Abstract:
There is disclosed a downhole packer for use in a well bore, and in particular, a packer which can be used for downhole testing. In an embodiment of the invention, a packer tool ( 10 ) for mounting on a work string to provide a seal against a tubular ( 32 ) is disclosed, the packer tool comprising a body ( 12 ) with one or more packer elements ( 18 ) and a sleeve ( 14 ), the packer tool being set by movement of the sleeve relative to the tool body compressing the one or more packer elements, wherein the tool has a plurality of bypass channels ( 16 ) to provide a fluid path past the packer elements, the sleeve including at least owe anchoring member ( 22, 50 ), the at least one anchoring member being actuate to contact the tubular by fluid pressure from the bypass channels when the packer is set.

Description:
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 in-flow 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 in-flow 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 and indeed as the drill string itself would normally be rotated during this type of operation, 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 liner 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 of loading on the PBR. When an in-flow test is carried out large pressure differentials are created across the packing element and thus a substantial force is applied to the packer from above. In a compression set packer much of this force is transferred to the PBR. As a result, both the packer element and the PBR are at risk of failure if the load bearing capacity is exceeded. This is a particular problem in deep wells were the differential pressures will be greater. For example, if a packer has an annulus surface area, in use, of 10 square inches and a pressure differential applied across it of 30,000 pounds, this provides a force of up to 250,000 pounds at the compression set packer. 
   The problem of excessive loading and the additional forces on the liner by the hydraulic test pressure differentials has been considered for a liner top test packer as described in WO 03/067027. This discloses an arrangement where the slips are set below a compression set packer and the packer is set against the slips. The additional loading and forces are all then transferred to the casing in which the packer is set via the slips. Thus the slips prevent loading onto any liner or liner hanger located below the slips. 
   This packer tool, however, has a number of disadvantages. As with all weight-set tools there is a risk that the tool will set in the wrong location if it meets an obstruction in the well bore. As this tool is set by shearing pins and then engaging slips before the packer elements expand, it is difficult to release the tool for repositioning once it has set. Additionally, as the slips move transversely in response to a longitudinally applied force, under excessive longitudinal loading, which can be experienced at high pressure differentials, the slips can loose grip and thus there is a risk of the full force landing on the liner top. 
   SUMMARY OF THE INVENTION 
   It is an object of the present invention to provide a compression set packer which includes a mechanism to take up excess force created by the pressure differential during an in-flow test. 
   It is an object of at least one embodiment of the present invention to provide a compression set packer which prevents force from the pressure differential being applied to a liner top. 
   According to a first aspect of the present invention there is provided a packer tool for mounting on a work string to provide a seal against a tubular, the packer tool comprising a body with one or more packer elements and a sleeve, the packer tool being set by movement of the sleeve relative to the tool body compressing the one or more packer elements, wherein the tool has a plurality of bypass channels to provide a fluid path past the packer elements and wherein the sleeve includes at least one anchoring member, the at least one anchoring member being actuable to contact the tubular by fluid pressure from the bypass channels when the packer is set. 
   Thus a flow path exists in the tool past the packer elements at all times. When the elements are set, the fluid pressure is used to actuate anchoring means against a wall of the well bore to prevent excess loading below. Increased flow pressure caused by a pressure differential at the elements is used to further secure the anchoring means. Further the existence of a flow path around the packer elements reduces surging and swabing when the tool is run-in and pulled out of the well bore. 
   Preferably the at least one anchoring member is a moveable pad. Preferably there are three pads equidistantly arranged around the sleeve. Preferably the pads are arranged to move radially with respect to a longitudinal axis of the tool. Preferably each pad includes a gripping surface to engage the tubular. Advantageously each pad is part cylindrical, with the curved face being the gripping surface. Preferably a radius of curvature of the gripping surface matches a radius of curvature of the tubular. Preferably also each pad includes a rear surface against which fluid pressure can act to move the pad. 
   The tool may include restraining means. The restraining means may be one or more springs which bias the/each pad toward the sleeve. The springs may be a pair of leaf springs arranged longitudinally on either side of each pad. The restraining means prevents the pads from engaging the tubular wall when the tool is run-in the tubular. 
   Preferably the sleeve includes a plurality of ports, each port being arranged between an inner and an outer surface of the sleeve. Preferably, when the packer is not set, the ports align with a base of the bypass channels so that fluid bypassing the packer elements passes to the outer surface of the sleeve. Preferably also, when the packer is set, the ports are closed by virtue of their movement away from the bypass channels. 
   Preferably, closure of the ports directs the fluid bypassing the packer elements and transfers the fluid pressure to the anchoring means. More preferably the directed fluid flows through one or more channels in the sleeve to exert the fluid pressure upon the rear surface of the pads. 
   Preferably the sleeve includes one or more recesses arranged longitudinally on the outer surface. The recesses provide fluid flow past the sleeve as the tool is run in a well bore. 
   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 liner top if located at the packer tool. Preferably the liner top is a polished bore receptacle. 
   Preferably the one or more packer elements are made from a moulded rubber material. 
   The sleeve may be mechanically linked to the body of the tool by a shear means, wherein the shear means is adapted to shear under the influence of setting down weight on the tool when the shoulder co-operates with the formation. 
   The sleeve may be mechanically linked to the sleeve by a safety trip button which prevents the sleeve from disengaging from the body until the tool has reached the liner top. Such safety trip buttons are as disclosed in WO 03/040516. 
   Preferably the sleeve is biased away from the packer element. Preferably the biasing is achieved by a spring. More preferably the spring is located in the channels to the pads. 
   Preferably the packer tool further includes one or more scrapers and/or brushes mounted below the sleeve. The scrapers and/or brushes clean ahead of the packer elements and prepare the area that the tool is to be set in. 
   Preferably the work string is a drill string. The drill string may also include dedicated well clean up tools. 
   According to a second aspect of the present invention there is provided a method for setting the packer tool of the first aspect in a well bore, the method comprising the steps of:
         a) running the packer tool mounted on a work string into a well bore while allowing fluid to bypass the packer elements via bypass channels in the tool;   b) landing the tool upon a liner top within the well bore;   c) setting down weight on the packer tool to move the sleeve relative to the tool body in order to compress and set the packer elements;   d) diverting the fluid pressure through the bypass channels to actuate anchoring means on the sleeve; and   e) anchoring the tool against a wall of the well bore to limit the load on the liner top.       

   Preferably the method also comprises the step of performing an inflow or negative test to test the integrity of the well bore. 
   Preferably the packer elements can be set repeatedly. 
   Preferably the method further comprises the step of brushing and/or scraping the well bore ahead of packer when running the packer. 
   Preferably also the method includes the step of inserting the tool within the liner top to engage a safety trip button before retracting the tool to release the safety trip button and allow the sleeve to separate from the body. 
   According to a third aspect of the present invention there is provided a method of performing an inflow test within a tubular, the method comprising the steps of:
         a) setting a compression set packer on a liner top within the tubular;   b) creating a differential pressure between a bore of the liner and an annulus over which the packer element is set;   c) diverting fluid pressure in the annulus through bypass channels around the packer element;   d) using the fluid pressure to actuate anchoring means to secure the compression set packer against the tubular below the packer element to limit loading on the liner top; and   e) monitoring fluid pressure at surface to detect leaks within the liner.       

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     Example embodiments of the invention will now be illustrated with reference to the following Figures in which: 
       FIG. 1  is a cross-sectional schematic view of a packer tool according to the present invention; 
       FIG. 2  is a sectional view through the line  2 - 2  of  FIG. 1 ; and 
       FIG. 3  illustrates a further embodiment of a packer tool according to the present invention. 
   

   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 in 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  19  within a well bore. Packer tool  10  further includes bypass channels  16  behind the packer element  18  and an anchoring means, generally indicated by reference numeral  22 , below the packer element  18 . 
   Tool body  12  is a cylindrical mandrel including a throughbore  21 . 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 of the body  12  there is located a corresponding pin section (not shown) so that the tool  10  can be mounted within the work string. The sleeve  14  includes a shoulder  28  on an outer surface  30  thereof. The shoulder is designed to match and locate on a top  34  of a tubular  32  which may be referred to as a liner top. In the preferred embodiment tubular  32  is a polished bore receptacle and is held in position by a tieback packer as is known in the art. The tieback packer provides a permanent seal below the top  34 . 
   The body  12  further includes a series of ports  36  providing a fluid passageway from the bypass channels  16  to the outer surface  20  of the body  12 . The ports  36  are equidistantly arranged around the circumference of the body  12 . The sleeve  14  is arranged to cover the ports  36  and has a series of matching ports  38  arranged around its circumference. The ports  38  extend through the sleeve  14 . In this way, when ports  38  are aligned with ports  36  fluid travelling through the channels  16  can pass from the channels  16  through the ports  36 ,  38  into the well bore. Equally fluid pressure can be transferred through fluid within the channels  16 . 
   Sleeve  14  is initially held to the body  12  by a shear pin  48 . Shear pin  48  provides a mechanical link between the sleeve  14  and the body  12 . The shear line for the pin is on the outer surface  20  of the body and when split the pin is retained within the sleeve  14 . With the shear pin  48  in place, the ports  36 , 38  are aligned and fluid bypasses the packer element  18  and is returned to the well bore. 
   In an alternative embodiment the sleeve  14  is held to the body  12  by a safety trip button. Such a safety trip button is that disclosed in WO 03/040516 which is incorporated herein by reference. The button operates between the tool body  12  and a sleeve  14  of the tool, locking them initially together. When the tool reaches a liner top in a well bore, the button engages the liner which unlocks the body and sleeve. The button is kept in the unlocked position by virtue of the liner while the tool is set. The button prevents premature setting of the tool. 
   The sleeve  14  is moved by virtue of the shoulder  28  contacting the liner top  34 , and weight being set down on the work string. Sleeve  14  is biased away from the packer element  18  via a spring  40  located in a channel  42 , thus the spring  40  is compressed as the sleeve  14  is moved. Channel  42  is longitudinally arranged between the sleeve  14  and the body  12 . Channel  42  has a lower lip  44  against which spring  40  is biased and an upper opening  46  which aligns with the port  36  in the body  12 . In the embodiment shown there are three channels  42 . However, any number of channels or reservoirs may be incorporated. Fluid pressure in the bypass channel  16  will be directed through the opening  46  to travel through the channels  42  if the ports  38  are closed by virtue of being misaligned with the ports  36 . 
   Channels  42  extend into the anchoring section  22  and end behind three pads  50  located on the sleeve  14 . Thus fluid pressure guided through each channel  42  can impinge on a rear surface  58  of each pad. Each pad  50  lies in a recess  52  on the outer surface  30  of the sleeve  14 . Each recess  52  is shaped to provide a lip  54  to prevent the pad from moving into the body  12 . Recess  52  includes seals  56  so the fluid behind each pad  50  will not travel between the pad  50  and the recess  52  to escape from the tool  10 . Each pad  50  can therefore be moved radially outward from the sleeve  14  by virtue of fluid pressure reaching the rear surface  58 . 
   On actuation of the pads  50 , by increased fluid pressure through the channels  42 , each pad  50  moves as a piston, radially outwards and contacts the surface  19  in the well bore. Each surface  60  with moving pads  50  is serrated to provide a gripping surface such as would be found on slips and the like so that pads  50  adhere to the surface  19 . 
   Further, restraining means, generally indicated by reference numeral  62 , are attached to each pad also. In the embodiment shown the restraining means comprises two leaf springs  64   a,b  arranged longitudinally on either side of each pad  50 . Each spring  64  is bolted  66  at one end to the pad  50  and is located under the surface  68  of each pad  50  at the other end. The springs  64   a,b  bias the pad  50  into the recess  52 . 
   There are three pads  50  arranged equidistantly on the outer surface  30  of the sleeve  14 . It will be appreciated by those skilled in the art that the pads could be staggered upon the surface  30  and various numbers of pads could be used. Each pad  50  has an outer surface  38  which is part cylindrical, as seen with the aid of  FIG. 2 . The curvature of the outer surface  68  matches the radius of curvature of the surface  19  to which it adheres. 
   On the outer surface  30  of the sleeve  14  at the anchoring means  62  there are arranged longitudinal recesses  70  between the pads  50 . The recesses reduce the diameter of the sleeve so that fluid can always flow past the sleeve  14  at the anchoring means  62 . 
   In use, tool  10  is located in a work string using the box section  26  and the pin section (not shown). The work string is then run into casing  17  until the tool  10  reaches a liner top  34 . During run in the ports  36 , 38  are aligned and fluid can pass around the packer elements  18  in an upward direction to achieve a faster run-in rate as the surge effect is reduced. This also allows the tool to have a diameter closer to the tubular diameter. On reaching the liner top  34 , shoulder  28  of the tool  10  contacts the liner top  34 . Weight set down on the work string causes the sleeve  14  to be arrested at the liner top  34  while the body  12  moves downwards relative to the sleeve  14 . This relative movement causes sufficient force to break the shear pin  48  so that the sleeve  14  and body  12  are released from each other. With the sleeve arrested, the downward movement of the body causes a shoulder  74  of the body  12  to move against the packer element  18 . Packer element  18  will expand radially under the compression caused from the shoulder  74  moving towards a shoulder  76  on the sleeve  14  at the opposite side of the element  18 . Continued compression will result in the packer element expanding until it meets the surface  19  of the casing  17 . At this point the element  18  provides a seal within the well bore in the annulus between the tool  10  and the casing  17 . 
   This movement of the sleeve  14  misaligns the port  36 ,  38  and therefore blocks the exit of port  36  into the well bore and instead opens into the channels  42  which end at the rear surface  58  of the pads  50 . As a result, fluid pressure in the annulus above the packer  18  will cause the pads  50  to move radially outwards to contact surface  19  of the casing  17 . This anchors the sleeve  14  within the well bore. Such fluid pressure is created as the pressure differential is induced to perform an in-flow test. 
   In particular, as the sleeve is now fixed, the shoulder  28  is held at the liner top  34 . The fluid pressure at the packer  18  now directed to the pads  50 . Thus, any load transmitted through the packer element  18  to the sleeve  14  will be borne by the pads  50  and thus the liner top  34  is prevented from any additional pressure. Thus all load is now tied back to the tubular. Further, as the pressure is applied radially to the pads  50 , by virtue of pressure applied to their rear surfaces  42 , the pads cannot slip as there is no longitudinal loading applied. 
   With the ports  36 , 38  misaligned, the well bore within the casing  17  is now sealed by the packer element  18 . An in-flow or negative test can be performed. The pressure differential created in the annulus will be used to secure the pads  50  to the tubular. 
   Reference is now made to  FIG. 3  of the drawings which illustrates a packer tool, generally indicated by reference numeral  74 , in accordance with an embodiment of the present invention. Like parts of  FIG. 3  to those of  FIGS. 1 and 2  have been given the same reference numeral but are now suffixed “a”. 
   Packer tool  74  comprises a one piece full length drill pipe mandrel  76  comprising a body  12   a  with a longitudinal bore  21   a  therethrough. A box section  26   a  is located at the top end  24   a  of the mandrel  76  and a corresponding pin section  78  is located at the lower end  80  of the mandrel  76 . Sections  24   a ,  78  provide for connection of the packer tool  74  to upper and lower sections of a drill pipe or work string (not shown). 
   Mounted on the body  12   a  of the mandrel  76  is a packer tool  10   a , described hereinbefore with reference to  FIGS. 1 and 2 . Below the packer tool  10   a  is located a stabilizer sleeve  82 . Sleeve  82  is rotatable in respect to the mandrel  76 . Raised portions or blades  84  on the sleeve  82  provide a “stand off” for the tool  74  from the walls of the well bore and reduce friction between the two during insertion into the well bore. 
   Located below the stabilizer sleeve  82  is a Razor Back (Trade Mark) lantern  86 . This Razor Back lantern (Trade Mark) provides a set of scrapers for cleaning the well bore prior to setting the packer  18   a . Though scrapers are shown, brushing tools such as a Bristle Back (Trade Mark) could be used instead of or in addition to the scrapers. 
   The shoulder  28   a  for operating the sleeve  14   a  of the packer  10   a  is located on a top dress mill  88  at the lower end of the tool  74 . The shoulder  28   a , via abutting surfaces through the intermediary sections  88 ,  86 ,  82  acts on the sleeve  14   a  operation of the tool  74  is achieved through landing the shoulder  28   a  on a formation, such as a polished bore receptacle, to move the sleeve  14   a  relative to the body  12   a  as described hereinbefore. The presence of the top dress mill  88  allows the polished bore receptacle to be dressed prior to setting a packer. 
   The principal advantage of the present invention is that it provides a compression set packer tool to seal by a liner top within a well bore which prevents excess weight or force being placed on the liner top  34 . 
   Advantageously, fluid pressure in the well bore is used to energize and maintain an anchoring device which holds the tool at the liner top once the compression set packer has set. 
   Additionally by anchoring the tool below the packer element after the packer has been set the anchoring means of the present invention can be released so that the anchor is retracted, the packer elements are released from the well bore surface and the tool and work string can be easily removed from the well bore. 
   Additionally, the use of bypass channels around the packer element allows the tool to be dimensioned close to the inner diameter of the tubular without experiencing problems of surging and swabbing. 
   Various modifications may be made to the invention herein disclosed without departing from the scope thereof. In particular, the number, position and shape of the anchoring pads used can be varied. Additionally while longitudinal channels are described to connect the bypass channels to the rear surfaces of the pads, a single channel in the form of a reservoir could alternatively be used so that the pressure on the pads is equalized for use. 
   Where the packer tool comprises a one piece full length drill pipe mandrel, with items such as a stabilizer sleeve, razorback lantern and a mill, the packer tool may alternatively be actuated through a shoulder on the tool being set down on a liner (or other tubular) top. The other items may therefore be dimensioned to pass into the liner; in this situation, the mill may be provided as a stabilizer sleeve mill.