Patent Publication Number: US-6986390-B2

Title: Expandable packer with anchoring feature

Description:
PRIORITY INFORMATION 
   This application is a divisional application of Ser. No. 10/301,229, filed on Nov. 21, 2002, which was a continuation-in-part of prior U.S. application Ser. No. 10/117,521, filed on Apr. 5, 2002, which claims the benefit of U.S. Provisional Application No. 60/344,314 filed on Dec. 20, 2001. 

   FIELD OF THE INVENTION 
   The field of this invention relates to packers and more particularly to packers that can be set by expansion and more particularly incorporating an anchoring feature to engage the surrounding tubular upon physical expansion of the packer. 
   BACKGROUND OF THE INVENTION 
   Traditional packers comprised of a sealing element having anti-extrusion rings on both upper and lower ends and a series of slips above or/and below the sealing element. Typically a setting tool would be run with the packer to set it. The setting could be accomplished hydraulically due to relative movement created by the setting tool when subjected to applied pressure. This relative movement would cause the slips to ride up cones and extend into the surrounding tubular. At the same time, the sealing element would be compressed into sealing contact with the surrounding tubular. The set could be held by a body lock ring, which would prevent reversal of the relative movement, which caused the packer to set in the first instance. 
   As an alternative to pressure through the tubing to the setting tool to cause the packer to set, another alternative was to run the packer in on wire line with a known electrically operated setting tool such as an E-4 made by Baker Oil Tools. In this application, a signal fires the E-4 causing the requisite relative movement for setting the packer. Some of these designs were retrievable. A retrieving tool could be run into the set packer and release the grip of the lock ring so as to allow a stretching out of the slips back down their respective cone and for the sealing element to expand longitudinally while contracting radially so that the packer could be removed from the well. 
   In the past, sealing has been suggested between an inner and an outer tubular with a seal material in between. That technique, illustrated in U.S. Pat. No. 6,098,717, required the outer tubular or casing to be expanded elastically and the inner tubular to be expanded plastically. The sealing force arose from the elastic recovery of the casing being greater than the elastic recovery of the inner tubular, thus putting a net compressive force on the inner tubular and the seal. Other expansion techniques, described in U.S. Pat. Nos. 5,348,095; 5,366,012; and 5,667,011 simply related to expansion of slotted tubulars, serving as a liner in open hole, as a completion technique. U.S. Pat. No. 4,069,573 illustrates the use of expansion to form a tubular casing patch. 
   The present invention relates to construction features and methods of employing packers that can be expanded into sealing position. The surrounding tubular does not need to be expanded to set the packer of the present invention. Rather, an anchor such as slips is used to support the expanded sealing element and hold it in a set position. Preferably, existing setting tools, with minor modifications can be used to expand the packer of the present invention. Similarly releasing tools can be employed to remove the packer from its set position. The running string can be exposed to lower pressures than the packer through the use of pressure intensifiers. The expansion force can be pinpointed to the area of the packer, thus avoiding subjecting the formation or the running string to undue pressures during setting of the packer. Alternatively, the inner tubular may simply be an anchor for another tool or a liner string. The anchoring can be ridges on the exterior of the inner tubing directly or on a ring mounted over the inner tubular being expanded. The ring can be slotted to reduce the required expansion force. The slips are retained to the mandrel by undulating mating surfaces. The grip area is enlarged to reduce stress on the tubular. Features are included to help hold the set on shifting load conditions and to augment the applied force on the sealing element. A variety of potential applications are illustrated. 
   The setting tool can be delivered through tubing on slick line or wire line or run into the well on rigid or coiled tubing or wire line, among other techniques. The release tool can be likewise delivered and when actuated, stretches the packer or anchor out so that it can be removed from the wellbore. Conventional packers, that have their set held by lock rings, can be released with the present invention, by literally pushing the body apart as opposed to cutting it downhole as illustrated in U.S. Pat. No. 5,720,343. 
   These and other advantages of the present invention will be more readily understood from a review of the description of the preferred embodiment, which appears below. 
   SUMMARY OF THE INVENTION 
   An expandable packer or anchor is disclosed. It features a gripping device integral to or mounted in a sleeve over the mandrel and mating undulating surfaces to help maintain grip under changing load conditions. Upon expansion, pressure on a sealing element is enhanced by nodes to increase internal pressure as it engages an outer tubular. Adjacent retaining rings limit extrusion and enhance grip. A gripping device, such as wickers on slips, preferably digs into the outer tubular. The expansion is preferably by pressure and can incorporate pressure intensifiers delivered by slick line or wire line. Release is accomplished by a release tool, which is delivered on slick line or wire line. It stretches the anchor or packer longitudinally, getting it to retract radially, for release. The release tool can be combined with packers or anchors that have a thin walled feature in the mandrel, to release by pulling the mandrel apart. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a section through the packer of the present invention in the run in position; 
       FIG. 2  is the view of  FIG. 1  with the packer in the set position; 
       FIG. 3  is an outside view of the packer showing the slips on a ring with recesses; 
       FIGS. 4   a – 4   d  show the packer schematically prior to expansion using a pressure intensifier; 
       FIGS. 5   a – 5   d  show the packer of  FIGS. 4   a – 4   d  in the set position with the through tubing pressure intensifier removed; 
       FIGS. 6   a – 6   b  show schematically how force is to be applied to release the packer; 
       FIGS. 7   a – 7   b  show the released position of the packer after applying the forces shown in  FIGS. 6   a – 6   b;    
       FIGS. 8   a – 8   b  show one version of a release tool for the packer where the release tool is tubing delivered to latch to the top of the packer; 
       FIGS. 9   a – 9   b  show a through tubing release tool, which can be delivered on wire line or slick line; 
       FIGS. 10   a – 10   d  show a packer with a mandrel having a thin wall segment with a release tool inserted through tubing and the packer in the set position; 
       FIGS. 11   a – 11   d  show the packer of  FIGS. 10   a – 10   d  in the released position. 
       FIGS. 12   a – 12   e  show the packer run in with a wire line or hydraulic setting tool in the run in position; 
       FIGS. 13   a – 13   e  show the packer of  FIGS. 12   a – 12   e  in the set position with the setting tool released; 
       FIG. 14  is a section view during run in of a preferred embodiment showing the nodes under the sealing element and the undulating surface contact for the 
       FIG. 15  is the view of  FIG. 14  in the expanded and set position; 
       FIG. 16  is a variation of the packer shown in the set position in  FIG. 15  showing a line or conductor through its body; 
       FIG. 17  is a section view of a prior art packer in the run in position showing the relatively short slip length involved, which leads to a greater stress on the surrounding tubular; 
       FIG. 18  is the packer in  FIG. 17  in the set position; 
       FIG. 19  is a section view in the set position of the packer of the present invention showing the longer slip lengths leading to a reduced stress on the surrounding tubular; 
       FIG. 20  shows the use of the packer of the present invention when drilling out a plug; 
       FIG. 21  is the view of  FIG. 20  after the plug is drilled out; 
       FIG. 22  is the view of  FIG. 21  after the bit is released; 
       FIG. 23  is the view of  FIG. 22  with the packer expanded to the set position; 
       FIG. 24  is a section view of an application of the packer of the present invention to a liner top isolation packer next to a liner hanger; 
       FIG. 25  shows a set packer having an interior plug; 
       FIG. 26  is the view of  FIG. 25  showing running in with a string with a seal, a retrieving tool and a sinker bar; 
       FIG. 27  shows the plug being knocked out and the seals landed in the packer; 
       FIG. 28  shows the retrieving tool releasing the packer by stretching it; 
       FIGS. 29   a–b  are a section view of a one-trip packer with pressure intensifier in the run in position; 
       FIGS. 30   a – 30   b  are the packer of  FIGS. 29   a – 29   b  in the set position; 
       FIGS. 31   a – 31   b  are the packer of  FIGS. 30   a – 30   b  shown in the ball released position; 
       FIG. 32  shows a latching grove for a slick line plug used as an alternative to setting the packer; 
       FIG. 33   a – 33   e  is an alternative embodiment showing an internal recess on the slips against a cylindrical expansion mandrel, in the run in position; 
       FIGS. 34   a – 34   e  are the view of  FIGS. 33   a – 33   e  in the set position; and 
       FIGS. 35   a – 35   f  are the view  FIGS. 34   a – 34   e  in the ball release position. 
   

   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
   Referring to  FIG. 1 , the packer P has a mandrel  10  with an upper thread  12  and a lower thread  14 . Upper slip ring  16  attaches at thread  12  and has extending slips  18 . As shown in  FIG. 3 , slips  18  are fingers of preferably metal separated by slots  34 . One purpose of the slots  34  is to decrease resistance to expansion. Another is to allow the wickers  32  to be hardened. If the slips were to be continuous and have hardened wickers  32 , the brittleness would cause the slips to crack on expansion. Lower slip ring  20  attaches at thread  14  and has finger like slips  22  extending from it. Slips  18  and  22  each have wickers or some other surface sharpness  32  designed to dig in for a supporting bite into the casing C upon expansion of the mandrel  10 . A sealing element  24  having backup rings  26  and  28  is disposed between slips  18  and  22 . Those skilled in the art will appreciate that the slips  18  and  22  can be formed as an integral part of the mandrel, thus eliminating the threads  12  and  14  as well as the rings  16  and  20 . In that event, the slips  18  and  22  can be a series of finger shaped protrusions from the outer surface of the mandrel  10 . These protrusions can be integral, welded, or attached in some other way. Although a packer has been described, the sealing element  24  can be eliminated and the slips  18  and  22 , regardless of how they are attached, can be used to anchor a tubing string (not shown) or a tool (not shown) attached to the mandrel  10 , when the wickers  32  dig into the surrounding casing C. Conceivably, the expansion of the wickers  32  into the casing or outer tubular C can accomplish not only a support function but also a sealing function. Sealing is possible without having to appreciably expand the casing C or even without expanding the casing C at all. The invention can be effective with a single or multiple rings of slips, regardless of their attachment mode, and with a variety of known designs for the sealing element  24 . 
   The clear advantage of the present invention is that cones are not required to drive the slips outwardly. This means that for a given outside diameter for run in, the packer or anchor P of  FIG. 1  will have a larger internal bore diameter than a design relying on cones to ramp slips out. The larger bore possible in the mandrel  10  comes with no significant reduction of the pressure rating of the packer P. 
   The wickers  30  and  32  are preferably hardened to facilitate penetration into the casing. The sealing element  24  is preferably Nitrile but can also be made from other materials such as Teflon or PEEK. The backup rings  26  and  28  are preferably ductile steel and serve the function of keeping the sealing element  24  out of the slots  34  between the slips  18  and  22 . Rather than slots  34  to facilitate expansion of the slips  18  and  22 , the sleeve that holds the slips can be made thinner or have other openings, such as holes, to reduce its resistance to expansion. The expansion itself can be carried out with known expansion tools such as roller expanders, swages, or cones. Alternatively, an inflatable can be used to expand the mandrel  10  or a pressure technique, as illustrated in  4   a – 4   d ,  5   a – 5   d ,  12   a – 12   e , and  13   a – 13   e.    
     FIGS. 4   a – 4   d  illustrate a thru-tubing approach to setting where either a slick line or a wire line can be used to deliver a pressure intensifier  36  to a desired position where it will latch in the tubing  37  adjacent the packer or anchor P. The packer or anchor P is illustrated schematically as is the connection at the top of the intensifier  36 . Pressure applied into tubing  37  enters ports  39  and  40 . Pistons  42 ,  44 , and  46  are connected together for tandem movement. Pressure from ports  39  and  40  enters cavities  48  and  50  to apply downward forces on pistons  42 ,  44 , and  46 . Additional pistons can be used for greater force amplification. The use of intensifier  36  allows a lower pressure to be used at the wellhead in case it has a low pressure rating and the expansion force desired at the packer or anchor P exceeds the rated wellhead pressure. Downhole movement of piston  46  forces fluid out of port  52  to expand the packer or anchor P. The intensifier  36  is retrieved after expansion with a known fishing tool, which engages a fishing neck in the top of the intensifier. As shown in  FIGS. 5   a – 5   d , the packer or anchor P is set against tubular or casing C and the intensifier is removed from the tubing  37 . 
   Another way to deliver and set the packer or anchor P is shown in  FIGS. 12   a – 12   e  and  13   a – 13   e . In these figures the packer or anchor P is delivered on a hydraulic or wire line setting tool, as opposed to the through-tubing techniques previously described. The setting tool is schematically illustrated to cover the use of both hydraulic or wire line setting. A sleeve  54  abuts the top of the packer or anchor P ( FIG. 12   d ). A gripping sleeve  56  retains the packer or anchor P until the shear stud  58  fails. Circulation is possible when using the hydraulic setting tool until an object is dropped to allow pressure buildup to ultimately move piston  60  to set the packer or anchor P. Upward movement of the piston  60  breaks the shear stud  58  after delivering the required pressure for expansion through port  62  to the packer or anchor P. The hydraulic setting tool can incorporate pressure intensifiers so as to limit the surface pressure applied to get the desired expansion, in the event the wellhead has a low pressure rating. Breaking the shear stud  58  allows removal of the setting tool and a subsequent tagging the packer with production tubing. The pressure intensifier can have more or fewer pistons to get the desired pressure amplification. Hydrostatic pressure can be employed to do the expanding instead of or in conjunction with surface applied pressure. Various ways can be used to connect the tubing to the packer. The expansion tool can be released from the packer by rotation. Known setting tools can be employed such as those made by Baker Oil Tools under model numbers BH, BHH, B-2 and J with only slight adaptations. 
   In a wire line variation, the setting tool would be electrically actuated to set off an explosive charge to create the needed pressure for expansion of the packer or anchor P in the manner previously described with the possibility of integrating a pressure intensifier. Once the packer or anchor P is expanded, an automatic release from the setting tool occurs so that it could be removed. Known wire line setting tools like the E-4 made by Baker Oil Tools can be used, or others. The expansion concept is the same, stroking a piston with a pressure source and, if necessary a pressure intensifier, creates the pressure for expansion of the packer or anchor P to expand it into position against the tubular or casing C and to trigger an automatic release for retrieval of the settling tool. After the setting tool is pulled out, tubing is tagged into the expanded packer or anchor. 
   Release of the packer or anchor P is schematically illustrated in  FIGS. 6   a – 6   b . The technique is longitudinal extension as illustrated by opposed arrows  64  and  66 . This longitudinal extension results in radial contraction, shown schematically as arrow  68 . What actually occurs is that the wickers  30  and  32  (shown in  FIG. 1 ), which had dug into the casing C on expansion, are pulled or sheared out of the casing. The longitudinal extension also draws back the sealing element  24  as the mandrel under it radially contracts.  FIGS. 7   a – 7   b  show the released position. 
   One way to accomplish the release as described above is shown in  FIGS. 8   a – 8   b . The release tool  70  is run into the well after the production tubing is pulled. It is secured downhole to the packer at connection  72 , which can be a variety of configurations. A ball seat  74  is retained by shear pins  76  and accepts a ball  78  dropped from the surface. Built up pressure pushes down of piston  80  and piston  82  through port  84 . Piston  80  bears down on piston  82 . Piston  82  bears on shoulder  86  on the packer or anchor P. Thus the packer or anchor P is subjected to a longitudinal extension from an uphole force at connection  72  and a downhole force at shoulder  86 . The resulting radial retraction allows removal of the packer or anchor P with the tubing  72 . 
     FIGS. 9   a – 9   b  show a thru-tubing variation of the release technique. The release tool  88  can be run in on slick line or wire line to latch into latch  90 . Pressure is developed on pistons  92 ,  94 , and  96 . Ports  98  and  100  allow access to pistons  94  and  96  respectively. Piston  92  bears on piston  94 , which in turn bears on piston  96 . Piston  96  rests on shoulder  102  on the anchor or packer P while the other end of the release tool  88  is latched at latch  90 . Ports  104  and  106  allow pistons  92  and  94 , respectively to move by allowing fluid to pass. Accordingly, applied pressure in tubing  108  or generated pressure from an electric line setting tool such as an E-4 made by Baker Oil Tools, stretches the packer or anchor P to get the slips  18  and  22  (see  FIG. 1 ) to let go of their grip of the tubular or casing C in the manner previously described. 
     FIGS. 10   a – 10   d  and  11   a – 11   d  show a packer of known construction except that it has a narrow portion  110  in its mandrel  112 . It has a sealing element  114  and slips  116  extendable with cones  118  and  120 . A lock ring  122  holds the set. In the past, the packer could be released by releasing the lock ring by cutting the mandrel of the set packer downhole, as illustrated in U.S. Pat. No. 5,720,343. However this technique had its uncertainties due to doubts about placement of the cutter and knowledge as to if the cut was completed. The release technique for such packers of the present invention, removes such uncertainties. The release tool  122  can be run thru tubing on slick line or wire line and latched at latch  124 . A pressure intensifier  126  of the type previously described rests on shoulder  128  of the packer or anchor P. Application of pressure from the surface or the electric line tool puts opposing forces at latch  124  and shoulder  128  until the narrow portion  110  fails in tension. This releases the hold of the set position by the lock ring  122  and allows extension and radial retraction of the slips  116  and the sealing element  114 . The break  130  is shown in  FIG. 11   d . If there are multiple packers or anchors P in the well, the process can be repeated for each one that needs release. As well, the setting process can be repeated to set in any order desired, other packers or anchors P to isolate a desired zone for example. The release tool can be delivered through the production tubing or on wire line or slick line after the production tubing has been removed. After release, the release tool can drop the tool just released or it can stay with it and allow the released tool to be removed to the surface. 
   Other downhole tools can be expanded and extended for release in the manner described above other than packers or anchors. Some examples are screens and perforated liners. 
   The techniques described above will also allow for expansion and extension of a variety of tools more than a single time, should that become necessary in the life of the well. Extension of the downhole tool for release does not necessarily have to occur to the extent that failure is induced, as described in conjunction with  FIGS. 10 and 11 . The extension of a tool such as the packer or anchor P an embodiment of which is shown in  FIG. 1 , can allow it to be re-expanded with the variety of tools described above. 
   Tubing itself can also be expanded and extended for release using the techniques described above. 
   Although the retrieving tool has been illustrated as abutting a shoulder to obtain the extension, the shoulder can be provided in a variety of configurations or can be replaced with a gripping mechanism such as slips on the release tool. The slips could alternatively replace the latching notch while still putting a downhole force on the lower shoulder. The mandrel can also have an undercut and collets can engage the undercut to put the requisite extension force on the mandrel body. 
   Selected zones can be isolated or opened for flow with the techniques previously described. Pressure intensifiers of various designs and pressure magnifications can be used or, alternatively, no pressure magnification device can be used. 
   If the through-tubing tool is used with the explosive charge as the pressure source, then it will need to be removed and the charge replenished before it is used to expand another device in the well. The hydraulically operated through-tubing tool can simply be repositioned and re-pressurized to expand another downhole packer, tubular or other tool. 
   The various forms of the release tools can be used with conventional packers that set with longitudinal compression of a sealing element and slips with the set held by a lock ring by extending that packer to the point of mandrel or other failure, which can release the set held by the lock ring. 
   Referring now to  FIG. 14 , a preferred embodiment of the packer P is illustrated. The mandrel  150  has an undulating surface  152  defining peaks  154  and adjacent valleys  156 . The peaks  154  and valleys  156  can be rounded, blunt or may define a sharp angle, although a slight radius is preferred. Slips  158  and  159  straddle the sealing element  162 . Slips  158  and  159  each have an undulating surface  160 , which matches undulating surface  152 . The number and height of the undulations can be varied to meet the expected performance conditions for the packer P. Because of the slant orientation of the undulations  152  and  160  a net force from uphole acting in a downhole direction (or vice versa), represented by arrow  161  in  FIG. 15 , will create a radial component force acting on the slips  158  and  159  whose size depends on the size of the net force acting uphole or downhole and the angle of the mating surfaces of undulations  152  and  160 . The resultant force is shown by arrow  163  and it has a radial component shown by arrow  165  and a longitudinal component shown by arrow  167 . 
   The sealing element  162  has nodes such as  164  and  166  under it. These nodes are protrusions from the mandrel  150 . They act to increase the internal pressure in the sealing element  162  so that it retains sealing contact despite load direction or load size changes. Augmenting the increase in internal seal pressure that is caused by one or more nodes such as  164  and  166  are anti-extrusion rings  168  and  170  that are mounted above and below the sealing element  162 . As seen in section in  FIG. 15 , the rings  168  and  170  have sloping surfaces  172  and  174  respectively to engage slips  158  and  159 , respectively to help push out close wickers  176  and  178 . The close wickers  176  and  178  are closer to rings  168  and  170  to insure that the rings  168  and  170  are firmly positioned to prevent extrusion of element  162  despite changing loads amounts or load direction. At the same time, the internal pressure in the sealing element  162  working against rings  168  and  170  pushes their respective sloping surfaces  172  and  174  under slips  158  and  159  so as to enhance the bite of not only the close wickers  176  and  178  but also the remaining wickers  180  and  182 . 
     FIG. 16  illustrates the use of a tube or line  184  to carry signal lines or fluid pressure to locations beyond the packer P. Line  184  runs outside the mandrel  150  and through the sealing element  162  and between sets of slips such as  158  or  159 . Line  184  can alternatively run through a portion of the body of mandrel  150 . Fiber optic or electric lines can be run in line  184  to control downhole equipment or gather data from below the packer P. 
     FIGS. 17 and 18  show the limitation of prior art systems in the ability to radially load the slips. Sloping surfaces  186  and  188  on cones  190  and  192  have limited contact with slips  198  and  200 . As seen in  FIG. 18  that contact is limited between points  194  and  196  of surface  188 , for example. The spacing between the points  194  and  196  can&#39;t be increased because the taper angle must stay in a preferred range to transmit sufficient radial force to a slip such as  192  and making the spread between points  194  and  196  longer can effectively be done at the expense of decreasing the internal bore of the packer for a given exterior run in dimension. Accordingly, the prior art packers set by relative longitudinal movement, whether initiated by mechanical force or hydraulic pressure were limited in the length of the slips  198  and  200  to which radial loading could be applied. This limitation forced higher stresses to be applied to the tubular against which the slips  198  and  200  were actuated. The packer P of the present invention solves this problem using the expansion technique. As shown in  FIG. 19 , mandrel  150  expands below a slip such as  158  by applying a radial force between points  202  and  204 , with point  204  being on surface  172  of ring  168 . This spacing between points  202  and  204  can be as long as desired and much longer than the design parameters of the prior art designs illustrated in  FIGS. 17 and 18  would allow. As a result, the desired contact force is applied over a substantially grater contact area, extending to a substantial portion of the length of longer slips, to greatly reduce the stress applied to the surrounding tubular or the formation if in open hole. As previously stated, in a cased hole, for example, the surrounding tubular need not be deformed as the wickers such as  176 – 182  dig in for a bite. The present invention allows for the use of more wickers to decrease the stress on the tubular from the penetration. Even if all the wickers bottom into the surrounding tubular, the resulting stress is reduced, when compared to the prior art, because the contact area over which radial force is transmitted has been dramatically increased. The radial load can be applied to over 90% of the length of the slips that can be used in any desired length. 
     FIGS. 20–23  show an application of the packer P to drilling out a well plug  206  with a bit  208 , with the packer P mounted right above on the drill string  210 . After the plug is drilled out the annulus  212  can be isolated when the packer P is expanded. In  FIG. 21 , the plug  206  is fully milled out. In  FIG. 22 , the bit  208  is released. In  FIG. 23 , the packer P is expanded into contact with the wellbore W, isolating the annulus  212  around the drill string  210 . Production can start through string  210  with the annulus  212  sealed off by packer P. The advantage is the robustness of the packer to allow cuttings to be circulated around it. The prior art technique dispensed with annulus isolation and allowed communication into annulus  212  as the well was produced into string  210 . In gas wells, potentially corrosive gasses could migrate into the annulus damaging the wellbore W, which could be casing of a material incompatible with the migrating gas. Even circulating or reverse circulating mud of a predetermined weight into the annulus, in the past, without annulus isolation, did not insure that undesirable fluids would not migrate into the annular space. The packer P of the present invention can be used to provide positive annulus isolation in such applications, as illustrated in  FIGS. 20–23 . 
     FIG. 24  illustrates a liner  214  suspended from a liner hanger  216  with the packer P serving as the liner top packer in wellbore W, which can be cased or uncased. 
     FIGS. 25–28  illustrate the use of the packer P initially as an isolation packer and subsequently as a production packer. As shown in  FIG. 25 , the packer P is expanded into a sealing position. The packer P is shown schematically. It may have a removable plug  218  that sits below its body. Plug  218  can be run in with the packer P and portions of the packer above the plug  218  can be expanded into sealing position with the wellbore W. As shown in  FIG. 26 , an assembly comprising of tubing  220 , seal assembly  222 , retrieving device  224 , and a sinker bar  226  are lowered into position adjacent the plug  218 . In  FIG. 27 , the plug  218  has been knocked out and the seal assembly  222  is in seal bore  223  of the packer P.  FIG. 28  illustrates the release tool and retrieving device  224 , as previously described, stretching the packer P to get it to release and retaining a grip on it after release so it can be removed. 
     FIGS. 29–32  illustrate a one trip hydraulically set packer P that is run in and set using a pressure intensifier  228 . Mounted inside body  230  is a piston  232 . A port  234  communicated into annular space  236  defined by lower sub  238 . Seals  240 – 248  isolate annular space  236  so that applied pressure after ball  250  lands on seat  252  puts a downward force on piston  232 , which moves in tandem with sleeve  254 . Seal  256  allows pressure to be built up on landed ball  250  until a predetermined value, at which point the shear pin or pins  258  break to release ball  250 , as shown in  FIG. 31   b . As shown in  FIG. 29   a , annular space  260  is defined between piston  232  and mandrel  262 . Seals  264 – 268  and  240 – 244  isolate the annular space  260 . Piston  232  has a shoulder  266 , which decreases the volume of annular space  260  as the piston  232  is moved downwardly. The pressure is intensified because the radius of seal  248  is larger than the radius of seals  242 – 244  and  264 – 266 . The downward force on ring  254  is converted to a greater force applied to a smaller radius, where shoulder  266  is located. As a result, the mandrel  262  expands radially to push out the sealing element  270  and the slips  272 – 274  in the manner previously described. After the packer P is set, a further buildup of pressure on ball  250  breaks shear pin  258  to release ball  250  downhole.  FIG. 32  shows an alternative way to set the packer P using a slick line plug, not shown, that lands in groove  276  and seals adjacently using seals carried on the plug. The packer P is then set using the pressure intensification as described with respect to  FIGS. 29–31 . At the conclusion of the setting process, the plug is captured with a fishing tool on a fishing neck, in a known manner and hoisted out. No matter how the packer is set, the intensifier  228  is built into it and stays in position after the packer P is set to become a part of the central passage through the packer P. The packer P is run in on one trip and pressured up after the object such as ball  250  or a slick line plug (not shown) is quickly placed in position to allow pressure buildup to initiate expansion. If using the slickline plug, multiple packers can be run on a single string and set in a predetermined order or in any random order. 
   Referring to  FIGS. 33   a – 33   e , an alternative embodiment is disclosed. The slips  300  and  302  now each have at least one inwardly oriented depression  304  and  306  respectively. The expansion mandrel  308  is preferably cylindrical in the region of slips  300  and  302  but may have slight indentations  310  and  312  to orient the slips  300  and  302  in the run in position. As shown in  FIG. 33   a , a seat  314  accepts a ball  316  for movement of the piston  318 . Piston  318  moves between outer seals  320  and  322  and inner seals  324  and  326  to reduce the volume of cavity  328 . Because the area of cavity  328  is smaller than the piston area at seat  314  with ball  316  landed on it, there is a magnification of applied pressure on the ball  316  that acts to expand the expansion mandrel  308 .  FIGS. 34   d – 34   e  show what happens as the expansion mandrel  308  expands. It not only pushes the slips  300  and  302  outwardly to make supporting contact with the wellbore or tubular  330  but it also assumes the interior shape of the slips  300  and  302  by expanding into their respective depressions  304  and  306 . Those skilled in the art will appreciate that the depressions  304  and  306  may be on the mandrel  308  and that slips  300  and  302  can be cylindrical or have outward projections on their inwardly oriented surfaces. The advantage to the embodiment in the  FIGS. 33–35  is that it is simpler to put recesses  304  and  306  into the slips than to prepare an expansion mandrel and matching slips with mating undulating surfaces. Since there is some shrinkage in length during the expansion process, getting the undulations to stay meshed throughout the expansion process can become an issue. Using the preferred embodiment of a depression on the slips not only better secures the slips  300  and  302  to the expansion mandrel  308  but it takes better advantage of the shrinkage during expansion to hold the slips  300  and  302  in position. The number, shape and depth of depressions  304  and  306 , as well as their location on the slips or the expansion mandrel can be varied depending on the application.  FIG. 35   f  shows the seat  314  and the ball  316  being blown out of the way after the set position is obtained. A plug or some other object can be used instead of ball  316  to temporarily obstruct the interior passage to allow pressure buildup to set the Packer P. 
   Apart from reducing stress on a surrounding tubular or wellbore, the packer P of the present invention also conforms to oval shaped casing as well as provides increased collapse resistance in the set position. The packer P can be delivered into casing on wireline or slickline or on wireline or slickline through tubing. Alternatively coiled tubing can deliver the packer P into casing or through tubing. The packer P can be set hydraulically in one trip as described or in two trips when combined with an intensifier that needs to be removed after expansion. The retrieving tool for the packer P can be delivered into the packer P in the variety of ways the packer P can be delivered. The release tool preferably stretch the packer P sufficiently until it releases and can be combined with a pressure intensifier. The releasing can be done with one trip or additional trips. The packer P can be used in a variety of applications apart from those described in detail above. Some examples are frac/injection, production, feed through, dual bore, zone isolation, anchored seal bore, floating seal bore, Edge set, combined with sliding sleeve valves, and setting in a multilateral junction. 
   The simplicity of the packer P lends itself to rapid development with less testing than other prior art designs because its behavior under expansion forces is more predictable. Prior art packers were compressed axially to expand radially and had many parts that moved relatively to one another. It was difficult to predict how the seal would react to an axial compressive force. As a result complex programs were developed to predict seal behavior under compressive force. With the packer P on the other hand, the reaction of the seal to expansion is more readily predicted. Additionally, prior designs required a variety of anti-extrusion systems and those needed testing to see that they would deploy before extrusion had actually taken place. With the packer P scaling up from one size to another is also simplified. 
   The packers P can be introduced quickly at different levels in the wellbore and set or released selectively with ease. In another application the packer P can be run in on tubing and then pumping cement through the tubing and out around the packer, followed by setting the packer. The packer P can be used as a velocity string hanger below a safety valve. The packer P can have multiple bores and it can be set in not only out of round casing but also in the reformed leg of a multilateral junction. The packer P either assumes the oval shape or conforms the oval tubing back to a round shape. The expansion technique enhances not only collapse resistance but also corrosion resistance. The reason is that by using a swage to expand, higher stresses are imposed than if pressure is used, with the result being a loss in corrosion resistance and collapse resistance. As an alternate to release by stretching, release can be accomplished by isolation of the expanded segment and pulling a vacuum to collapse the mandrel sufficiently so that it will release for removal. 
   The rings  168  and  170  keep the wickers  176 – 182  engaged despite reversals in load direction. Internal pressure in the sealing element  162  creates a radial force on the slips  158  and  159  through the ramped surfaces on rings  168  and  170 . The nodes  164 – 166  allow the use of a non-elastomeric seal. Pressure one end of seal element  162  transfers load to another node on the lower pressure end of the seal element  162 . The presence of multiple nodes increases the internal pressure to help maintain the seal as loading conditions shift. 
   Another distinction from the prior art packers is the use of even loaded collet type slips that are urged into greater contact with the casing when uphole or downhole pressures increase. Due to the undulating contact between the slips and the mandrel, such axial loading from pressure is not transmitted to the sealing element; rather it just causes the slips to grab harder. 
   The above description is illustrative of the preferred embodiment and many modifications may be made by those skilled in the art without departing from the invention whose scope is to be determined from the literal and equivalent scope of the claims below.