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This application is a divisional application of U.S. patent application Ser. No. 12/436,416 filed May 6, 2009 now U.S. Pat. No. 7,694,746 and which was a divisional application of U.S. patent application Ser. No. 11/595,465, filed on Nov. 9, 2006 now abandoned. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The invention relates generally to methods and packer devices that can be set within a wellbore with little or no reduction in useable cross-sectional bore area. 
     2. Description of the Related Art 
     Wellbore packers are used for securing production tubing inside of casing or a liner within a wellbore. Packers are also used to create separate zones within a wellbore. Unfortunately, conventional packers and techniques for setting packers results in a reduction of usable diameter within the well. This is because the packer is carried by a conveyance tubular (such as a production tubing string) that is of smaller diameter than the tubing or casing against which it is set. The packer is then set within the annular space between the conveyance tubular and the outer tubing or casing. Once set, the useable diameter of the well (i.e., the diameter through which production fluid can flow or tools can be passed) becomes the inner diameter of the conveyance tubular. However, the components of the packer device (including slips, elastomeric seals, setting sleeves and so forth) inherently occupy space between the inner and outer tubulars. For example, a wellbore having standard 21.40 lb. casing with an outer diameter of 5 inches, would have an inner diameter of 4.126 inches. It would be desirable to run into the casing a string of tubing having an outer diameter of approximately 4 inches, which would allow for a tubing string with a large cross-section area for fluid flow and tool passage. However, the presence of presence of packer components on the outside of the tubing string will dictate that a smaller size tubing string (such as 2⅞″) be run. Over an inch of diameter in usable area is lost due to the presence of both the inner production tubing string and the packer device that is set within the space between the production tubing string and the casing. 
     The present invention addresses the problems of the prior art. 
     SUMMARY OF THE INVENTION 
     The invention provides devices and methods for setting a packer inside a wellbore with little appreciable reduction of the useable area of the wellbore. In described embodiments, the outer casing or liner of the wellbore contains one or more integrated casing coupler joints having an increased diameter chamber portion. A large bore packing element is carried within the increased diameter chamber portion. The packing element may be selectively actuated to form a seal against an interior tubular member. Because the packing element is located within the chamber portion of the casing coupler, the packer may be set while saving useable cross-sectional area within the casing. In the instance of the 5 inch casing situation described above, an interior tubing string having a four inch diameter could be run into the exterior casing or liner. 
     Rather than being conveyed into the wellbore on the tubing string, the packer device is already disposed within the well prior to running of the tubing string. They are then activated using activation components that are run into the wellbore on the tubing string. 
     In one embodiment, the packer device comprises an axially compressible sealing element that may be formed of a ductile metal. The ductile metal may be integrated with elastomeric or non-elastomeric sealing elements, if desired. The sealing element is axially compressed by camming action by a setting sleeve member that is also located within the increased diameter portion of the casing coupler. The setting sleeve preferably includes an engagement profile that can be engaged by a complimentary engagement member, which may be integrated into the tubing string. 
     In a second described embodiment, the compressible element of the packer device is set by a coarsely threaded setting sleeve that is helically moveably engaged with an interior surface of the casing coupler. The threaded setting sleeve includes a rotational engagement key that can be engaged by a complimentary engagement member, which may be carried on the tubing string that is inserted into the casing string. To set the packer device, the setting sleeve is rotated with respect to the casing coupler. 
     In a third described embodiment, the element is set by moveable conical surface that urges the sealing element radially inwardly and against the tubing string. In further exemplary embodiments, the packer device is set by an energizing setting power source that is retained within the wellbore casing and preferably within the casing coupler itself. The power source can comprise a fluid chamber or a compressed spring. The tubing string is adapted to release or energize the stowed energy source. The release or energization may be accomplished a number of ways, including the use of a latch member to engage a portion of the energy source and release it or by use of a tag device, such as an RFID (radio frequency identification) tag that will release or energize the power source upon electronic recognition. If desired, a delay could be incorporated into the setting mechanism. 
     In a further described embodiment, the packer device is actuated hydraulically via fluid that is pumped down the production tubing string and into the enlarged diameter chamber. In still another described embodiment, a ductile tube is attached to the tubing string and, by hydraulic or mechanical methods, the ductile tube is inflated radially outwardly and forms a metal-to-metal or metal-to-non-metal seal with the sealing device contained within the casing coupler. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a thorough understanding of the present invention, reference is made to the following detailed description of the preferred embodiments, taken in conjunction with the accompanying drawings in which like reference characters designate like or similar elements throughout the several figures of the drawing. 
         FIG. 1  is a side, cross sectional view of an exemplary packer device constructed in accordance with the present invention. 
         FIG. 2  is a side, cross sectional view of the packer device shown in  FIG. 1 , now having been set. 
         FIG. 3  is a side, cross-sectional view of an alternative packer device constructed in accordance with the present invention. 
         FIG. 4  is a side, cross-sectional view of the packer device shown in  FIG. 3 , now with having been set. 
         FIG. 5  is a side, cross-sectional view of a further alternative packer device constructed in accordance with the present invention. 
         FIG. 6  is a side, cross-sectional view of the packer device shown in  FIG. 5 , now having been set. 
         FIG. 7  is a side, cross-sectional view of an alternative packer device constructed in accordance with the present invention and utilizing a hydraulic setting arrangement for setting the packer device. 
         FIG. 8  is a side, cross-sectional view of the packer device shown in  FIG. 7 , now having been actuated to a set position. 
         FIG. 9  is a side, cross-sectional view of an alternative packer device also utilizing a hydraulic setting arrangement. 
         FIG. 10  is a side, cross-sectional view of the packer device shown in  FIG. 9 , now having been actuated to a set position. 
         FIG. 11  is a side, cross-sectional view of a further exemplary packer device which incorporates a ductile, radially expandable tube. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       FIGS. 1 and 2  illustrate an exemplary wellbore  10  that has been drilled through the earth  12 . The wellbore  10  is lined with a string of casing, of which two casing sections  14 ,  16  are depicted. A casing coupler  18  interconnects the casing sections  14 ,  16  to form a casing string  17  that defines a central bore  19  along its length. Cement  20  surrounds the casing sections  14 ,  16  and casing coupler  18 . It is noted that the casing coupler  18  has a greater diameter than the casing sections  14 ,  16  and is secured to each of the casing sections  14 ,  16  via threaded connections  22 ,  24 , respectively. 
     The casing coupler  18  includes an axial bore  26  for passage of tools and fluid through the casing coupler  18 . The bore  26  has an enlarged diameter chamber portion  28 . A packer device  30  is disposed within the enlarged diameter chamber portion  28 . The packer device  30  includes a cylindrical elastomeric packer sealing element  32  and a cylindrical setting sleeve  34 . The setting sleeve  34  is a compression member that is axially moveable within the enlarged diameter portion  28  of the bore  26 . The setting sleeve  34  features an axial bore  36  with an engagement profile  38  within. A ratchet-style body lock ring assembly  37 , of a type known in the art, is associated with the outer radial diameter surface of the setting sleeve  34 . The body lock ring assembly  37  provides for limited one-way movement of the setting sleeve  34  with respect to the surrounding casing coupler  18 . 
       FIGS. 1 and 2  depict actuation of the packer device  30  to create a seal between the casing string  17  and a string of production tubing  40 , the lower end of which is visible in  FIG. 2 . The lower end of the production tubing string  40  includes a setting tool  42  for actuation of the packer device  30 . In  FIG. 1 , the packer device  30  is in an initial, unset position. In one embodiment, the setting tool  42  includes a cylindrical tool body  44  having a plurality of collets  46  extending axially therefrom. Each of the collets  46  carries a radially enlarged portion  48  that presents a stop shoulder  50  and a tapered camming surface  52 . The enlarged portion  48  is shaped and sized to fit within the engagement profile  38  of the setting sleeve  34 . 
     To activate the packer device  30 , the production tubing string  40  and setting tool  42  are inserted into the casing string  17 . The tapered camming surface  52  of each collet  46  will contact the upper ends of the sealing element  32  and the setting sleeve  34  and deflect the collet  46  radially inwardly. When the radially enlarged portion  48  of each collet  46  becomes aligned with the engagement profile  38  of the setting sleeve  34 , each collet  46  will snap radially outwardly so that the radially enlarged portion  48  becomes disposed within the engagement profile  38 , as shown in  FIG. 2 . Once the setting tool  42  is attached to the setting sleeve  34  in this manner, the tubing string  40  is then pulled upwardly to cause the setting sleeve  34  to be moved axially upwardly within the enlarged diameter portion  28  of the bore  26 . The collets  46  are not disengaged from the engagement profile  38  due to abutting contact between the stop shoulder  50  and the upper end  54  of the profile  38 . The  38 . The sealing element  32  is thereby axially compressed by the setting sleeve  34  and, when axially compressed, will be extruded radially inwardly against the tool body  44  of the production tubing string  40 . The body lock ring assembly  37  will prevent the setting sleeve  34  from moving back downwardly with respect to the surrounding casing coupler  18 , thereby preventing the packer device  30  from becoming unset. 
     Because the components of the packer device  30  are retained within an enlarged diameter portion  28  of the casing coupler  18 , the gap between the exterior of the tubing string  40  and the interior of the casing string  17  can be quite small. For example, in a casing string made up of 35.3 lb. Casing sections with an external diameter of 5 inches, an interior diameter of 4.126 inches would be available. With the large bore, external packer arrangement described above, it would be possible to insert a tubing string  17  having a diameter approximating 4 inches, rather than a smaller diameter tubing string (i.e., 2⅞″). In fact, the use of a larger diameter tubing string is desirable for two reasons. First, the resulting available cross-sectional flow and work bore area of the tubing string  17  will be larger. Second, the sealing element  32  of the packer device  30  can more easily and securely seal against the larger diameter tubing string  17 . 
       FIGS. 3 and 4  illustrate an alternative embodiment of the invention wherein a packer device  30 ′ has a sealing element  32  and a setting sleeve assembly  60 . The setting sleeve assembly  60  includes an inner setting sleeve member  62  having an external helical thread  64  and an internal helical thread  66  that is formed on the interior of the enlarged diameter portion  28 . It is noted that the external and internal threads  64 ,  66  are interengaged with one another in a well-known manner such that rotation of the sleeve member  62  within the casing coupler  18  will move the sleeve member  62  axially within the coupler  18 . One or more key slots  68  are located on the radial interior of the sleeve member  62 . 
     In  FIG. 3 , the packer device  30 ′ is in an unset, initial position. In  FIG. 4 , a production tubing string  40  has been inserted into the casing string  17 . A setting component  70  is secured to the lower end of the production tubing string  40  and presents radially extending keys  72  that are shaped and sized to fit within the key slots  68 . It is noted that the keys  72  are preferably spring-biased radially outwardly from the body of the setting component  70  so that they may be compressed radially inwardly as needed for disposal down through the casing string  17  and to pop radially outwardly upon encountering the key slots  68 . When the keys  72  are located within the key slots  68 , the inner sleeve member  62  is secured rotationally with respect to the setting component  70  such that rotating the tubing string  40  and setting component  70  will rotate the sleeve member  62 . In order to set the packer device  30 ′, the tubing string  40  is rotated at the surface to cause the sleeve member  62  to move axially upwardly with respect to the casing coupler  18 , thereby radially compressing the sealing element  32  and causing it to seal against the tubing string  40 . In this embodiment, no body lock ring is required to maintain the packer device  30 ′ in the set position. The inward compressive force exerted by the sealing element  32  upon the outer radial surface of the tubing string  40  should be sufficient to prevent counter-rotation of the tubing string  40  within the casing string  17  that might cause the packer device  30 ′ to become unset. 
       FIGS. 5 and 6  depict a further alternative embodiment for a packer device  30 ″ constructed in accordance with the present invention. The packer device  30 ″ includes a sealing element  72  having a ductile metallic body  74  and elastomeric sealing portions  76 . A suitable sealing element of this type is the “ZX” packing element that is available commercially from Baker Oil Tools of Houston, Tex. It is noted that the exterior radial surface  77  of the sealing element  72  is substantially conical in shape such that the lower axial end  78  of the sealing element  72  presents a smaller diameter than the upper axial end  80 . 
     Also included in the packer device  30 ″ is a setting sleeve member  82  having a generally cylindrical sleeve body  84  that defines a central axial bore  86  with an interior engagement profile  88 . A body lock ring assembly  37  is associated with the outer radial surface of the sleeve body  84  and provides for limited one-way movement of the setting sleeve member  82  with respect to the surrounding casing coupler  18 . A tapered bore portion  90  is located proximate the upper end  92  of the body  84  thereby providing a ramped surface that is in abutting contact with the outer radial surface  77  of the sealing element  72 . 
       FIG. 5  depicts that packer device  30 ″ in an unset condition. In  FIG. 6 , a production tubing string  40  has been disposed into the casing string  17 . A setting tool component  94  is secured to the lower end of the tubing string  40  and presents axially extending collets  96  with radially outwardly projecting portions  98  that are shaped and sized to reside within the engagement profile  88  of the setting sleeve member  82 . As the tubing string  40  is lowered through the casing string  17 , the collets  96  are deflected radially inwardly until the outwardly projecting portions  98  encounter the engagement profile  88  and snap radially outwardly to reside within the engagement profile  88  to secure the tubing string  40  to the setting sleeve member  82 . Then, the tubing string  40  is raised to cause the setting sleeve member  82  and urge the ramped surface of tapered bore portion  90  axially against the outer radial surface  77  of the sealing element  72 . This axial movement causes the body the body  74  of the sealing element  72  to be cammed radially inwardly and deformed radially inwardly against the production tubing string  40 . Operation of the body lock ring assembly  37  will maintain the packer assembly  30 ″ in the set position. 
     Variations on the packer device  30 ″ are possible wherein the sealing element  72  is formed entirely of metal and without the elastomeric sealing portions  76 . When the packer device  30 ″ is set, a metal-to-metal seal is formed. Such a variation may be advantageous in many instances wherein, for example, there is a minimum amount of movement of the components needed to form an effective seal. Where a fully metallic sealing element is employed, the sealing element may be a bellow-type seal or a hydroformed seal or ring element. Additionally, a metal-to-metal seal may incorporate toothed slips, of a type known in the art, or other mechanisms for creating a biting engagement between the tubing string  40  and the surrounding casing string  17 . 
     Currently, each of the packer devices  30 ,  30 ′ and  30 ″ are permanently set packer devices. They may be removed from the wellbore, if desired, by use of a suitable milling tool, as is known in the art. 
       FIGS. 7 and 8  illustrate a further exemplary packer device  100  that employs an energy source that is contained within the casing string  17  prior to disposing the tubing string  40  into the casing string  17 . The enlarged diameter chamber  28  of the casing coupler  18  contains an outer collar  102  and an inner collar  104 . The inner collar  104  is disposed radially within the outer collar  102 , and a chamber  106  is defined radially between the two collars  102 ,  104 . Flanged end portions  108  and seals  110  are provided for each of the collars  102 ,  104 . The outer collar  102  presents an upper axial end portion  112  that lies in contact with the sealing element  32 . A recess  114  is inscribed within the interior radial surface  116  of the outer collar  102 . An annular seal member  118  is fixedly secured to the inner collar  104  and is, in turn, secured to a split ring, or C-ring member  120 . In the unset position, depicted in  FIG. 7 , the split ring  120  resides within the recess  114  of the outer collar  102 . As noted, the chamber  106  is defined radially between the inner and outer collars  102 ,  104 , at its upper end by seal  110 , and at its lower end by seal member  118 . A split ring actuator  122  (visible in  FIG. 7 ) is operably interconnected with the split ring  120 . The split ring actuator  122  preferably comprises a programmable electronic transceiver that is designed to receive a triggering signal from a transmitter. Signal transmitter  124  is incorporated within the tubing string  40 . In one currently preferred embodiment, the signal transmitter  124  may comprise an RFID (radio frequency identification) tag or chip which is designed to emit a triggering signal upon passing within a certain proximate distance of the actuator  122 . The actuator  122  is operably associated with the split ring  120  to retract the split ring  120  radially inwardly and out of the recess  114  upon receipt of the signal from the transmitter  124 . Radial retraction of the split ring  120  may be done by the actuator mechanically, magnetically, or using other suitable known techniques. 
     The chamber  106  may be an atmospheric chamber or a more highly pressurized chamber, which will create a pressure differential across the seal member  118  which will urge the end portion  112  of the outer collar  102  toward the sealing element  32  and a set position. In variations on this embodiment, the chamber  106  could be replaced with a mechanical spring to serve as an energy source to bias the outer collar  102  toward the sealing element  32 . Additionally, the transmitter  124  and actuator  122  could be replaced by a mechanical trigger arrangement wherein the spring is mechanically released from a compressed state by engaging a release latch for the spring with an engagement member within the tubing string  40 . 
     In operation, the packer device  100  is in the initially unset position shown in  FIG. 7 . The tubing string  40  is lowered into the casing string  17  until the transmitter  124  is located proximate the actuator  122 . The triggering signal is received by the actuator  122 , which then releases the split ring  120  from the recess  114 . If desired, a delay could be incorporated into the programming of the actuator  122  such that a predetermined period of time elapses between the time the triggering signal is received by the actuator  122  and the split ring  120  is released from the recess  114 . When the split ring  120  is released from the recess  114 , fluid pressure within the chamber  106  will urge the outer collar  102  axially upwardly so that the upper end  112  will compress the sealing element  32 . The sealing element  32  will be deformed radially inwardly to seal against the tubing string  40 , as depicted in  FIG. 8  to create a seal. 
     Referring now to  FIGS. 9 and 10 , a further exemplary packer device  130  is depicted which utilizes hydraulic setting via the tubing string  40 . The sealing element  32  is retained within the chamber  28  along with a setting piston  132 . The setting piston  132  features an enlarged compression head portion  134  that abuts the sealing element  32  and a reduced diameter stem portion  136  that extends downwardly from the head portion  134 . A ratchet mechanism  138  is located at its lower end of the stem portion  136  and operates in the manner of a body lock ring to ensure one-way sequential movement of the setting piston  132  with respect to the surrounding casing coupler  18 . 
     A fluid chamber  140  is defined between the setting piston  132  and the casing string  17  within the enlarged chamber  28 . Fluid flow ports  142  are disposed through the setting piston  132  to permit fluid communication between the fluid chamber  140  and the interior flowbore  144  of the setting piston  132 . Fluid seals  146  are provided between the setting piston  132  and the casing coupler  18  to ensure fluid tightness of the fluid chamber  140 . 
     The lower end of the tubing string  40  is closed off by a plug  148 . The plug  148  is preferably a temporary or removable plug which can be removed to allow flow through the tubing string  40  at a later point during production operations. Ports  150  are disposed through the side of the tubing string  40 . 
     In operation, the packer device  130  is initially in the unset position depicted in  FIG. 9 . The tubing string  40  is then disposed into the casing string  17  until the ports  150  of the tubing string  40  are generally aligned with the fluid flow ports  142  in the setting piston  132 . The interior flowbore  152  of the tubing string  40  is then pressurized so that fluid is flowed through the aligned ports  150  and  142  and into the fluid chamber  140 . The setting piston  132  is urged upwardly by the fluid pressure so that the enlarged head portion  134  compresses the sealing element  32 . Axial compression of the sealing element  32  causes the sealing element  32  to deform radially inwardly and seal against the tubing string  40 , as depicted in  FIG. 10 . The ratchet mechanism  138  ensures that the packer device  130  remains in the set position. 
       FIG. 11  depicts a further exemplary embodiment of the invention wherein a sealing element  200  is contained within the chamber  28  of the casing coupler  18  and an inflatable, or radially expandable, ductile tube  201  is made up into the production tubing string  40 . The ductile tube  201  is formed of a material that permits the tube  201 , or portions thereof, to be deformed radially outwardly. One such material is a nickel alloy. To create a create a seal, the ductile tube  201  is inflated or expanded radially outwardly until its radially outer surface is brought into sealing contact with the sealing element  200 . The ductile tube  201  can be inflated or expanded radially outwardly using a number of techniques for radially expanding ductile tubular members. One technique for inflating the ductile tube  201  is to seat a dart, ball, or other pug member  202  upon a seat  204  to seal off the flowbore  152  of the tubing string  40  below the ductile tube  201 . Fluid pressure is then increased within the flowbore  152  above the plug member  202  to cause the ductile tube  201  to expand radially outwardly, as illustrated in  FIG. 11 . In this embodiment, as well, the plug member  202  may be a temporary or removable plug member. Alternatively, a mechanical means, such as a suitable swaging instrument, can be used to radially expand the ductile tube  201  radially outwardly. 
     The sealing element  200  may be a metallic sealing element or a non-metallic sealing element. In one embodiment, the sealing element  200  is an elastomeric sealing element. In another embodiment, the sealing element  200  is a mechanical sealing element and contains toothed portions to form a biting engagement with the ductile tube  201 . The design of the sealing element  200  will preferably provide fluid sealing and mechanical retention between the inflatable tubing  201  and the casing coupler  18 . The sealing contact between the ductile tube  201  and the sealing element  200  forms a retention device between the tubing string  40  and the surrounding casing string that is capable of withstanding high axial tubing loads. 
     Those of skill in the art will appreciate that the present invention provides a novel wellbore packer arrangement as well as a wellbore production system that includes an outer tubular string having an enlarged diameter chamber portion; an inner tubular string; and a and a packer device disposed at least partially within the enlarged chamber to form a seal against the inner tubular string. 
     The present invention also provides methods of establishing a seal between inner and outer tubular string members within a wellbore wherein a packer device is disposed within an enlarged diameter chamber portion of an outer tubular string. The outer tubular string, such as a string of casing or liner, is run into a wellbore and cemented in place. At this point the packer device is in an unset position. Next, the inner tubular string is run into the outer tubular string to a predetermined depth or position within the outer string. The predetermined depth or position will typically correspond to the proper location of a tool, such as a production nipple, inside the outer tubular string. The packer device is then actuated from an unset to a set position to form a seal against a member of the inner tubular string. 
     Those of skill in the art will recognize that numerous modifications and changes may be made to the exemplary designs and embodiments described herein and that the invention is limited only by the claims that follow and any equivalents thereof.

Summary:
Devices and methods for setting a packer inside a wellbore with little appreciable reduction of the useable area of the wellbore. The outer casing or liner of the wellbore contains one or more integrated casing coupler joints having an increased diameter chamber portion. A large bore packing element is carried within the increased diameter chamber portion. The packing element may be selectively actuated to form a seal against an interior tubular member. Because the packing element is located within the chamber portion of the casing coupler, the packer may be set while saving useable cross-sectional area within the casing.