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BACKGROUND OF THE INVENTION  
       [0001]     Packers are installed in petroleum industry wellbores to isolate adjacent zones or regions from one another. Particularly, packers are used in petroleum production installations to isolate the annulus between a string of production tubing and a cased borehole to prevent the unwanted escape of production fluids.  
         [0002]     Packers typically function by expanding one or more elastomeric packer elements to fill any gaps between the production tube (or a through bore of the packer) and the wellbore (either cased or open). The packer element can be expanded either by “inflating” the elastomeric elements with pressurized fluid or by upsetting flexible elements through axial compression. Additionally, packers may also include anchor devices to “bite” into the tubing or wellbore in which they are to be set. Slips of the anchor mechanism are often set and ratcheted in place to prevent the packer from displacing axially up or down the bore once it is set. Irrespective of construction or the deployment method used, packers effectively create fluid seals between an inner tubular member and an outer tubular member.  
         [0003]     Furthermore, packers can be constructed to be either retrievable or permanent. Retrievable packers are preferably constructed so they can be set or retrieved into or out of a borehole with special tools and procedures. In contrast, permanent packers are not so easily retrieved. Because of their design and intent for long-term emplacement, most “permanent” packers must be destructively cut to release them from the location in which they are installed. This cutting operation typically severs mechanical devices that engage the bore to make the packer&#39;s engagement therewith permanent. Because slips of packer anchors are typically configured with one-way ratchet profiles, they cannot be easily released once engaged. As such, a cutting operation will be undertaken to cut and disengage the slips of the anchor mechanism so the packer assembly can be retrieved.  
         [0004]     Currently, operations to remove a permanent packer or anchor involve running of a cutter assembly downhole to the location of the device to be cut. Next, a chemical or mechanical cutter head is activated and severs the critical components of the device to be released. The cutter assembly is then retrieved (leaving the crippled packer or anchor behind) so that a retrieving, or fishing, apparatus could be run into the hole to remove the severed packer assembly. Because a minimum of two trips downhole is required, an operation using this procedure can take considerable time and cause significant delays in downhole operations. Furthermore, because the cut packer is left in place while the cutter assembly is retrieved from and the fishing assembly is run into the hole, there is a chance the packer can fall deeper into the wellbore. As such, it is desirable that the cutting operations to retrieve packers and other anchor components to run as quickly as possible. Any apparatus or methods to improve cutting and retrieval operations for anchored downhole components would be well received in the industry.  
       SUMMARY OF THE INVENTION  
       [0005]     The deficiencies of the prior art are addressed by an apparatus to cut and release a downhole anchor. The apparatus preferably includes a housing deployed upon a string of tubing in a wellbore, wherein the housing includes an engagement adapter at its distal end. The apparatus preferably includes a cutter assembly in a recessed position within the distal end of the housing. Preferably, the engagement adapter corresponds with an engagement profile of the downhole anchor. Preferably, the cutter assembly is configured to extend from the recessed position when the string of tubing is axially loaded. Preferably, the cutter assembly is configured to cut and release the downhole anchor when activated in the extended position. Preferably, the engagement adapter is configured to retain the downhole anchor and retrieve it from the wellbore after the cutter assembly is activated.  
         [0006]     The deficiencies of the prior art are also addressed in part by a method to remove an anchor device from a wellbore. The method preferably includes deploying a string of tubing down the wellbore to the anchor device, wherein the string of tubing has an engagement adapter and a recessed cutter at a distal end thereof. The method preferably includes engaging the engagement adapter within an engagement profile of the anchor device. The method preferably includes extending the recessed cutter. The method preferably includes activating the extended cutter and cutting the anchor device with the activated cutter. The method preferably includes retrieving the string of tubing from the wellbore to remove the cut anchor device attached thereto.  
         [0007]     The deficiencies of the prior art are also addressed in part by a cut and release tool to retrieve an engaged downhole anchor. The cut and release tool preferably includes a main body disposed at a distal end of a string of tubing disposed within a wellbore. The cut and release tool preferably includes an explosive cutter recessed within the string of tubing and within the main body and an engagement adapter connected to the main body and configured to securely engage with a corresponding profile of the downhole anchor. Preferably, the cutter is configured to extend from a recessed position when the string of tubing is axially loaded. Preferably, the cutter is configured to cut and release the downhole anchor when detonated. Preferably, the threaded adapter is configured to retain the downhole anchor and retrieve it from the wellbore after the cutter is detonated.  
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0008]      FIG. 1  A-D is a schematic section-view drawing of a one-trip cut to release tool in accordance with an embodiment of the present invention.  
         [0009]      FIG. 2  A-E is a schematic section-view drawing of a one-trip cut to release tool having a retracted cutting head and engaged within a downhole packer in accordance with an embodiment of the present invention.  
         [0010]      FIG. 3  A-E is a schematic section-view drawing of the one-trip cut to release tool of  FIG. 2  engaged within a downhole packer wherein the cutting head is extended. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0011]     Referring to  FIG. 1 , a one-trip cut to release tool assembly  100  capable of severing and retrieving a downhole anchor device is shown. While the term downhole anchor is used throughout this description, it should be understood that a downhole anchor could be any device installed downhole in such a way as to isolate a region, position or orient tools, or otherwise restrict access to a portion of the borehole. Therefore, the term “downhole anchor” includes, but is not limited to, packers, anchors, bore plugs, whipstocks, and muleshoes. Furthermore, while this disclosure is directed to the retrieval of “permanent” anchor devices, i.e. those that require a destructive cutting or severing operation to be removed, it should be understood that the present invention might include the cutting and releasing of “retrievable” anchor devices as well.  
         [0012]     Cut to release tool  100  is preferably deployed downhole upon a distal end of a string of tubing (not shown) and connected at coupling  102 . A string of thrust tubing  104  connects coupling to a main body  106  of cut to release tool assembly  100 . A lower string of tubing  108  extends from main body  106  to an engagement adapter  110  that is configured to engage within a corresponding engagement profile of a downhole packer or anchor. An internal string of activation tubing  112  extends from within thrust tubing  104  to main body  106 , terminating at a sliding mandrel  114 . A hydraulic inlet  116  allows fluid from inside thrust tubing  104  to communicate with activation tubing  112 . Optionally, a hydraulic line (not shown) can extend from a surface station to hydraulic inlet  116  through the bore of thrust tubing  104  to allow more direct control of cut to release tool  100 . Activation tubing  112  and mandrel  114  are preferably configured to be slidably engaged within lower tubing  108  when shear screws  118  are ruptured and thrust tubing  104  is thrust downward.  
         [0013]     A hydraulically activated cutter assembly  120  is connected to activation tubing  112  at a distal end of mandrel  114 . Cutter assembly  120  includes a cutter head  122  carrying a shape charge  124  capable of severing a downhole anchor, a downhole packer, or any other downhole well tool. Shape charge  124  is preferably configured to be hydraulically detonated but can be detonated through any means known in the art. While a shape charge detonation cutter  120  is shown, it should be understood that other types of cutters  120  including hydraulic cutters and chemical cutters, may be used. A thick-walled line  126  extends from cutter head  122  through tubing  108  to a union  128  with activation tubing  112 . To activate and fire shape charge  124  of cutter head  122 , hydraulic pressure is increased in activation tubing  112  through hydraulic inlet  116  until a detonation device  130  is activated and sends a detonation shock to shape charge  124  through thick walled line  126 .  
         [0014]     To release an emplaced downhole anchor or packer, the one trip cut to release assembly  100  is deployed and activated to sever components that maintain a grip on the inner wall of the bore in which the device is retained. Cut to release assembly  100  is deployed upon the distal end of a string of tubing connected at coupling  102 . The string of tubing can be a string of drill pipe, coiled tubing, slickline, or any other structural conduit capable of transmitting axial loads and hydraulic pressure downhole. Furthermore, safety plugs  134  prevent any premature detonation of cutter head  122  while cut to release tool  100  is on the rig floor or before it is run downhole. Therefore, safety plugs  134  must be removed prior to running cut to release assembly  100  downhole.  
         [0015]     Cut to release assembly  100  is run downhole until adapter  110  engages within a corresponding profile of the device to be cut. Preferably, the engagement profile is located above the point of severance to ensure the one-trip cut to release assembly  100  is not damaged by the detonation. With one-trip cut to release assembly  100  engaged within the device to be cut, cutter assembly  120  is extended and detonated. Cutter assembly  120  is delivered downhole in a retracted (shown) position to prevent premature detonation of shape charge  124  from contact with downhole components. Furthermore, a shroud  132  below engagement adapter  110  protects firing head  122  from incidental damage and provides a portal through which cutter assembly  120  extends.  
         [0016]     Before cutter assembly  120  can be extended beyond shroud  132  and detonated, shear screws  118  must first be ruptured. Shear screws  118  retain mandrel  114  within main body  106  and thereby prevent the extension of cutter assembly  120 . Each shear screw  118  is preferably designed as a screw or pin manufactured out of a material having known shear strength. With the shear strength known, the cross-sectional area of each shear screw  118  can be sized such that screws  118  will rupture and allow relative movement between mandrel  114  and main body  106  when a pre-defined tension load limit is exceeded. Shear screws  118  shown in  FIG. 1  are preferably designed to rupture when thrust tubing  104  is pulled up with a predetermined amount (e.g. 30,000 pounds) of axial tension.  
         [0017]     Once shear screws  118  are ruptured, tubing  104  is thrust downward to extend cutter assembly  120  downhole through shroud  132  and clear of engagement adapter  110 . Thrust tubing  104  is preferably designed to have a downward stroke equal to the distance cutter head  122  is required to be extended below shroud  132 . Because each anchor device to be cut will have a unique “weak point” where it is to be severed, the stroke of thrust tubing  104  is preferably selected such that cutter head  122  is positioned adjacent to that weak point when thrust tubing  104  is fully displaced. Bow springs  136  are engaged through ratchet profiles  138  of thick-walled hydraulic line  126  to stabilize and hold cutter assembly  120  in position once cutter head  122  is extended and detonated.  
         [0018]     Furthermore, when thrust tubing  104  is fully displaced, coupling  102  is seated within a sealing profile  142  at a distal end of main body  106 . Sealing profile  142  provides a pair of hydraulic seals  144 ,  146 , so that a hydraulic port  148  of coupling  102  is no longer exposed. Prior to full displacement of tubing  104  and engagement of coupling  102  into profile  142 , hydraulic port  148  acts as a safety measure to prevent the build up of hydraulic pressure within bore of thrust tubing  104  or hydraulic tubing  112 . When coupling  102  is not sealed within profile  142 , any build up of pressure in bore of tubing strings  104  and  112  is released through port  148 . Because detonation device  130  is pressure activated, port  148  assists in preventing the premature firing of cutter assembly  120 . With thrust tubing  104  fully displaced, port  148  of coupling  102  is isolated by seals  144  and  146  so pressure within hydraulic tubing  112  is allowed to increase.  
         [0019]     When cutter head  122  is properly aligned with an anchor device and coupling  102  seated within profile  142 , hydraulic pressure is increased within tubing  112  until detonation device  130  is activated. Once activated, detonation device  130  transmits energy to detonate shape charge  124  of cutting head  122  and sever the critical components of the anchor device. Detonation can be instant or delayed, depending on the particular configuration of detonation device  130 . Furthermore, detonation device  130  can be constructed to detonate shape charge  124  through electrical, hydraulic, mechanical, or shock energy once activated. Additionally, detonation device  130  can be omitted and an electrical line extended to firing head  122  through bore of tubing  104  from the surface, if desired.  
         [0020]     If firing head is properly aligned within the downhole anchor device when fired, the anchor device should be released from engagement with the wellbore and can be retrieved upon the distal end of one-trip cut to release assembly  100 . Engagement adapter  110  is preferably configured to retain engagement of the downhole anchor device after detonation so the device can be severed and retrieved in a single trip downhole. In the event cutting head  122  does not sever the downhole anchor device completely, one-trip cut to release assembly  100  can be configured to be released from the anchor device and retrieved from the wellbore, allowing for a second attempt to be made.  
         [0021]     Alternatively, one-trip cut to release assembly  100  can be constructed to allow a second detonation. Shear screws  140  holding main body  106  and lower string of tubing  108  together can be sheared through increased axial tension to allow a new cutter assembly  120  to be delivered and fired. This arrangement is particularly useful when engagement adapter  110  and corresponding profile of the downhole anchor is not easily separated. Particularly, it is important that the rupture shear strength of screws  140  is higher than that of screws  118  to prevent accidental separation of lower tubing  108  from main body  106  when attempting to release mandrel  114  as mentioned above. A replacement cutter assembly  120  can be constructed such that anchor device is severed at a different location than before. Preferably, the replacement cutter assembly  120  engages main body  106  or lower tubing  108  in such a way as to allow the anchor device to be retrieved after a successful firing.  
         [0022]     Referring now to  FIGS. 2 and 3 , a cut to release tool assembly  200  similar to that shown in  FIG. 1  is shown engaged within a downhole anchor assembly  300 . Downhole anchor assembly  300  includes a packer  302  located between an engagement profile  304  and a lower tubing assembly  306 . Lower tubing assembly  306  optionally includes a latching profile  308  in which a lower retrieval device (not shown) of cut to release assembly  200  may be engaged. Furthermore, lower tubing assembly  306  can either include a string of downhole tools and equipment or can be absent altogether if packer  302  is the only component of anchor assembly  300  to be retrieved.  
         [0023]     Referring specifically to  FIG. 2 , cut to release tool assembly  200  is shown in its retracted, as-delivered, configuration with cutter head  222  retracted within shroud  232  and thrust tubing  204  secured in its fully extended position relative to main body  206  by shear screws  218 . In this configuration, cut to release assembly  200  is delivered to anchor assembly  300  and engagement adapter  210  of cut to release assembly  200  is engaged within engagement profile  304 . Engagement adapter  210  can engage and lock within profile  304  through various methods including, but not limited to, ratchet profiles, threads, or any other type of engagement profile known in the art of downhole tools. Engagement adapter  210  is preferably constructed to be held by profile  304  with sufficient grip to support and retrieve entire anchor assembly  300  to be removed from the borehole. Alternatively, engagement adapter  210  can be configured to release from profile  304  under circumstances where cutter head  222  has detonated and packer  302  is not released. Such a configuration allows the retrieval and re-deployment of cut to release assembly  200  so that a second attempt at severing packer  302  can be made.  
         [0024]     With engagement adapter  210  secured within profile  304 , cut to release tool  200  is ready to be extended and activated. First, as with cut to release tool  100  of  FIG. 1 , thrust tubing  204  and coupling  202  are upwardly loaded in tension until shear screws  218  are ruptured. Once ruptured, downward axial compressive force is applied to move coupling  202 , thrust tubing  204 , activation tubing  212 , and hydraulic firing head  222  into an extended position ( FIG. 3 ).  
         [0025]     Referring now to  FIG. 3 , cut to release tool assembly  200  is shown engaged within downhole anchor assembly  300  and in the extended, ready to activate, position. In the extended position, coupling  202  is hydraulically seated within sealing profile  242  of main body  206 . Seals  244  and  246  hydraulically isolate a port  248  within coupling  202  so hydraulic fluids can no longer escape therethrough. Formerly, in the retracted position, pressure increases within bore of thrust tubing  204  and coupling  202  would be diverted through port  248  of coupling  202 . This diversion prevents the premature activation of cutting head  222  by uncontrolled pressure increases or spikes. With cutting head  222  extended, premature activation is no longer as high of a concern. Bow springs  236  act to centralize cutting head  222  within the bore of packer  302  to prevent damage to cut to release assembly  200  and to ensure thorough cutting upon activation of cutting head  222 .  
         [0026]     Furthermore, the stroke, or length of displacement of thrust tubing  204  between retracted position ( FIG. 2 ) and extended position ( FIG. 3 ), is calculated to place cutting head  222  in exactly the location relative to packer  302  predicted to have the highest probability of severing packer  302  in a single firing. Cutting head  222  can be of any type of cutting head known by one skilled in downhole cutting operations including, but not limited to, shape charge detonation heads, chemical cutting heads, and mechanical cutting heads. Cutting head  222  of  FIGS. 2 and 3  is a shape-charge cutting head, one that uses an explosive shape charge  224  to detonate and cut vital components of packer  302  in a predetermined pattern. Shape charge  224  is preferably configured such that packer  302  is severed but cut to release tool assembly  200  is unharmed. Furthermore, as shape charge  224  is preferably configured to detonate radially outward from cutting head  222 , shape charge  224  can be configured as a 360° charge or a non 360° charge. A 360° charge is continuous in 360° around cutter head  222  and cuts a complete circle in packer  302  in one detonation. The benefit of the 360° charge is that the packer is typically completely severed immediately and no radial alignment with components of packer  302  is necessary to obtain a successful release. A drawback of the 360° charge is that absent further structure below cutter head  222 , nothing remains to retain the lower tube assembly  306  if present. Therefore, in certain circumstances, a non-360° shape charge radially aligned at specific locations within packer can be used to sever packer  302  but still retain the ability to lift lower tube assembly  306  without further structure. Alternatively, a lower retainer (not shown) can be located below cutting head  222  of cut to release tool  200  for engagement with profile  308  to retain and lift lower tube assembly at the same time packer  302  is retrieved.  
         [0027]     To detonate shape charge  224  of cutting head  222 , pressure in the bore of thrust tube  204  is increased until an activation pressure is reached. With hydraulic port  248  of coupling  202  securely isolated within profile  242  of main body  206 , increases in pressure in thrust tubing  204  result in increased pressures through hydraulic inlet  216  thereby acting upon detonation device  230 . When sufficient pressure acts upon detonation device  230  for a sufficient amount of time, shape charge  224  is detonated and packer  302  is severed. Following severance, tension is applied to coupling  202  and thrust tubing  204  to retrieve cut to release tool assembly  200 , packer  302 , and the rest of downhole anchor assembly  300  in one return trip. If cutting head  222  is not successful in severing anchor components of packer  302 , additional attempts can be made at deploying additional cutting heads  122  with new shape charges  124  thereon to make successive detonations.  
         [0028]     Numerous embodiments and alternatives thereof have been disclosed. While the above disclosure includes the best mode belief in carrying out the invention as contemplated by the inventors, not all possible alternatives have been disclosed. For that reason, the scope and limitation of the present invention is not to be restricted to the above disclosure, but is instead to be defined and construed by the appended claims.

Summary:
Apparatuses and methods allow a downhole anchor device to be cut, released, and retrieved using a single one-trip cutter and removal assembly. The assembly preferably includes a cutter head recessed behind an anchor latch. The latch is landed to the anchor device to be removed and the cutter head is extended therefrom and activated. Once cut by the cutter head, the anchor device is retrieved upon a distal end of the assembly.