Patent Publication Number: US-11047187-B2

Title: Well abandonment and slot recovery

Description:
The present invention relates to methods and apparatus for well abandonment and slot recovery and in particular, though not exclusively, to an improved apparatus for casing recovery. 
     When a well has reached the end of its commercial life, the well is abandoned according to strict regulations in order to prevent fluids escaping from the well on a permanent basis. In meeting the regulations it has become good practise to create the cement plug over a predetermined length of the well and to remove the casing. Current techniques to achieve this may require multiple trips into the well, for example: to set a bridge plug to support cement; to create a cement plug in the casing; to cut the casing above the cement plug; and to pull the casing from the well. A further trip can then be made to cement across to the well bore wall. The cement or other suitable plugging material forms a permanent barrier to meet the legislative requirements. 
     Each trip into a well takes substantial time and consequently significant costs. Combined casing cutting and pulling tools have been developed so that the cutting and pulling can be achieved on a single trip. 
     When cutting and pulling casing it is advantageous to test for circulation after the cut is completed. Such a test ensures that if there is any build-up of gas bubbles these can be circulated out of the well and also determines if the cut casing section can be pulled. The presence of drilling fluid sediments, cement, sand or other debris behind the casing can prevent the casing from being pulled. In these circumstances a higher cut must be made and again circulation is tested to determine if the casing can be pulled. These steps may occur multiple times until a casing section can be retrieved. Thus it is a requirement of the combined casing cutter and spear tools that they should provide for multiple cuts and circulation tests on a single trip. 
     A difficulty in the design of such combined cutter and spear tools is that when cutting, circulation needs to be maintained with the return path in the annulus between the work string and the casing so that cuttings can return to surface, however for the circulation test this return path needs to be closed to force the return path to be through the cut and behind the casing to surface. 
     U.S. Pat. No. 5,101,895 to Smith International, Inc. discloses a remedial bottom hole assembly for casing retrieval having a spear and an inflatable packer utilized in combination with a pipe cutter. With such an assembly, after the spear is set and the casing is cut, the packer can be inflated to determine if circulation can be established without the removal of the spear and pipe cutter. 
     There are a number of disadvantages with this assembly. Not actuating a seal until the cut is made in order to allow for circulation during the cut leaves the well open so that if a kick occurs during the casing cutting it becomes difficult to quickly get control of the well, as the inflatable packer cannot be set in these circumstances. Additionally, the inflatable packer is operated by a drop ball which requires a choke in the string to get the back pressure for actuation. Such a restriction induces high velocity flow at the choke which causes erosion and potential washout. Yet further, to switch the assembly between modes requires a one eighth turn of the string. Such manipulation cannot reliably be achieved when a cut is made far from surface. 
     US 2012/0285684 to Baker Hughes Inc. discloses a cut and pull spear configured to obtain multiple grips in a tubular to be cut under tension. The slips are set mechanically with the aid of drag blocks to hold a portion of the assembly while a mandrel is manipulated. An annular seal is set in conjunction with the slips to provide well control during the cut. An internal bypass around the seal can be in the open position to allow circulation during the cut. The bypass can be closed to control a well kick with mechanical manipulation as the seal remains set. If the tubular will not release after an initial cut, the spear can be triggered to release and be reset at another location. The mandrel is open to circulation while the slips and seal are set and the cut is being made. Cuttings are filtered before entering the bypass to keep the cuttings out of the blowout preventers. 
     Like the assembly of U.S. Pat. No. 5,101,895 this tool requires measured rotation of the string to switch the tool between modes to undertake a circulation test and to cut the casing, as these tools all operate using j-slot mechanisms. Such manipulation cannot reliably be achieved when a cut is made far from surface. 
     The present Applicants have advantageously determined that a tension-set packer overcomes the disadvantages in the prior art as it is capable of sealing the annulus between the drill string and the casing both for testing and in case of a kick, while also keeping the annulus clear during cutting. The present Applicants now have the TRIDENT™ system. The TRIDENT™ system operates by providing an anchor to the casing, a casing cutter to cut the casing and a tension-set packer to provide a seal over the annulus between the string and casing to create a circulation path behind the casing and so aid casing recovery all in a single trip in the well bore. 
     In this arrangement, the anchor is set to provide stability for the cutter to allow for a fixed point for an overpull to be applied to set the packer. As with all such load set downhole tools i.e. weight set or tension set, they may have difficulties when used from floating rigs such as semi-submersibles. As they are anchored to the casing, sea swell will place tension and/or weight on the drill string and consequently there is a risk that the downhole tool is accidentally actuated by the increased load when a freak wave or lag is experienced at the floating rig. While heave compensators can be used, these still result in movement and the consequential variable load being applied. A known method to prevent the accidental actuation of the downhole tool is to insert a shear pin rated at a higher shear force than the predicted load which may occur in operation. Actuation of the downhole tool must then be achieved with an increased load i.e. a high overpull or significant weight. While the shear pin prevents accidental actuation, it also prevents the downhole tool being re-set. Thus for the tension-set packer multiple circulation tests cannot be performed. This is a major disadvantage. 
     It is therefore an object of the present invention to provide a resettable mechanism to prevent accidental actuation of a load set downhole tool. 
     It is an object of at least one embodiment of the present invention to provide a high overpull tension-set packer. 
     It is a further object of the present invention to provide a casing cutting and removal assembly on which multiple circulation tests can be performed on a single trip in the well. 
     According to a first aspect of the present invention there is provided a resettable mechanism for preventing the accidental actuation of a load set downhole tool, the downhole tool being actuated by an operating load, comprising: 
     a substantially tubular body having a central throughbore, with first and second ends; 
     an inner actuating member, the inner actuating member being an annular body having a first end for connection to an operating member of the downhole tool; 
     a collet including a detent, the detent having first and second faces and the detent being radially moveable upon application of a load; 
     a collet ring, the collet ring having third and fourth faces; 
     the collet and collet ring being arranged within the tubular body, so that: in a first configuration the first face can abut the third face and the detent prevents movement of the inner actuating member until a first load is applied in a first direction; and in a second configuration the detent prevents movement of the inner actuating member until a second load is applied in a second direction relative to the tubular body when the second face abuts the fourth face; and wherein 
     the first load is greater than a combined load of the operating load and a collet load; and 
     the second load is applied in reverse to the first load. 
     In this way, the collet is set to move radially only when a load greater than the highest accidental load which may be experienced by the downhole tool, in use, is applied. Thus a downhole tool, operable by a relatively low actuating load, can be used without the risk of accidental actuation. Additionally, the mechanism can be reset by reversing the load i.e. if a reduction in tension applied by setting down weight or if weight applied by pulling to apply tension. The load required to reset i.e. the second load can also be much smaller than the first load. 
     Preferably the collet is attached to the tubular body. The collet may be formed integrally with the tubular body. More preferably the detent is directed radially inwards. In this way, the collet can be located between the tubular body and the inner actuating member to prevent fouling of the collet fingers. 
     Preferably, the collet ring is supported on the inner actuating member. In this way, movement of the collet ring over the detent causes the downhole tool to actuate when load is applied in a first direction and release when a load is applied in a reverse, second direction. 
     Preferably the resettable mechanism comprises a disengagement assembly, the disengagement assembly disabling the detent so that the downhole tool can be actuated at the operating load in a third configuration. In this way, actuation of the downhole tool can be achieved when the string is not anchored to fixed structure. 
     Preferably the disengagement assembly comprises a collet ring support means, the support means holding the collet ring against a shoulder on the inner actuating member in a first position and releasing the collet ring to move relative to the inner actuating member in a second position. In this way the inner actuating member can move freely past the detent in the first direction when the disengagement assembly is in the second position. 
     Preferably the support means comprises a plurality of collet dogs arranged circumferentially around the inner actuating member. More preferably each collet dog is located in a retaining aperture through the inner actuating member. Preferably a portion of each collet dog protrudes from an outer surface of the inner actuating member to provide a face to abut against the collet ring in the first position. In this way, the collet dogs support the collet ring until they are removed from the apertures. 
     Preferably, the collet dogs are held in the first position by an inner sleeve located in the central throughbore. Preferably the inner sleeve includes a ball seat and is held to the inner actuating member by one or more shear screws in the first position. In this way the sleeve can be released to move relative to the inner actuating member by action of a drop ball. 
     More preferably, the inner sleeve includes an inner recess into which the collet dogs will fall when the disengagement assembly moves into the second position. Preferably also, the inner sleeve comprises first and second ports arranged on either side of the ball seat. More preferably, the ports align with a recess on the inner actuating member in the second position so that a fluid pathway is maintained from a first end to a second end of the resettable mechanism. 
     According to a second aspect of the present invention there is provided a method of controlled actuation of a load set downhole tool; the method comprising the steps:
         (a) mounting a resettable mechanism according to first aspect with a load set downhole tool in a string and connecting the inner actuating member to an operating member of the downhole tool;   (b) arranging the resettable mechanism in a first configuration wherein the first face can abut the third face and the detent prevents movement of the inner actuating member in a first direction;   (c) applying a first load, greater than an operating load of the downhole tool and a collet load, in the first direction sufficient to move the collet radially and allow the inner actuating member to move in the first direction to the second configuration and thereby actuate the downhole tool; and   (d) applying a second load, in the second direction so as to abut the second face and the fourth face and then move the collet ring over the detent to return the mechanism to the first configuration and thereby reset the mechanism and deactivate the downhole tool.       

     In this way, the downhole tool is prevented from actuating until a load greater than its operating load plus the collet load is applied and then the mechanism can be reset so that the downhole tool may be actuated any number of times. 
     The first direction may be downstream so that the downhole tool is a tension set tool. Alternatively, the first direction may be upstream so that the downhole tool is a weight set tool. 
     Preferably the method includes repeating steps (e) and (d) to repeatedly actuate the downhole tool. 
     Preferably the method includes the step of operating the disengagement assembly, so disabling the detent in a third configuration. The method may then comprise the further step of actuating the downhole tool at the operating load. 
     Preferably the method includes the step of releasing support of the collet ring so that it can move relative to the inner actuating member. 
     Preferably the method includes the step of dropping a ball through the central throughbore to operate the disengagement assembly. More preferably, the method includes the step of maintaining a flow path through the release mechanism in each configuration. 
     According to a third aspect of the present invention there is provided a high overpull mechanical tension-set retrievable packer configured to seal to casing or a downhole tubular, comprising: 
     a substantially tubular body having a central throughbore, with first and second ends including connection means for mounting in a string; 
     a mandrel which is configured to be axial moveable relative to a tool body; 
     at least one packer element; and 
     a resettable mechanism according to the first aspect wherein the mandrel is connected to inner actuating member. 
     An upward force or tension applied to the string axially may move the mandrel relative to the tool body. The axial movement of the mandrel relative to the tool body in the first direction may actuate and set the mechanical tension-set retrievable packer. The axial movement of the mandrel relative to the tool body in the second direction may de-actuate the mechanical tension-set retrievable packer. 
     The packer element may be made from any material capable of radially expanding when it is axially compressed such as rubber. 
     The upward force or tension required to the set the mechanical tension-set retrievable packer alone may range from 20,000 lbs to 80,000 lbs. Preferably the upward force or tension to the set the mechanical tension-set retrievable packer alone is 30,000 lbs. Thus the operating load may be around 15 tonnes. 
     Preferably the collet load is around 30 tonnes. This provides a combined operating load and collet load of around 45 tonnes. The first load may be greater than 45 tonnes. More preferably the first load is around 70 tonnes. This ensures the packer will set. 
     The axial movement of the mandrel relative to the tool body in the first direction radially expands the packer element. The radially expansion of the packer element may seal the wellbore. The axial movement of the mandrel relative to the tool body in the second direction radially contracts the packer element. 
     Preferably the mechanical tension-set retrievable packer comprises at least one port configured to be in fluid communication with the annulus of the casing and/or downhole tubular. The at least one port may be configured to allow fluid communication between the throughbore and the annulus of the casing and/or downhole tubular below the mechanical tension-set retrievable packer. 
     The axial movement of the mandrel relative to the tool body in the first direction may open the at least one port. The axial movement of the mandrel relative to the tool body in the second direction may close the at least one port. 
     According to a fourth aspect of the present invention there is provided a method of controlled setting of a mechanical tension-set retrievable packer, the method comprising the steps:
         (a) mounting mechanical tension-set retrievable packer according to the third aspect in a string;   (b) arranging the resettable mechanism in a first configuration wherein the first face can abut the third face and the detent prevents movement of the inner actuating member in a first direction;   (c) applying a first load, greater than an operating load of the mechanical tension-set retrievable packer and a collet load, in the first direction sufficient to move the collet radially and allow the inner actuating member to move in the first direction to the second configuration and thereby set the mechanical tension-set retrievable packer to seal against a casing; and   (d) applying a second load, in the second direction so as to abut the second face and the fourth face and then move the collet ring over the detent to return the mechanism to the first configuration and thereby reset the mechanism and release the mechanical tension-set retrievable packer from the casing.       

     Preferably the method includes cycling steps (c) and (d) to repeatedly set and unset the mechanical tension-set retrievable packer. 
     Preferably the method includes the step of operating the disengagement assembly, so disabling the detent in a third configuration. The method may then comprise the further step of setting the mechanical tension-set retrievable packer at the operating load. In this way, lighter fish such as cut casing can be removed were the string is not anchored to a fixed point. 
     Preferably the method includes the step of releasing support of the collet ring so that it can move relative to the inner actuating member. 
     Preferably the method includes the step of dropping a ball through the central throughbore to operate the disengagement assembly. More preferably, the method includes the step of maintain a flow path through the mechanical tension-set retrievable packer in each configuration. 
     According to a fifth aspect of the present invention there is provided a casing cutting and removal assembly comprising: 
     an anchor mechanism configured to grip a section of a tubular in a wellbore; 
     a mechanical tension-set retrievable packer according to the third aspect; and 
     a casing cutter configured to cut the tubular; 
     wherein the anchor mechanism is located between the mechanical tension-set retrievable packer and the casing cutter. 
     In this way, repeated circulation tests can be performed on a single trip in the well without concern that the mechanical tension-set retrievable packer will accidentally set if operated from a floating rig. 
     The casing cutting and removal assembly may further comprise a drill, the drill being located at a distal end of the casing cutting and removal assembly. Mounting a drill bit on the end of the casing cutting and removal assembly allows initial dressing of a cement plug prior to casing cutting being achieved on the same trip into the wellbore. 
     Alternatively, the casing cutting and removal assembly may further comprise a bridge plug, the bridge plug being located at a distal end of the casing cutting and removal assembly. Mounting a bridge plug on the end of the casing cutting and removal assembly allows setting of a bridge plug in the casing prior to casing cutting being achieved on the same trip into the wellbore. 
     The drill or bridge plug may be hydraulically or pneumatically actuated. In this way the drill or bridge plug can be operated from surface without actuation of the anchor mechanism, mechanical tension-set retrievable packer or the casing cutter. 
     According to a sixth aspect of the invention there is provided a method of performing a circulation test in a wellbore comprising:
         (a) providing a casing cutting and removal assembly according to the fifth aspect;   (b) actuating the anchor mechanism to grip a section of a tubular;   (c) actuating the casing cutter to cut the tubular;   (d) applying the first load to actuate the mechanical tension-set retrievable packer to seal the wellbore;   (e) performing a circulation test in the wellbore; and   (f) applying the second load to unset the mechanical tension-set retrievable packer to release it from the wellbore.       

     The method may comprise the step of determining circulation behind the cut tubular at surface. This provides a positive circulation test and the cut tubular section, preferably a casing section, can be removed. 
     Preferably the method includes the further steps of unsetting anchor mechanism, actuating the anchor mechanism to grip the cut tubular section at an upper location on the tubular, and removing the cut tubular section from the wellbore. 
     In the event that the circulation test is negative, there being no circulation behind the cut tubular, the method then comprises the further steps of unsetting anchor mechanism, locating the casing cutter at a higher position on the tubular and repeating the steps (b) to (f). This can be repeated until a positive circulation test occurs and a section of cut tubular can be removed from the wellbore. 
     Preferably the method includes the step of operating the disengagement assembly, so disabling the detent in a third configuration. The method may then comprise the further step of setting the mechanical tension-set retrievable packer at the operating load. In this way, the cut casing can be removed were the string is not anchored to a fixed point. 
     In the description that follows, the drawings are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results. 
     Accordingly, the drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as “including,” “comprising,” “having,” “containing,” or “involving,” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Likewise, the term “comprising” is considered synonymous with the terms “including” or “containing” for applicable legal purposes. 
     All numerical values in this disclosure are understood as being modified by “about”. All singular forms of elements, or any other components described herein including (without limitations) components of the apparatus are understood to include plural forms thereof. 
    
    
     
       There will now be described, by way of example only, various embodiments of the invention with reference to the drawings, of which: 
         FIGS. 1A to 1E  are sectional views of a resettable mechanism, with  FIG. 1E  being an exploded view of part of  FIG. 1A , in first and second configurations and first and second positions, respectively, for use with a load set downhole tool according to an embodiment of the present invention; 
         FIGS. 2A and 2B  are sectional views of a mechanical tension-set retrievable packer for use with the resettable mechanism of  FIGS. 1A to 1D , in unset and set states, respectively, according to an embodiment of the present invention; and 
         FIGS. 3A to 3F  provide schematic illustrations of a casing cutting and removal assembly in a method according to an embodiment of the present invention. 
     
    
    
     Referring initially to  FIGS. 1A to 1E  of the drawings there is illustrated a resettable mechanism, generally indicated by reference number  10 , according to an embodiment of the present invention. 
     Mechanism  10  comprises a tubular body  12  having, at a first end  14 , a pin connector  16  for mounting the mechanism  10  in a string (not shown). A second end  18  of the body  12  is integral with the tubular body  20  of a downhole tool (not shown). A screw threaded connection may be alternatively arranged at the second end  18  for connection to the downhole tool or other part of a string which is in turn connected to the downhole tool. The downhole tool will operate by relative movement of the body  20  and an operating member  22 . 
     An inner sleeve  24  is provided in a central throughbore  26  of the mechanism  10 . Inner sleeve  24  includes a shoulder  28  towards the first end  14  which is arranged to engage a shoulder  32  of the tubular body  12  and thereby limit travel of the inner sleeve  24  through the central throughbore  26 . Towards the second end  18 , the inner sleeve  24  is connected to the operating member  22  of the downhole tool. This is achieved via an overshot  36  in the present embodiment, but may be by direct connection. In the present embodiment the overshot  36  is used to provide a stop face  38  and limit the stroke length to actuate the downhole tool. 
     On an outer surface  40  of the inner sleeve  24  towards the second end  18  there is arranged a shoulder  42 . On an inner surface  41  toward the first end  14  there is arranged a circumferential recess  43 . Apertures  44  through the inner sleeve  24  are provided circumferentially around the sleeve  24  between the shoulder  42  and recess  43 . There are six apertures  44  but any number may be present. In a first configuration, shown in  FIG. 1A , collet dogs  46  are located in each aperture  44  with the shape of apertures  44  matched to the dogs  46  to retain them so that a portion of each dog  46  protrudes from the outer surface  40 . The apertures  44  and shoulder  42  are spaced apart by a size to hold a collet ring  48 . Collet ring  48  is an annular band that slides over the outer surface  40  of the inner sleeve  24 . It radially extends by a greater distance than that of the shoulder  42 . 
     In a chamber  50  created between the tubular body  12  and the inner sleeve  24  there is arranged a collet  52 . Collet  52  is attached to the body  12 . Collet  52  provides a plurality of collet fingers as are known in the art which are arranged longitudinally to be coaxial with the axis of the central bore  26 . On an inner surface  54  of each finger there is provided a detent  56 . Detent  56  is a raised portion presenting a first face  58  directed towards the first end  14  and a second face  60  directed towards the second end  18 . First face  58  is arranged to be near perpendicular to the axis whereas face  60  is a gentle slope. The profile of the detent  56  is matched in reverse by the profile of the collet ring  48  as it presents a third face  62  similar to the first face  58  directed towards the second end  18  and a fourth face  64  matching the second face  60  directed towards the first end  14 . Like most collets  52 , the fingers and detent  56  can be moved radially by a load applied to a face of the detent  56 . In this embodiment, the collet load is set to move the detent  56  radially outwards when applied to the first face  58 . Consequently a much lower load than the collet load will move the detent  56  radially outwards when a load is applied to the second face  60 . 
     A disengagement assembly, generally indicated by reference numeral  66 , is also present. Assembly  66  comprises a drop ball sleeve  68  located inside the inner sleeve  24  and the collet dogs  46 . The outer surface  70  of the sleeve  68  includes a circumferential recess  72  towards the second end  18 . Towards the first end  14  there is a drop ball seat  74  created by a narrowing of the bore of the sleeve  68 . On either side of the drop ball seat  74  is arranged first ports  76  and second ports  78  respectively. The ports  76 ,  78  are apertures through the wall of the sleeve  68 . The drop ball sleeve  68  is attached to the inner sleeve  24  by shear screws  80 . 
     In use, the mechanism  10  is arranged in a first configuration as shown in  FIG. 1A . The drop ball sleeve  68  is connected to the inner sleeve  24  so that the collet dogs  46  are located in the apertures  44  and support the collet ring  48 . The inner sleeve  24  abuts the tubular body  12  by the abutment of shoulders  28 , 32 . In this configuration the first face  58  and the third face  62  also abut to prevent movement of the inner sleeve towards the second end  18 . Mechanism  10  is arranged to operate with a tension-set tool. However, it will be realised that the mechanism can be used with a weight-set tool. In either case the sting will be anchored at a fixed point in the well bore so that a load can be applied to the string. The downhole tool and resettable mechanism can be run in a well and the downhole tool, which would normally operate at a relatively low operating load, say 15 tonnes as an example, will not actuate until a load greater than the combination of the operating load and the collet load is applied. If we say in our example that the collet load is set to 30 tonnes, then a load of greater than 45 tonnes is required to actuate the downhole tool. Preferably a load of around 75 tonnes would be recommended to ensure the tool operates. In the present embodiment, when the load applied by an overpull to the string is greater than the combined combination, the detent  56  will move radially outwards and allow collet ring  48  to ride over the detent  56  so that the inner sleeve  24  moves towards the second end  18  relative to the tool body  12 . Relative movement of the inner sleeve  24  causes the operating member  22  of the downhole tool to also be relatively moved and consequently the downhole tool is actuated. Thus it has taken a load well in excess of the operating load of the downhole tool, in this case a multiple of the operating load being five times the operating load, to actuate the downhole tool. 
     The operating configuration being a second configuration is shown in  FIG. 1B . Here it is seen that the collet ring  48  has passed over the detent  56 , the inner sleeve  24  has moved to towards the second end  18  with the overshot  36  moving the operating member  22  until the face  38  meets a stop  30  on the downhole tool. This is the full stroke length of the downhole tool. Shoulders  28 ,  32  have parted and ports  34  allow equalisation of fluid. 
     If weight is set down, a reverse load is applied and the overshot  36  will move relative to the tool body  12  towards the first end  14 . This moves the collet ring  48  back over the detent  56 . In this case the second  60  and fourth  64  faces abut but as the angle of impact is small the load required to move the collet ring  48  over the detent  56  is smaller than the first load to actuate the tool. The inner sleeve  24  will be stopped when the shoulders  28 ,  32  contact. This resets the mechanism  10  as it is placed back in the first configuration. 
     It will be appreciated that the downhole tool can be actuated and de-actuated repeatedly as the reset can be undertaken any number of times. The resettable mechanism  10  thus allows for continuous operation of a downhole tool with a relatively low operating load. Such low operating loads provide for more complex downhole tools where the components would otherwise be damaged, are not available or would be of unworkable dimensions is they had to be designed to operate at high loads. 
     If the downhole tool requires to be actuated at its operating load, which may be needed when the string is no longer fixed in the well bore, such as when using the downhole tool in a fishing operation, the disengagement assembly  66  is operated. From a first position shown in  FIG. 1A , a drop ball  82  is passed through the central bore  26  being dropped from surface through the string. The ball  82  seats in the drop ball seat  74 . This blocks the passage of fluid through the mechanism  10  and fluid pumped through the bore  26  will cause a build-up of pressure on the ball  82  and the sleeve  68 . This pressure will become sufficient to shear screws  80  and thereby allow the sleeve  68  to move under pressure inside the inner sleeve  24 . The sleeve  66  will move until a front face  84  is stopped at a shoulder  86  on the inner sleeve  24 . Movement of the drop ball sleeve  66  relative to the inner sleeve  24  causes the recess  43  in the sleeve  68  to be positioned under the collet dogs  46 . Without support from the sleeve  68 , the collet dogs  46  slide back into the recess  43 , and no longer support the collet ring  48 . This means that the collet ring is now free to move along the outer surface  40  of the inner sleeve  24 . Additionally the ports  76 , 78  are now aligned with the recess  43 , allowing fluid flow passed the drop ball  82 . This may be considered as a second position for the disengagement assembly and is shown in  FIG. 1C . 
     To actuate the downhole tool now requires only the operating load as movement of the collet ring  48  and inner sleeve  24  is no longer prevented by the detent  56 . Indeed the collet ring  48  is now free to move along the outer surface  48  away from the detent  56  towards the first end  14 . When a load is applied the inner sleeve  24  will move relative to the tool body  12 , the collet ring  48  does not have to ride over the  56  and thus the sleeve  24  moves passed the detent  56  unimpeded. Thus the detent  56  is disengaged. The load applied to the inner sleeve  24  now only requires to be at the operating load for the downhole tool to move the operating member and thereby actuate the downhole tool. Additionally, as the drop ball sleeve  66  abuts the inner sleeve  24 , fluid flow is maintained between the ends  18 , 14  of the mechanism  10  via the ports  76 ,  78  and recess  43 . This is as illustrated in  FIG. 1D . 
     Reference is now made to  FIGS. 2A and 2B  which are enlarged longitudinal sectional views of a mechanical tension-set retrievable packer, generally indicated by reference numeral  222 , according to an embodiment of the present invention. The mechanical tension-set retrievable packer  222  comprises a packer element  240 . The packer element  240  is typically made from a material capable of radially expanding when it is axially compressed such as rubber or other elastomeric material. 
     The packer  222  has a mandrel  215  movable in relation to the body  213 . A spring compression ring  248  is mounted on the second end  215   b  of the mandrel. The spring compression ring  248  is configured to engage a first end  246   a  of spring  246 . For brevity the entire length of spring  246  is not illustrated but indicated by the cross lines. The second end  46   b  of the spring  246  is connected and/or engages shoulder  244  on the tool body  213 . The mandrel  215  is movably mounted on the body  213  and is biased to a first position shown in  FIG. 2A  by spring  246 . 
     At a first end  214  the packer  222  is connected to the resettable mechanism  10  of  FIGS. 1A to 1D . Those parts of  FIGS. 1A to 1D  viewable on the drawings are marked. The operating member  22  thus forms the mandrel  215  and body  12  is integral with body  213 . 
     The mandrel is configured to move from a first mandrel position shown in  FIG. 2A  to a second mandrel position shown in  FIG. 2B  when an upward tension or force is applied to the packer  222  via the drill string (not shown) connected thereto at a second end  218 . 
     In the first mandrel position the spring force of spring  246  maintains the position of the mandrel  215  relative to the body  213 . The packer element  240  is not compressed. 
     In the second mandrel position the mandrel  215  moves relative to the body  213 , the upward force acting on the mandrel  215  moves the spring compression ring  248  in a direction X which compresses the spring  246 . A lower gauge ring  252  mounted on the mandrel  215  engages a first edge  240   a  of the packer element  240 . An upper gauge ring  254  mounted on the tool body  213  engages a second edge  240   b  of the packer element. 
     An upward force acting on the packer  222  moves the lower gauge ring  252  toward the upper gauge ring  254  compressing the packer element  240 . Compression of the packer element  240  causes it to radially expand to contact the casing and seal the annulus of the wellbore. 
     The upward force or tension applied to the packer  222  has a pre-set lower threshold such that the spring force of spring  246  is overcome when upward force or tension is applied above the lower threshold. The lower threshold may be the minimum force or tension required to overcome the spring force of spring  246 . The lower threshold is set so that actuation will occur once an operating load is applied. An example operating load may be 15 tonnes. However, when the resettable mechanism  10  is part of the packer  222  a greater load is required to actuate the packer  222 . This increased load is determined by the collet load in the mechanism  10 . If we were to attempt to design a tension-set packer operable on the increased load, the springs  246  would be excessively long and such a packer would be impractical. By using the resettable mechanism  10 , the packer  222  can now be set using an increased load which can be adjusted so that it is greater than any unexpected loading which may occur on the drill string in use. Such variable loading is typically experienced when the string is run form a floating rig. Additionally, the resettable mechanism  10  allows the packer  222  to be unset and reset any number of times without requiring the packer to be pulled out of the well. 
     Referring now to  FIG. 3A  of the drawings there is illustrated a casing cutting and removal assembly, generally indicated by reference numeral  310 , run into a wellbore  312  which is lined with casing  314  or other tubular. Casing cutting and removal assembly  310  includes, from a first end  316 , a casing cutter  318 , an anchor mechanism  320  and a mechanical tension-set retrievable packer  322  which includes a resettable mechanism  325  arranged on a drill string  323  or other tool string according to an embodiment of the present invention. 
     The casing cutter  318 , anchor mechanism  320  and mechanical tension-set retrievable packer  322  with the resettable mechanism  325  may be formed integrally on a single tool body or may be constructed separately and joined together by box and pin sections as is known in the art. Two parts may also be integrally formed and joined to the third part. 
     Anchor mechanism  320  may be considered as a casing spear. The anchor mechanism  320  may be of any configuration to grip the casing  314 . A typical anchor mechanism  320  may comprise slips which move over a cone to extend and grip the casing  314 . By application of fluid pressure in the central throughbore of the string  323 , the slips will engage the inner surface  317  of the casing  314 . If tension is applied by overpulling the drill string  323  and the tool  310 , the slips are further forced outwards to grip the inner surface  317  of the casing  314 . This anchors the tool  310  to the casing  314  and sets the anchor mechanism preventing accidental release. Changing fluid pressure through the anchor mechanism will not deactivate the slips. The slips and anchor mechanism will release when the tension is removed and weight is set down on the string  323 . The anchor mechanism  320  therefore provides a fixed point against which a load may be applied, either by pulling to tension or by setting down weight on the drill string  323 . 
     A bearing on the tool body connects the anchor mechanism  320  with the tool body. The anchor mechanism  320  is rotatably mounted on the body and is configured to secure the tool  310  against the wellbore casing  314 . An upward force applied to the tool body may also apply pressure to the bearing and may facilitate the rotation of the lower tool body which will be connected to the casing cutter  318  and thus allow rotation thereof. 
     Casing cutter  318  may be any type of casing cutter. In the embodiment shown, the casing cutter  318  comprises a plurality of blades  330  which extend by the application of fluid pressure through the drill string  323 . The blades  330  rotate to cut through the wall of the casing  314 . Preferably fluid flows over the blades  330  to provide cooling and lubrication. Such fluid flow also removes the casing cuttings. 
     In use, the casing cutting and removal assembly  310  is assembled on a drill string  323 , in the order of the mechanical tension-set retrievable packer  322  with resettable mechanism  325 , the anchoring mechanism  320  and the casing cutter  318 . There may also be a drill  319  mounted on the end  316  for dressing a cement plug  321  already located in the casing  314 . Alternatively, a bridge plug (not shown) could replace the drill  319  and be set in the casing  314  in place of the cement plug  321 . 
     Referring to  FIG. 3A  of the drawings, the casing cutting and removal assembly  310  is run-in the wellbore  312  and casing  314  until it reaches the cement plug  321 . At this point a wellbore integrity test can be performed using the anchor mechanism  320  and the mechanical tension-set retrievable packer  322 , if desired. With the casing cutter  318 , anchor mechanism  320  and mechanical tension-set retrievable packer  322  all held in inactive positions, fluid can be pumped at a fluid pressure below a pre-set threshold through the bore of the drill string  323  to hydraulically activate the drill  319 . This does not actuate the casing cutter  318 , anchor mechanism  320 , the mechanical tension-set retrievable packer  322  or the resettable mechanism  325 . The drill  319  is used to dress the cement plug  321 . 
     The casing cutting and removal assembly is then pulled up to locate the blades  330  of the casing cutter  318  at a desired location to cut the casing  314 . At this position, the anchor mechanism  320  is hydraulically actuated to grip the casing surface  317  to secure the axial position of the tool  310  in the wellbore. The fluid circulation rate through bore  325  is increased and the anchor mechanism  320  grips the casing  314 . The tool  310  is then anchored to the casing by reversibly setting the anchor mechanism  320  by pulling the string  323 . 
     Once the anchor mechanism  320  has engaged the casing  14  and is set, as illustrated in  FIG. 1B , the casing cutter  318  can be actuated. Note that the casing  314  is held in tension when the casing cutter  318  is operated. The mechanical tension-set packer  322  and resettable device  325  are not affected by setting of the anchor mechanism  320  or the casing cutting as the tension applied is lower than the combined operating load and collet load. 
     During the cutting operation the anchor mechanism  320  remains substantially stationary relative to the casing cutter  318 , with rotation of the casing cutter being made possible via the bearing. Fluid flows out of the string  323  at the blades  330  and this is illustrated in  FIG. 3C  which arrows showing the direction of fluid flow. It is noted that upward flow travels in the annulus  328  passed the mechanical tension-set retrievable packer  322  without any obstructions in the annulus  328  at the location of the mechanical tension-set retrievable packer  322 . 
     If a kick occurs in the wellbore  312  for any reason, the mechanical tension-set retrievable packer can be rapidly set to seal the wellbore by simply applying greater tension to the drill string  323  to set the packer. This is described hereinbefore with reference to  FIGS. 2A and 2B . The load applied being great enough to overcome the detent in the resettable mechanism  325  so that the packer  322  can set. 
     When the casing cutter  318  has finished cutting the casing, the casing cutter is deactivated. 
     To perform a circulation test the mechanical tension-set retrievable packer  322  is first set to seal the casing  314 . To set the packer an upward tension or pulling force is applied to the drill string as shown by arrow X in  FIG. 3D . In this example 60,000 lbs of upward tension or pulling force is applied to the drill string. As described hereinbefore the load applied is great enough to overcome the detent in the resettable mechanism  325  so that the packer  322  can set. As the packer element is axially compressed it radially expands to engage the casing and seals the casing annulus  328 . The upward force is maintained to seal of the wellbore. This is as illustrated in  FIG. 3D . 
     The annulus  328  is now sealed off and pressurised fluid pumped through the drill string  323  will enter the annulus  328  and travel through the cut  329  in the casing  314 . While fluid can travel down between the casing  314  and the formation  331  it will be stopped at cement  341 . In this way, the fluid will be forced upwards between the casing  314  and the formation  331  towards the surface. A recording of pressure in the annulus behind the casing at surface indicates a positive circulation test and that the annulus behind the casing is free of debris which may cause the casing  314  to stick when removed. The casing  314  can now be removed. 
     On completion of the circulation test, the upward force or tension applied to the drill string is reduced to deactivate the mechanical tension-set retrievable packer  322  and the resettable mechanism moves to its first configuration and has reset. The packer element returns to its original uncompressed state and moves away from the well casing  314 . 
     To unset and release the anchor mechanism  320  a downward force is applied. This weight setting operation can merely be a continuation of the release of tension which unset the packer  322 . 
     The tool  310  is now relocated to a new axial position in the casing  314  with the anchor mechanism  320  located at an upper end of the cut section of casing  343 . In this position the anchor mechanism  320  is activated to grip the casing section  343  as described above and as illustrated in  FIG. 3E . 
     By pulling the drill string  323  and the casing cutting and removal assembly  310  from the wellbore  312 , the cut section of casing  343  is removed from the wellbore  312 . The wellbore  312  now contains the casing stub  345  and cement plug  321  as shown in  FIG. 3F . 
     In the event that the circulation test is negative, that is a pressure increase is not seen at surface, then it is assumed that cement or other debris is located in the annulus between the cut casing  343  and the formation  331  which will prevent movement and subsequent recovery of the cut casing section  343 . The drill string  323  and casing cutting and removal assembly  310  are then pulled up the casing to locate the blades  330  of the casing cutter  318  at a location higher in the well on the cut casing section  343 . 
     At this new position the method is undertaken again starting from  FIG. 3B  with the anchor mechanism  320  being reset. As the anchor mechanism  320 , casing cutter  318  and mechanical tension-set retrievable packer  322  are all retrievable, they can be operated multiple times in a single trip in the wellbore  312  until a section of casing is removed. 
     Additionally, if the string  323  experiences movement against the anchor mechanism  320  caused by the movement of the rig from which the string  323  and assembly  310  is deployed, the resultant load will still be less than the combined operating load and collet load so that the retrievable mechanical tension-set packer  322  cannot be accidentally actuated. 
     The retrievable mechanical tension-set packer  322  can also be used to assist in retrieval of the casing section  343  is desired. As casing section  343  is now free, the string  323  is now no longer anchored at a fixed point and thus tension can only be applied against the weight of the casing section  343 . In the event that this does not provide a sufficient load differential to activate the anchor mechanism  320  and/or packer  322 , the packer  322  can be set at its operating load. This is achieved by dropping a ball through the drill string  323 . The ball seats in a disengagement assembly of the resettable mechanism  325  and desupports the collet ring, thereby removing the detent. Consequently the packer  322  can then be set by its much lower operating load. 
     The principal advantage of the present invention is that it provides a resettable mechanism to prevent accidental actuation of a load set downhole tool. 
     A further advantage of an embodiment of the present invention is that it provides a high overpull tension-set packer which is resettable. 
     A still further advantage of an embodiment of the present invention is that it provides a casing cutting and removal assembly on which multiple circulation tests can be performed on a single trip in the well. 
     The foregoing description of the invention has been presented for the purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. The described embodiments were chosen and described in order to best explain the principles of the invention and its practical application to thereby enable others skilled in the art to best utilise the invention in various embodiments and with various modifications as are suited to the particular use contemplated. Therefore, further modifications or improvements may be incorporated without departing from the scope of the invention herein intended.