A method of repairing tubulars downhole is described. A swage is secured to a force magnification tool, which is, in turn, supported by an anchor tool. Applied pressure sets the anchor when the swage is properly positioned. The force magnification tool strokes the swage through the collapsed section. The anchor can be released and weight set down on the swage to permit multiple stroking to get through the collapsed area. The swage diameter can be varied.

PRIORITY CLAIM 
   This application is a divisional application claiming priority from U.S. patent application Ser. No. 10/359,759, filed on Feb. 6, 2003, which claims the benefit of U.S. Provisional Application No. 60/356,061, filed on Feb. 11, 2002. 


   FIELD OF THE INVENTION 
   The field of this invention relates to techniques for repair of collapsed or otherwise damaged tubulars in a well. 
   BACKGROUND OF THE INVENTION 
   At times, surrounding formation pressures can rise to a level to actually collapse well casing or tubulars. Other times, due to pressure differential between the formation and inside the casing or tubing, a collapse is also possible. Sometimes, on long horizontal runs, the formation surrounding the tubulars in the well can shift in such a manner as to kink or crimp the tubulars to a sufficient degree to impede production or the passage of tools downhole. Past techniques to resolve this issue have been less than satisfactory as some of them have a high chance of causing further damage, while other techniques were very time consuming, and therefore expensive for the well operator. 
   One way in the past to repair a collapsed tubular downhole was to run a series of swages to incrementally increase the opening size. These tools required a special jarring tool and took a long time to sufficiently open the bore in view of the small increments in size between one swage and the next. Each time a bigger swage was needed, a trip out of the hole was required. The nature of this equipment required that the initial swage be only a small increment of size above the collapsed hole diameter. The reason that small size increments were used was the limited available energy for driving the swage using the weight of the string in conjunction with known jarring tools. Tri-State Oil Tools, now a part of Baker Hughes Incorporated, sold casing swages of this type. 
   Also available from the same source were tapered mills having an exterior milling surface known as Superloy. These tapered mills were used to mill out collapsed casing, dents, and mashed in areas. Unfortunately, these tools were difficult to control with the result being an occasional unwanted penetration of the casing wall. In the same vein and having similar problems were dog leg reamers whose cutting structures not only removed the protruding segments but sometimes went further to penetrate the wall. 
   What is needed and is an object of the invention is a method and apparatus to allow repair of collapsed or bent casing or tubulars in a single trip using an expansion device capable of delivering the desired final internal dimension. The method features anchoring the device adjacent the target area, using a force multiplier to obtain the starting force for expansion, and stoking the swage as many times as necessary to complete the repair. These and other advantages of the present invention will become clearer to those skilled in the art from a review of the detailed description of the preferred embodiment and the claims below. 
   SUMMARY OF THE INVENTION 
   A method of repairing tubulars downhole is described. A swage is secured to a force magnification tool, which is, in turn, supported by an anchor tool. Applied pressure sets the anchor when the swage is properly positioned. The force magnification tool strokes the swage through the collapsed section. The anchor can be released and weight set down on the swage to permit multiple stroking to get through the collapsed area. The swage diameter can be varied. 


   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIGS. 1   a – 1   d  show the anchor in the run in position; 
       FIGS. 2   a – 2   d  show the anchor in the set position; 
       FIGS. 3   a – 3   e  show the force magnification tool in the run in position; 
       FIG. 4  is a swage that can be attached to the force magnification tool of  FIGS. 3   a – 3   e.    
       FIGS. 5   a – 5   c  are a sectional elevation view of the optional adjustable swage shown in the run in position; 
       FIGS. 6   a – 6   c  are the view of  FIGS. 5   a – 5   c  in the maximum diameter position for actual swaging; 
       FIGS. 7   a – 7   c  are the views of  FIGS. 6   a – 6   c  shown in the pulling out position after swaging 
       FIG. 8  is a perspective view of the adjustable swage during run in; 
       FIG. 9  is a perspective view of the adjustable swage in the maximum diameter position; 
       FIG. 10  is a perspective view of the adjustable swage in the pulling out of the hole position. 
   


   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
   Referring to  FIG. 1   a , the anchor  10  has a top sub  12 , which is connected at thread  14  to body  16 . A rupture disc  20  closes off a passage  18 . At its lower end, the body  16  is connected to bottom sub  22  at thread  24 . Body  16  supports a seat  26  with at least one snap ring  28 . A seal  30  seals between body  16  and seat  26 . The purpose of seat  26  is to receive a ball  31  ( FIG. 1C ) to allow pressure buildup in passage  32  to break rupture disc  20 , if necessary. A passage  34  communicates with cavity  36  to allow pressure in passage  32  to reach the piston  38 . Seals  40  and  42  retain the pressure in cavity  36  and allow piston  38  to be driven downwardly. Piston  38  bears down on a plurality of gripping slips  40 , each of which has a plurality of carbide inserts or equivalent gripping surfaces  42  to bite into the casing or tubular. The slips  40  are held at the top and bottom to body  16  using band springs  44  in grooves  46 . The backs of the slips  40  include a series of ramps  48  that ride on ramps  50  on body  16 . Downward, and by definition outward movement of the slips  40  is limited by travel stop  52  located at the end of bottom sub  22 .  FIG. 2  shows the travel stop  52  engaged by slips  40 . The thickness of a spacer  54  can be used to adjust the downward and outward travel limit of the slips  40 . 
   Located below the slips  40  is closure piston  56  having seals  58  and  60  and biased by spring  62 . A passage  64  allows fluid to escape as spring  62  is compressed when the slips  40  are driven down by pressure in passage  34 . Closure piston  56  is located in chamber  57  with ratchet piston  59 . A ratchet plug  61  is biased by a spring  63  and has a passage  65  though it. A dog  67  holds a seal  69  in position against surface  71  of ratchet piston  59 . A seal  73  seals between piston  59  and bottom sub  22 . Area  75  on piston  59  is greater than area  77  on the opposite end of piston  59 . In normal operation, the ratchet piston  59  does not move. It is only when the slips  40  refuse to release and rupture disc  20  is broken, then pressure drives up both pistons  56  and  59  to force the slips  40  to release and the ratchet teeth  79  and  81  engage to prevent downward movement of piston  56 . Passage  65  allows fluid to be displaced more rapidly out of chamber  83  as piston  59  is being forced up. 
   Referring now to  FIG. 3 , the pressure-magnifying tool  66  has a top sub  68  connected to bottom sub  22  of anchor  10  at thread  70 . A body  72  is connected at thread  74  to top sub  68 . A passage  76  in top sub  68  communicated with passage  32  in anchor  10  to pass pressure to upper piston  78 . A seal  80  is retained around piston  78  by a snap ring  82 . Piston  78  has a passage  84  extending through it to provide fluid communication with lower piston  86  through tube  88  secured to piston  78  at thread  90 . Shoulder  92  is a travel stop for piston  78  while passage  94  allows fluid to move in or out of cavity  96  as the piston  78  moves. Tube  88  has an outlet  98  above its lower end  100 , which slidably extends into lower piston  86 . Piston  86  has a seal  102  held in position by a snap ring  104 . Tube  106  is connected at thread  108  to piston  86 . A lower sub  110  is connected at thread  112  to tube  106  to effectively close off passage  114 . Passage  114  is in fluid communication with passage  76 . Passage  116  allows fluid to enter or exit annular space  118  on movements of piston  86 . Shoulder  120  on lower sub  110  acts as a travel stop for piston  86 . A ball  122  is biased by a spring  124  against a seat  126  to seal off passage  128 , which extends from passage  114 . As piston  86  reaches its travel limit, ball  122  is displaced from seat  126  to allow pressure driving the piston  86  to escape just as it comes near contact with its travel stop  120 . Thread  130  allows swage body  132  (see  FIG. 4 ) to be connected to pressure magnifying tool  66 . 
   The illustrated swage  134  is illustrated schematically and a variety of devices are attachable at thread  130  to allow the repair of a bent or collapsed tubular or casing  136  by an expansion technique. 
   The operation of the tool in the performance of the service will now be explained. The assembly of the anchor  10 , the force magnifying tool  66  and the swage  134  are placed in position adjacent to where the casing or tubular is damaged. Pressure applied to passage  32  reaches piston  38 , pushing it and slips  40  down with respect to body  16 . Ramps  48  ride down ramps  50  pushing the slips  40  outwardly against the return force of band springs  44 . Inserts  42  bite into the casing or tubing and eventually slips  40  hit their travel stop  52 . Piston  56  is moved down against the bias of spring  62 . The pressure continues to build up after the slips  40  are set, as shown in  FIG. 2 . The pressure applied in passage  76  of pressure magnification tool  66  forces pistons  78  and  86  to initially move in tandem. This provides a higher initial force to the swage  134 , which tapers off after the piston  78  hits travel stop  92 . Once the expansion with swage  134  is under way, less force is necessary to maintain its forward movement. The tandem movement of pistons  78  and  86  occurs because pressure passes through passage  84  to passage  98  to act on piston  86 . Movement of piston  78  moves tube  88  against piston  86 . After piston  78  hits travel stop  92 , piston  86  completes its stroke. Near the end of the stroke, ball  122  is displaced from seat  126  removing the available driving force of fluid pressure as piston  86  hits travel stop  120 . With the pressure removed from the surface, spring  62  returns the slips  40  to their original position by pushing up piston  56 . If it fails to do that, a ball (not shown) is dropped on seat  26  and pressure to a high level is applied to rupture the rupture disc  20  so that piston  56  can be forced up with pressure. When piston  56  is forced up so is piston  59  due to the difference in surface areas between surfaces  75  and  77 . Ratchet plug  61  is pushed up against spring  63  as fluid is displaced outwardly through passage  65 . Ratchet teeth  79  and  81  lock to prevent downward movement of piston  56 . If more of casing or tubing  136  needs to be expanded, weight is set down to return the force-magnifying tool  66  to the run in position shown in  FIG. 3  and the entire cycle is repeated until the entire section is repeated to the desired diameter with the swage  134 . 
   Those skilled in the art can see that the force-magnifying tool  66  can be configured to have any number of pistons moving in tandem for achieving the desired pushing force on the swage  134 . Optionally, the swage can be moved with no force magnification. The nature of the anchor device  10  can be varied and only the preferred embodiment is illustrated. The provision of an adjacent anchor to the section of casing or tubular being repaired facilitates the repair because reliance on surface manipulation of the string, when making such repairs is no longer necessary. Multiple trips are not required because sufficient force can be delivered to expand to the desired finished diameter with a swage such as  134 . Even greater versatility is available if the swage diameter can be varied downhole. With this feature, if going to the maximum diameter in a single pass proves problematic, the diameter of the swage can be reduced to bring it through at a lesser diameter followed by a repetition of the process with the swage then adjusted to an incrementally larger diameter. Optionally the anchor  10  can also include centralizers  138  and  140 . A single or multiple cones or other camming techniques can guide out the slips  40 . Spring  63  can be a bowed snap ring or a coiled spring. Slips  40  can have inserts  42  or other types of surface treatment to promote grip into the casing or tubular. 
   Additional flexibility can be achieved by using flexible swage  138 .  FIG. 8  shows it in perspective and  FIGS. 5   a – 5   c  show how it is installed above a fixed swage  134 . The adjustable swage  138  comprises a series of alternating upper segments  140  and lower segments  142 . The segments  140  and  142  are mounted for relative, preferably slidable, movement. Each segment,  140  for example, is dovetailed into an adjacent segment  142  on both sides. The dovetailing can have a variety of shapes in cross-section, however an L shape is preferred with one side having a protruding L shape and the opposite side of that segment having a recessed L shape so that all the segments  140  and  142  can form the requisite swage structure for 360 degrees around mandrel  144 . Mandrel  144  has a thread  146  to connect, through another sub (not shown) to thread  130  shown in  FIG. 3   e  at the lower end of the pressure magnification tool  66 . The opening  148  made by the segments  140  and  142  (see  FIG. 8 ) fits around mandrel  144 . 
   Segments  140  have a wide top  150  tapering down to a narrow bottom  152  with a high area  154 , in between. Similarly, the oppositely oriented segments  142  have a wide bottom  156  tapering up to a narrow top  158  with a high area  160 , in between. The high areas  154  and  160  are preferably identical so that they can be placed in alignment, as shown in  FIG. 6   a . The high areas  154  and  160  can also be lines instead of bands. If band areas are used they can be aligned or askew from the longitudinal axis. The band area surfaces can be flat, rounded, elliptical or other shapes when viewed in section. The preferred embodiment uses band areas aligned with the longitudinal axis and slightly curved. The surfaces leading to and away from the high area, such as  162  and  164  for example can be in a single or multiple inclined planes with respect to the longitudinal axis. 
   Segments  140  have a preferably T shaped member  166  engaged to ring  168 . Ring  168  is connected to mandrel  144  at thread  170 . During run in a shear pin  172  holds ring  168  to mandrel  144 . Lower segments  142  are retained by T shaped members  174  to ring  176 . Ring  176  is biased upwardly by piston  178 . The biasing can be done in a variety of ways with a stack of Belleville washers  180  illustrated as one example. Piston  178  has seals  182  and  184  to allow pressure through opening  186  in the mandrel  144  to move up the piston  178  and pre-compress the washers  180 . A lock ring  188  has teeth  190  to engage teeth  192  on the fixed swage  134 , when the piston  178  is driven up. Thread  194  connects fixed swage  134  to mandrel  144 . Opening  186  leads to cavity  196  for driving up piston  178 . Preferably, high areas  154  and  160  do not extend out as far as the high area  198  of fixed swage  134  during the run in position shown in  FIG. 5 . The fixed swage  134  can have the variation in outer surface configuration previously described for the segments  140  and  142 . 
   The operation of the method using the flexible swage  138  will now be described. The assembly of the anchor  10 , the force magnifying tool  66 , the flexible swage  138  shown in the run in position of  FIG. 5 , and the fixed swage  134  are advanced to the location of a collapsed or damaged casing  133  until the swage  134  makes contact (see  FIG. 4 ). At first, an attempt to set down weight could be tried to see if swage  134  could go through the damaged portion of the casing  133 . If this fails to work, pressure is applied from the surface. This applied pressure could force swage  134  through the obstruction by repeated stroking as described above. If the fixed swage  134  goes through the obstruction, the flexible swage could then land on the obstruction and then be expanded and driven through it, as explained below. As previously explained, the slips  40  of anchor  10  take a grip. Additionally, pressure from the surface can start the pistons  78  and  86  moving in the force magnification tool  66 . Finally, pressure from the surface enters opening  186  and forces piston  178  to compress washers  180 , as shown in  FIG. 6   b . Lower segments  142  rise in tandem with piston  178  and ring  176  until no further uphole movement is possible. This can be defined by the contact of the segments  140  and  142  with the casing or tubular  133 . This contact may occur at full extension illustrated in  FIG. 6   b  or  9 , or it may occur short of attaining that position. The full extension position is defined by alignment of high areas  154  and  160 . Washers  180  apply a bias to the lower segments  142  in an upward direction and that bias is locked in by lock ring  188  as teeth  190  and  192  engage as a result of movement of piston  178 . At this point, downward stroking from the force magnification tool  66  forces the swage downwardly. The friction force acting on lower segments  142  augments the bias of washers  180  as the flexible swage  138  is driven down. This tends to keep the flexible swage at its maximum diameter for 360 degree swaging of the casing or tubular  133 . The upper segments do not affect the load on the washers  180  when moving the flexible swage  138  up or down in the well, in the position shown in  FIG. 6   a.    
   When it is time to come out of the hole it will be desirable to offset the alignment of the high areas  154  and  160 . When aligned, these high areas exceed the nominal inside diameter of the casing or tubing  133  by about 0.150 inches or more. To avoid having to pull under load to get out of the hole, the mandrel  144  can be turned to the right. This will shear the pin  172  as shown in  FIG. 7   a . Ring  168  will rise, taking with it the upper segments  140 . High areas  154  and  160  will be offset and at a sufficiently reduced diameter due to this movement to be brought out of the casing or tubing without expanding it on the way out. The reason the dimension on full alignment of high areas  154  and  160  exceeds the nominal casing or tubing inside diameter is that the casing or tubing  133  has a memory and bounces back after expansion. The objective is to have the final inside diameter be at least the original nominal value. Therefore the expansion with the flexible swage  138  has to go about 0.150 inches beyond the desired end dimension. The angled configuration of the segments, which interlock on a straight track allows the desired outer diameter variation and could be configured for other desired differentials between the smallest diameter for run in and the largest diameter for swaging. It should be noted that the swaging could begin at a diameter less than that shown in  FIG. 6   a  or  9 . The swaging diameter can grow as the swaging progresses due to the combined forces of washers  180 , friction forces on surfaces  164  and the condition of the casing or tubular  133 . 
   Those skilled in the art will appreciate that swaging can be done going uphole rather than downhole; if the flexible swage  138  shown in  FIG. 5  is inverted above the fixed swage  134 . The flexible swage  138  can be used in the described method or in other methods for swaging downhole using other associated equipment or simply the equipment shown in  FIG. 5 . The advantages of full 360 degree swaging at variable diameters makes the flexible swage  138  an improvement over past spring or arm mounted roller swages, which had the tendency to cold work the pipe too much and cause cracking. The collet type swages would not always uniformly extend around the 360 degree periphery of the inner wall of the casing or tubular causing parallel stripes of expanded and unexpanded zones with the potential of cracks forming at the transitions. The interlocking or side guiding of the segments  140  and  142  presents a more reliable way to swage around 360 degrees and provides for simple run in and tripping out of the hole. It can also allow for expansions beyond the nominal inside dimension, with the ability to trip out quickly while not having to do any expanding on the way in or out. 
   The foregoing disclosure and description of the invention are illustrative and explanatory thereof, and various changes in the size, shape and materials, as well as in the details of the illustrated construction, may be made without departing from the spirit of the invention.