such as ball 39 and catcher subassembly 40. 
     The pressure of fluid within longitudinal passageway 50 is transmitted to variable volume zone 56 by second lateral ports 58. When fluid pressure in variable volume zone 56 exceeds the pressure of fluid (if any) in zone 55, piston means 80 will move expanding variable volume zone 56 and displacing fluid in zone 55 to the exterior of housing 72 through first lateral ports 57. This movement of piston means 80 causes sleeve 71 to contract or move longitudinally with respect to housing 72 in the one direction. With the ends of the tubing string secured as shown in FIG. 1, contraction of tensioner 70 causes tension to be applied to the tubing string. Slips 95 allow sleeve 71 to move in the one direction relative to housing 72. Slips 95 firmly engage the rough surface 103 to prevent movement of sleeve 71 in the other direction when pressure is released from variable volume zone 56. 
     The amount of tension applied to a tubing string can be limited by controlling the pressure within passageway 50. The maximum amount of tension is determined by the distance or stroke between piston means 80 and stop shoulder 76 when tensioner 70 is fully extended. By selecting the proper stroke length versus tubing length, it is possible to ensure that the tubing will not be over stressed by tensioner 70. 
     During some well conditions such as high formation pressure or high hydrogen sulfide concentration in the formation fluids, it is desirable to minimize the number of operations and the length of time requiring removal of the blowout preventers (not shown) while completing the well. 
     For an oil gas well such as FIG. 1, tubing 21 is installed within casing 31 through blowout preventers. The use of blowout preventers with various combinations of rams is well known. One method of applying tension to a tubing string and spacing out the tubing consists of securing the lower end of the tubing string to the casing by means such as packer 32. Conventional draw works (not shown) are used to raise the tubing until the weight indicator shows that the desired amount of tension has been placed on the tubing string. The blowout preventers are removed and the tubing marked at the location of the surface tubing hanger. The mark is usually intermediate the ends of a section of tubing. Therefore, one or more pup joints are required to extend from the last full joint or section of tubing to the surface tubing hanger. 
     After marking the tubing, the tubing is then raised to allow removal of the section of tubing having the mark. Pup joints equivalent to the length from the lower end of the removed section of tubing to the mark are installed and standard lengths of tubing attached to the top of the pup joints. The tubing string is then lowered into the well and secured to the casing at packer 32. The tubing string is raised until the desired tension is shown on the weight indicator (not shown). If the mark was properly made and the pup joints properly measured, the top of the upper pup joint should be level with the surface tubing hanger 34. The surface tubing hanger slips 34a are set to engage the tubing string. The tubing attached above the pup joints is removed and the wellhead installed to establish positive pressure control of th9e well. With the above procedure, the blowout preventers are removed while spacing out. Tensioner 20 or tensioner 70 would reduce the time between removal of the blowout preventers and connection of wellhead 30. Tensioner 20 and/or tensioner 70 significantly minimizes the tubing handling requirements. 
     Packer 32 is installed intermediate the ends of casing 31 at a preselected distance from the well surface. Tubing string 21 including expendable catcher subassembly 40, hydraulic tubing tensioner 20 and wireline releasable travel joint 23 is lowered into bore 33 of casing 31 through blowout preventers (not shown). The lower portion of tubing 21 is secured to packer 32 by J-latch 110. The blowout preventers are removed and the tubing string raised or lowered until the top of a full joint of pipe or section of tubing is at the surface tubing hanger. For long lengths of tubing strings, movement of one section of tubing is possible without over stressing the tubing. Slips 34a of the surface tubing hanger are then secured to the top end of the full section of tubing and wellhead 30 including master valve 35 and swab valve 36 installed. Wellhead 30 provides for positive well fluid pressure control. Wing valve 37 can be opened to admit fluid pressure to bore 22 of tubing 21. If ball 39 is engaged with valve seat 43, pressure in longitudinal passageway 50 can be increased to a preselected value. As previously described, fluid pressure in passageway 50 causes tensioner 20 to contract applying tension to tubing 21. At a preselected pressure, pin 44 will shear releasing seat 43 and ball 39 limiting the amount of tension applied to tubing 21. 
     Hydraulic tubing tensioner 20 can also be used to apply tension to tubing under conditions when normal methods are not available. FIGS. 8A and 8B illustrate such a use for tensioner 20. 
     Packer 111 is installed within casing 31 above producing formation 112 and perforations 113. Tubing string 114 is secured within packer 111 and extended only a limited distance above packer 111. Tubing 114 may have failed at this point from corrosion and wear or may have been purposely cut off to facilitate recompletion of the well for dual production tubing strings. 
     A dual completion tubing string is shown being lowered into the well comprising dual production packer 115 with a short tubing string 116 and a long tubing string 117. Short tubing string 116 will allow formation fluids entering the bore of casing 31 between packer 111 and dual packer 115 to flow to the well surface. Long tubing string 117 comprises wireline releasable traveling joint 23, tensioner 20, expendable catcher subassembly 40 and a packoff overshot or overshot connector 118. U.S. Pat. No. 3,865,408 discloses an overshot connector satisfactory for use with the present invention. U.S. Pat. No. 3,865,408 is adopted by reference for all purposes. 
     The dual tubing string is lowered into the well until overshot 118 engages tubing 114 and forms a fluid tight seal with the exterior of tubing 114. Dual production packer 115 can then be secured to casing 31 by applying hydraulic fluid pressure to short tubing string 116 from the well surface. A modified catcher subassembly 40a is provided to allow pressure buildup to a preselected value within short tubing string 116. After dual packer 115 has been set, fluid pressure can be applied to tubing string 117 from the well surface to contract hydraulic tubing tensioner 20. The section of tubing joining packer 111 and dual packer 115 can thus be placed in tension. 
     Alternatively, dual packer 115 could be initially anchored to casing 31 by the contraction of tensioner 20. As shown in FIG. 8A, tension on tubing 117 below packer 115 can be transmitted to cone 119 forcing slips 120 on packer 115 radially outward into contact with casing 31. Dual hydraulic production packers which are set by either the long string or short string are generally available. In this alternative method, packer 115 is set at the same time as tensioner 20 is being contracted. 
     The previously described hydraulic tubing tensioner can be readily adapted for use in various wells. The previous description is illustrative of only two embodiments of the presents invention and methods of using the invention. Changes and modifications will be readily apparent to those skilled in the art and may be made without departing from the scope of the invention which is defined in the claims.