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CROSSREFERENCE TO RELATED APPLICATIONS 
   This patent application claims an international filing date of 20 May 2003 and a priority date of 21 May 2003 and a priority date of 21 May 2002. 
   STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
   Not Applicable 
   THE NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT 
   Not Applicable 
   INCORPORATION-BY-REFERENCE OF MATERIAL SUBMITTED ON A COMPACT DISC 
   Not Applicable 
   BACKGROUND OF THE INVENTION 
   The present invention relates to a downhole packer for use in a well bore. More particularly, the present invention relates to a packer which can be used for downhole testing. 
   During well completions it is desirable to check the integrity of the production bore and any packers used to isolate portions of the well. A known technique for this is to perform an inflow or negative test. One or more packers are inserted into the well bore to seal off a portion of the well. Low density fluid is introduced to the work string reducing hydrostatic pressure within the pipe. As a consequence of the drop in hydrostatic pressure, well bore fluid flows through any cracks or irregularities into the bore resulting in an increase in pressure which can be monitored and used to indicate where repairs are necessary. 
   Typically, a separate trip is required to be made into the well to perform an inflow or negative pressure test. This is because the conventional packer tools used are set by a relative rotation within the well bore. As many other tools are activated by rotation it is likely that the packer would prematurely set. This problem has been overcome by the introduction of a weight set packer. Such a weight set packer, referred to as a compression set packer, is disclosed in the Applicant&#39;s International Patent Application, publication no. WO/0183938. The packer is set by a sleeve moveable on a body of the packer being set down on a formation in the well bore. Movement of the sleeve compresses one or more packing elements to provide a seal. 
   This compression set packer is particularly suitable for integrity testing of a completion when a permanent packer, or ‘tieback’ packer, with a Polished Bore Receptacle (PBR) has been used. Once the permanent packer with the PBR has been set, a single trip can be made into the well to operate clean-up tools and perform an in-flow or negative test. The clean-up tools may be operated by relative rotation of the work string in the well-bore and further the work string can be slackened off so that the sleeve of the compression set packer lands out on the PBR. This sets the compression set packer above the PBR and seals the bore between the packers. An in-flow or negative test can then be performed. 
   A significant disadvantage of this compression set packer is that if the sleeve contacts a surface prior to reaching the PBR, the packer can be prematurely set. Additionally, as the work string requires to move through the bore relative to the sleeve for compression to occur, the compression set packer cannot be run on the same string as the tieback packer and PBR. 
   It is an object of the present invention to provide a compression set packer which includes a mechanism to prevent premature setting of the packer in a well bore. 
   It is a further object of at least one embodiment of the present invention to provide a packer which can be run with a tubular in a well bore to seal above the tubular when the tubular is positioned in the well bore. 
   It is a further object of at least one embodiment of the present invention to provide a method of performing an in-flow test in a well bore on the same trip as setting a tieback packer including a polished bore receptacle. 
   BRIEF SUMMARY OF THE INVENTION 
   According to a first aspect of the present invention there is provided a packer tool for mounting on a work string, the packer tool comprising a body with one or more packer elements and a sleeve, the packer tool being set by movement of the tool body relative to the sleeve compressing the one or more packer elements, wherein the sleeve includes at least one retaining member, the at least one retaining member being moveable between first and second positions, the first position preventing movement of the sleeve relative to the tool body and the second position releasing the tool body while providing means for arresting movement of the sleeve so that the tool can be set. 
   Preferably the/each retaining member is located in an aperture between an inner and an outer surface of the sleeve. Preferably a first portion of the/each retaining member protrudes from the aperture in the first position. Preferably also a second portion of the/each retaining member protrudes from the aperture in the second in the second position. Preferably also the sleeve includes restraining lips or overhangs on the inner and outer surfaces at the/each aperture to limit movement of the/each retaining member as it protrudes from the aperture. 
   Preferably the retaining member is a sprung dog. Preferably a spring of the/each dog biases the/each dog to the second position. In the first position the dog may protrude from the inner surface of the sleeve and in the second position the dog may protrude from the outer surface of the sleeve. 
   Advantageously the tool body includes at least one recess on an outer surface. Preferably the/each retaining member locates in the/each recess in the first position. By locating in a recess of the tool body, the/each retaining member effectively locks the sleeve and tool body together preventing movement of the sleeve relative to the tool body. 
   Preferably also the second portion of the/each retaining member includes a contact surface. The contact surface may engage a formation in the well bore when the/each retaining member is in the second position. Thus the contact surface of the/each retaining member can be landed on a formation in a well bore. Pressure upon the/each retaining member is then transferred to the sleeve. When the work string is slackened off the tool body will then move relative to the sleeve and thereby set the packer. 
   Advantageously when the packer is run in the well bore, the/each sprung dog is held in the first position such that the packer cannot be set. When the packer is located above the required formation, the/each dog is released and the spring within the/each dog will bias the dog into the second position ready to be landed on the formation and set the packer. 
   Preferably also the tool body and the sleeve include one or more ports. Advantageously the ports are aligned when the packer is set to allow the passage of fluid from the outer surface of the sleeve to a throughbore of the tool body. More preferably the throughbore is connected to a throughbore of the work string. Preferably also the tool body and the sleeve are keyed together to limit longitudinal movement and prevent rotational movement of the sleeve relative to the tool body. The tool body and the sleeve may be keyed via a longitudinal slot on the outer surface of the tool body and a pin on the inner surface of the sleeve. 
   Preferably also biasing means are located between the tool body and the sleeve. In setting the packer the sleeve may move against the biasing means. The biasing means may be a spring. 
   Further the packer may include a shoulder on an outer surface. More preferably the shoulder is located on the outer surface of the sleeve. The shoulder provides an abutment surface for a tubular if located at the packer tool. The tubular may be used to hold the retaining member in the first position. Preferably the tubular is a polished bore receptacle. 
   According to second aspect of the present invention there is provided a method of setting the packer tool of the first aspect in a well bore, the method comprising the steps:
     (a) locating the packer tool on a work string and abutting a shoulder of the tool on a top of a tubular being run in the well bore;   (b) using the tubular to hold a retaining member of the packer tool in a first position preventing movement of a sleeve of the tool relative to a body of the tool;   (c) running the tool and tubular into a well bore;   (d) detaching the work string from the tubular and raising the tool relative to the tubular;   (e) locating the retaining member above the top of the tubular so that it moves to a second position releasing the tool body and providing a contact surface; and   (f) landing the contact surface on the top of the tubular so that the sleeve is arrested and movement of the tool body compresses packing elements on the body which set the tool.   

   Running the tool with the retaining member in the first position prevents the tool from prematurely setting. Additionally as it is the tubular, which may be a polished bore receptacle, which is used to hold the tool in the first position, setting of the packer will only be achieved at the top of the tubular as desired. 
   According to a third aspect of the present invention there is provided a method of performing an integrity test on a well completion, the method comprising the steps:
     (a) locating a retrievable packer at a polished bore receptacle of a tieback packer on a work string;   (b) running the work string in a well bore;   (c) setting the tieback packer at a desired location within the well bore;   (d) setting the retrievable packer to isolate a section of the well bore;   (e) circulating a light density fluid through the work string and monitoring the pressure to determine the integrity; and   (f) removing the work string and retrievable packer from the well bore.   

   Preferably the integrity test is an in-flow or negative pressure test as is known in the art. 
   Preferably the step of setting the retrievable packer includes the step of setting down the retrievable packer on the polished bore receptacle. 
   Preferably also the method includes the step of detaching the work string from the tieback packer and polished bore receptacle prior to setting the retrievable packer. 
   More preferably the method includes the step of pulling up the work string after setting the tieback packer and before setting the retrievable packer. 
   Preferably the retrievable packer is a compression set packer. 
   Advantageously, the compression set packer is according to the first aspect. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     An example embodiment of the invention will now be illustrated with reference to the following Figures in which: 
       FIGS. 1(   a ) and ( b ) show a part cross sectional schematic view of a packer tool according to the present invention; 
       FIG. 2  shows a sectional view through section A-A′ of the tool of  FIG. 1 ; and 
       FIG. 3  is a partial sectional view of a lower part of the packer tool of  FIG. 1 , shown coupled to a tieback packer. 
   

   DETAILED DESCRIPTION OF THE INVENTION 
   Reference is initially made to  FIG. 1  of the drawings which illustrates a packer tool, generally indicated by reference numeral  10 , according to the present invention. Packer tool  10  is a compression set packer. 
   The packer tool  10  comprises a body  12  upon which is arranged a packing element  18  and a sleeve  14 . Packing element  18  is the form of an annular band of rubber which when compressed longitudinally will expand radially, increasing the overall diameter of the tool  10  to provide a seal between the outer surface  20  of the body  12  and a surface within a well bore (not shown). Packer tool  10  further includes dogs  16  circumferentially arranged around the body  12  within the sleeve  14 . 
   Tool body  12  is a cylindrical mandrel including a throughbore  22 . At an upper end  24 , there is located a box section  26  to allow the body  12  to be connected to a work string (not shown). At a lower end  28  of the body  12  there is located a pin section  30  so that the tool  10  can be mounted within a work string (not shown). The work string located at the bottom  28  of the tool  10  preferably supports a packer and a tubular shown in part at  32 . It will be understood that the tubular  32  can be of any form, for example liner or casing. The top  74  of the tubular  32  may referred to as a liner top or liner lap. In the preferred embodiment tubular  32  is a polished bore receptacle and the packer is a tieback packer providing a permanent seal below the top  74 . 
   The body  12  further includes a port  34  providing a radial aperture from the throughbore  22  to the outer surface  20 . Further on the outer surface  20  is arranged a longitudinal slot  36  and six recesses  38 , the recesses being arranged circumferentially around the body  12 . The purpose of each of these will be described hereinafter. 
   Mounted on the body  12  is a shoulder  40  against which is arranged the packer element  18 . A second shoulder  42  is located on the sleeve  14  adjacent the packer element  18 . Shoulders  40  and  42  contain the packer element  18  and if moved toward each other will provide the necessary compression for the subsequent radial expansion of the element  18  which sets the tool  10 . 
   The sleeve  14  is arranged around the body  12  and a recess  44  is formed there between. Within recess  44  is located a bias spring  46 . Bias spring  46  is limited in longitudinal movement between a face  48  on the body  12  and a face  50  on the sleeve  14 . When the faces  48 , 50  are moved together as the body  12  and the sleeve  14  are moved relative to each other, the spring  46  will be compressed and allow the packer element  18  to expand. The spring  46  will bias the packer element  18  to an uncompressed state. Recess  44  is limited in size by the movement of a retaining stud  52  located through the sleeve  14  which protrudes into the slot  36  on the tool body  12 . The retaining stud  52  allows the body  12  and the sleeve  14  to move relative to each other over an axial distance dictated by the length of the slot  36 . Slot  36  is selected to provide a sufficient length against which suitable compression of the packing element  18  of the tool  10  can be achieved. 
   Sleeve  14  includes a port  54  which provides fluid access from an inner surface  56  to the outer surface  58  of the sleeve  14 . Port  54  can be arranged to align with the port  34  of the tool body  12  so that there is a passage of fluid from the throughbore  22  to the outer surface  58  of the sleeve  14  and consequently the tool  10 . 
   Further apertures  60  are located through the sleeve  14 . There are six apertures  60  in the preferred embodiment. This is best illustrated in  FIG. 2 . However, any number of apertures may be used and, for clarity, only one will be described here. Located in aperture  60  is a sprung dog  16  which may be considered as a retaining member as it is contained within the sleeve  14 . Retention of sprung dog  16  is provided by a first lip  62 , arranged on the outer surface  58  of the sleeve  14 , and a second lip  64 , on the inner surface of the sleeve  14 . Sprung dog  16  is held between the overhangs of the lips  62 ,  64  and allows the dog  16  to move within the aperture  60  so that it may protrude from the inner  56  or outer  58  surface of the sleeve  14 . 
   In a first position, a first portion  66  of the dog  16  protrudes from the inner surface  56  into recess  38  on the body  12 . In a second position, a second portion  68  of the dog  16  may protrude through the outer surface  58  of the sleeve  14 . In  FIG. 1  the tool  10  is shown in the first position, where the first portion  66  is contained within recess  38  and the second portion  68  is enclosed in the aperture  60 . The dog  16  is held in the first position by virtue of the second portion  68  contacting the tubular  32 . As can be seen from the Figure the diameter of the tool  10  is selected to match the inner diameter of the tubular  32 . 
   Dog  16  further comprises a spring  70  used to bias the dog  16  into the second position, that is having the second portion  68  protruding from the outer surface  58  of the sleeve  14 . This would occur if tool  10  were removed from the tubular  32 . The first portion  66  would be moved into the aperture  60  while the second portion  68  moves radially outwards to expose a surface  78  substantially perpendicular to the axis of the tool  10 . 
   Mounted on the sleeve  14  above the dogs  16  is a ring  72 . Ring  72  is fixed to sleeve  14  via a grub screw  80  and provides a surface  82  for abutment to the top  74  of the tubular  32 . When abutted, the ring  72  prevents debris entering the annulus  76  between the tool  10  and the tubular  32 . 
   In use, tool  10  is mounted on a work string via the box section  26  and pin  30 . The work string will also support a tubular  32 , which is preferably a polished bore receptacle. In an embodiment a tieback packer  83 , shown in  FIG. 3 , is located on the work string below the tool also. Packer tool  10  is positioned on the string so that the surface  82  of ring  72  abuts the top  74  of the tubular  32 . In this way the tubular  32  may provide support to the tool  10 . Additionally the dogs  16  are located within the tubular  32 . 
   Initially, by virtue of the tubular  32  contacting the second portion  68  of the dog, the first portion  66  of the dog  16  will protrude from the inner surface  56  of the sleeve  14  into the recess  38  of the body  12 . As the dog  16  breaches the body  12  and the sleeve  14  at the recess  38 , neither the body  12  nor the sleeve  14  can move independently of the other. The dog  16  has effectively locked them together. The sleeve  14  and body  12  cannot rotate relative to each other by virtue of the dog  16  and the stud  52  located in the longitudinal slot  36 . 
   The tool  10  is run into the well bore in this first position. As the leading edge  84  of the sleeve  14  is held within the tubular  32 , the edge  84  is prevented from contacting anything within the well bore which would put pressure on the sleeve and want the packer to set. More preferably, if anything in the well bore contacts the sleeve above the tubular, the shoulder  42  is prevented from moving by virtue of the dog  16  being located within recess  38  of the tool body so that it is impossible for the packing element  18  to be compressed in any way to prematurely set the tool  10 . 
   When tubular  32  is positioned in the well bore, the work string is rotated to release the tool  10  from the tieback packer and tubular  32 . As the packer tool  10  is not set by rotation but by weight, the packing element  18  will not be compressed and therefore the tool cannot set during this operation. The work string carrying the tool  10  can then be raised, pulling the tool  10  out of the tubular  32 . As the packer tool  10  is raised relative to the tubular  32 , the dogs  16  will reach a position above the top  74  of the tubular  32 . At this location, the tubular  32  will no longer hold the dogs  16  against the body  12  and consequently the springs  70  of the dogs  16  will bias the dogs radially outwards and a second portion  68  of each dog  16  will now extend past the outer surface  58  of the sleeve  14 . The perpendicular surface  78  of each dog  16  will now extend outwards from the sleeve  14 . The packer tool  10  is not set by this lifting operation as the bias spring  46  located in the recess  44  between the body  12  and the sleeve  14  is biased such that the packer element  18  is in an extended position. 
   Once the dog  16  is released at the top of the tubular  32  the tool  10  can be set down by slackening weight on the work string. When the work string is slackened off the tool will fall to a position where a surface  79  of the dog  16  contacts the top  74  of the tubular  32 . Contact of the surface  79  on the top  74  will arrest the sleeve  14  by virtue of the holding position maintained by each dog  16 . With the sleeve  14  now held in position at the top  74  of the tubular  32 , all weight exerted on the work string will bear upon the tool body  12 . The tool body  12  will be forced down through the sleeve  14  and the tubular  32  which will thereby compress the bias springs  46  and cause the longitudinal slot  36  in the body  12  to move over the stud  52 . Movement of the body  12  relative to the sleeve  14  will cause the shoulder  40  on the body  12  to move towards the shoulder  42  on the sleeve  14 , thereby compressing the spring  46  and the packing element  18 . Compression of element  18  sets the tool as the element  18  will seal against the well bore or casing/liner if in place. Excessive pressure cannot be applied to the element  18  by virtue of the stud  52  reaching an end  86  of the slot  36 . 
   This is considered as the second position of the tool  10 . In this position the port  34  in the body is aligned with the port  54  in the sleeve  14 . Fluid may then flow from the well bore to the throughbore of the work string. 
   To retrieve the packer tool  10 , the work string is simply pulled out of the well bore. As weight is removed from the body  12 , surface  48  of the body  12  is raised away from surface  50  of the sleeve  14 . This is assisted by the bias spring  46 . At the same time, the slot  36  will pass over the stud  52  until the stud locates in a lower end  88  of the slot. This movement releases compression on the packer element  18  and the element  18  will be pulled back to release from the well bore and break the seal. The packer tool  10  can then be removed from the well bore on the work string as the sleeve will be supported on the body by the stud  52 . 
   In order to conduct an in-flow or negative pressure test on a completion, the tool is operated as is described herein above with a tieback packer  83  and polished bore receptacle mounted on the work string below the packer tool  10 . The polished bore receptacle will hold the dogs  16  in the first position to prevent the body  12  and sleeve  14  from moving relative to each other and thereby the packer tool cannot prematurely set. The ring  72  will prevent debris entering the polished bore receptacle particularly if cleaning tools are used on the work string above the packer tool  10 . 
   As described above, once the polished bore receptacle is fixed in the well bore and the tieback packer has been expanded to seal below the packer tool  10 , the packer tool  10  can be raised and provides a seal in the well bore above the polished bore receptacle. This seal will be against a casing or liner in the well bore. A light density fluid can be pumped through the work string and circulated in the well bore. The pressure within the throughbore  22  will be lower than the pressure in the annulus  76  and consequently between the polished bore receptacle and the casing/liner. As a result, any cracks or leaks in the casing/liner or through the tieback packer will cause well fluid, which will be at a higher pressure than the light density fluid in the throughbore  22 , to move into the throughbore  22 . The leaked fluid will enter the throughbore through the ports  34 ,  54  which when packer tool  10  is set will align to provide a single radial bore. The higher pressure fluid entering the throughbore will increase the pressure in the throughbore  22  which can be monitored on the surface of the well bore and used to provide an indication of the integrity of the completion. Once the test is complete the packer tool  10  can be retrieved from the well as described herein above. 
   The principle advantage of the present invention is that it provides a packer tool which can be run with the completion to allow an integrity test to be performed without the need to make a dedicated run into the well for testing. 
   A further advantage of the present invention is that it provides a retrievable packer tool which includes a mechanism to prevent the packer tool from prematurely setting in a well bore. 
   Various modifications may be made to the invention herein described without departing from the scope thereof. In particular, it will be appreciated that any number of sprung dogs, studs and slots, and radial ports may be incorporated in the tool. Additionally although the tool is described, in use, in a vertical well bore, the tool may be used in inclined or horizontal bores.

Summary:
A packer tool for mounting on a work string in an oil and/or gas well is described. The packer is of the compression set type but includes a mechanism to prevent premature setting in the well. A method of running the tool with the completion is provided in order to advantageously allow an integrity test to be performed on the same run.