WELL ABANDONMENT AN D SLOT RECOVERY

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.

US 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 US 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 at least one embodiment 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 first piston arranged in a fluid filled chamber between the tubular body and the annular body, the piston being fixed to the annular body and moveable relative to the tubular body;

the first piston creating an upper chamber and a lower chamber on respective sides of the first piston;

the first piston including a valve mechanism comprising a first valve, operable at a first fluid pressure applied from the upper chamber to the lower chamber, and a second valve, operable at a second fluid pressure applied in reverse, which is less than the first fluid pressure, each biased in opposing directions and providing an actuable through passage between the upper and lower chambers, so that:

in a first configuration, the first and second valves are closed and the fluid in the upper chamber prevents movement of the inner actuating member until a first load is applied in a first direction; and in a second configuration the fluid in the upper chamber prevents movement of the inner actuating member until a second load is applied in a second direction; and wherein

the first load is greater than a combined load of the operating load and a piston load; and

the second load is applied in reverse to the first load. In this way, the piston load can be set by the calculated area of the piston together with the pressure rating of the first valve. Thus the first piston is set to move 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. The second load can be set by the pressure rating of the second valve. Preferably the first valve is a high pressure relief valve. In an embodiment the first valve is operable at a first fluid pressure of 5000 psi (3.4xl0 ⁷ Nm ² ) or greater.

Preferably the second valve is a check valve. In an embodiment the second valve is operable at a second fluid pressure of 5 psi (3.4xl0 ⁴ Nm ² ) or greater.

Preferably the fluid in the chamber is oil. In this way, debris laden mud is isolated from the valves.

Preferably a floating piston is disposed in the lower chamber providing an equalisation chamber which includes a port through the tubular body. In this way, the floating piston ensures pressurisation of the closed oil filled chamber as the tool is run to depth.

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 the first aspect with the load set downhole tool in a string and connecting the inner actuating member to the operating member of the downhole tool;

(b) arranging the resettable mechanism in the first configuration wherein the first and second valves are closed and the fluid in the upper chamber prevents movement of the inner actuating member in the first direction; (c) applying the first load, greater than the operating load of the downhole tool and the piston load, in the first direction sufficient to open the first valve and move the first piston and allow the inner actuating member to move and thereby actuate the downhole tool; and

(d) applying the second load, in the second direction so as to open the second valve 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 piston 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 (c) and (d) to repeatedly actuate the downhole tool.

According to an embodiment 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 cylindrical 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 tubular body;

at least one packer element; and

a resettable mechanism according to the first aspect wherein the mandrel is connected to the inner actuating member. An upward force or tension applied to the string axially may move the mandrel relative to the tubular body. The axial movement of the mandrel relative to the cylindrical body in the first direction may actuate and set the mechanical tension-set retrievable packer. The axial movement of the mandrel relative to the cylindrical 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.

In an embodiment, to compress disc springs to start setting the packer a pull of approx. 130,000lbs is required. With a piston area of say 20 sq. inches and a pressure relief valve set at 5,000psi, you need to pull 100,000lbs to allow oil through the valve plus at least 30,000 lbs to start the further compression of the disc springs. To unset the packer you simply slack off and the strong disc springs will ensure that the oil will return through the weak check valve. The axial movement of the mandrel relative to the cylindrical 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 cylindrical body in the second direction allows the packer to contract radially.

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 cylindrical body in the first direction may open the at least one port. The axial movement of the mandrel relative to the cylindrical body in the second direction may close the at least one port.

According to an embodiment of the present invention there is provided a method of controlled setting of the mechanical tension-set retrievable packer, the method comprising the steps:

(a) mounting a mechanical tension-set retrievable packer in a string ;

(b) arranging the resettable mechanism in the first configuration wherein the first and second valves are closed and fluid in the upper chamber prevents movement of the inner actuating member in the first direction;

(c) applying the first load, greater than the operating load of the mechanical tension-set retrievable packer and the piston load, in the first direction sufficient to open the first valve, move the first piston and allow the inner actuating member to move in the first direction and thereby set the mechanical tension-set retrievable packer to seal against a casing ; and

(d) applying the second load, in the second direction so as open the second valve and move the first piston 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.

According to an embodiment of the present invention there is provided a casing cutting and removal assembly comprising :

an anchor mechanism configured to grip a section of casing or a downhole tubular in a wellbore; the mechanical tension-set retrievable packer; 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 an embodiment of the invention there is provided a method of performing a circulation test in a wellbore comprising :

(a) providing the casing cutting and removal assembly;

(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.

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:

Figures 1A and IB are sectional views of a resettable mechanism in first and at second configurations, respectively, for use with a load set downhole tool operated by tension on a spring according to an embodiment of the present invention;

Figures 2A and 2B are sectional views of a mechanical tension-set retrievable packer for use with the resettable mechanism of Figures 1A and IB, in unset and set states, respectively, according to an embodiment of the present invention; and

Figures 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 Figures 1A and IB 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 and operating member 22 are shown connected in the mechanism 10, with the operating member 22 forming a portion of the inner sleeve 24. The inner sleeve 24 is thus connected to the operating member 22 of the downhole tool. This is achieved via a direct connection in the present embodiment, but may be by an overshot arrangement. Also shown is a spring compression ring 28 attached to the operating member 22 which will compress a disc spring 46 which can be used to operate a tool (not shown). This spring compression ring 28 and spring 46 are not part of the mechanism 10 and shown only for illustrative purposes of operating a tension set tool.

Mechanism 10 comprises a chamber 48 formed by the tubular body 12 and inner sleeve 24. The tubular body 12 provides an inner surface 41, upper surface 31 and a lower surface 34 to the chamber 48. The outer surface 40 of the inner sleeve 24 provides the bounding wall of the closed chamber 48. Within the chamber 48 there is arranged a piston 50. Piston 50 is fixed to the inner sleeve 24 and so that it can move in the chamber 48 in response to movement of the inner sleeve 24. The piston 50 is sealed 71 to an inner surface 41 of the tubular body 12. The presence of the piston 50 creates an upper chamber 60 and a lower chamber 64. The upper chamber 60 is bounded by the outer surface 40, inner surface 41, upper surface 31 and upper piston face 54. The lower chamber 64 is bounded by the outer surface 40, inner surface 41, lower surface 34 and lower piston face 52.

In the embodiment shown, there is an additional feature of a pressure equalisation system via a floating piston 62. Floating piston 62 is located in the lower chamber 64 being sealed against the outer surface 40 and inner surface 41. The floating piston 62 creates a further chamber, being a pressure equalisation chamber 66 in the lower chamber 64.

Piston 50 includes two valves, pressure relief valve 58 and a check valve 56. Valves 56, 58 lie in parallel with the longitudinal axis of the mechanism 10 and selectively provide fluid communication the upper chamber 60 and the lower chamber 64. The relief valve 58 is operable at around 5000 psi (3.4xl0 ⁷ Nm ² ) to allow fluid flow from the upper chamber 60 to the lower chamber 64. The check valve 56 is operable at a low pressure, say about 5 psi (3.4xl0 ⁴ Nm ² ) to allow fluid to flow from the lower chamber 64 to the upper chamber 60.

The inner surface 41 of upper chamber 60 is provided with an aperture 70 which is sealed with a top aperture sealing plug 72. Also, the inner surface of lower chamber 64 is provided with an aperture 74 which is sealed with a lower aperture sealing plug 78. The inner surface 41 of pressure equalisation chamber 66 is also provided with an aperture 78. Prior to deployment, the mechanism 10 is arranged such that it is unset. Oil is pumped through lower aperture 74 into chamber 64 at a pressure sufficient to actuate the low-pressure check valve 56, in this case around 5 psi. The pressurised oil actuates the low-pressure check valve 56 causing it to open and allow the oil to travel through the low-pressure check valve 56, into chamber 60 and to be expelled through aperture 70 to ensure the amount of oil in the system is appropriate to enable the valve system to function. When the oil is balanced appropriately, a lower sealing plug 76 and top sealing plug 72 are used to seal apertures 74 and 70 respectively. Throughout the mechanism 10, seals 71 prevent the unwanted movement of fluid between the chambers 60,64,66.

The piston face area 54 together with the rating of the pressure relief valve 58 determine a piston load at which the pressure relief valve 58 will open and the piston 50 will move in a first direction towards the upper surface 31. This is selected to be at greater than the operating load for actuation of the downhole tool being used with the mechanism 10. Preferably the piston load is three to five times greater than the operating load. The piston load can be selected to represent a load greater than that which may be experience by the downhole tool when deployed in a well.

In use, the mechanism 10 is arranged in a first configuration as shown in Figure 1A. When run in the well, the pressure equalisation chamber 66 ensures that the volume of oil will remain pressurised. As the tool is run in the well the piston 50 will want to move upwards very slightly due to the increase in hydrostatic pressure and move downwards due to the increase in temperature and therefore the expansion of oil. At depth, the work string will be anchored so that there is a fixed point against which a load may be applied.

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 (15000 kg) as an example, will not actuate until a load greater than the combination of the operating load and the piston load is applied. If, for example, the piston face area 54 together with the rating of the pressure relief valve 58 provide a piston load of 45 tonnes (45,000 kg). This load is thus required to allow oil through valve 58 plus a pull or load of at least 15 tonnes (15,000kg) to start movement of the piston 50 and the inner sleeve 24 such that a load of at least 60 tonnes (60,000kg) is required to actuate the downhole tool. Preferably a load of around 75 tonnes (75,000 kg) 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 combination of the operating load and the piston load, the check valve 58 will open allowing oil to transfer from chamber 60 through to chamber 64. As a result, chamber 64 will increase in size as chamber 64 receives oil through valve 58 and face 52 moves away from floating piston face 63. At the same time, chamber 60 will diminish in size as the face 54 moves towards face 31 and thus the associated relative movement of the inner sleeve 24 causes the operating member 22 of the downhole tool also to 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 is shown in Figure IB. Here it is seen that the disc springs 46 have been compressed so that the downhole tool is effectively actuated. The high-pressure relief valve 58 has been opened allowing oil to pass into and expand chamber 64, thus minimising chamber 60, whilst the inner sleeve 24 has moved along towards the second end 18 such that spring compression ring 28 compresses the spring 46 to operate the downhole tool. While any load is maintained on the tool in the first direction i.e. towards the second end 18, the downhole tool remains actuated. In our example, the spring 46 remains contracted. Any variation in the load will not cause the tool to be deactivated as long as a net load remains in the first direction. If weight is set down, a reverse load is applied. This can be considered as a load being applied in a second direction, opposite the first direction, being towards the first end 14. This will move mechanism 10 into the second configuration. Under the reverse load, the disc springs 46 will be able to relax such that the inner sleeve 24 will move relative to the tool body 12 towards the first end 14. As the check valve 56 has a low pressure rating, the inner sleeve 24 should move freely as oil will flow from chamber 64 to chamber 60 and the piston returns to the first configuration as was shown in Figure 1A. The mechanism 10 has therefore been reset.

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. Reference is now made to Figures 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 215b of the mandrel. The spring compression ring 248 is configured to engage a first end 246a of spring 246. For brevity the entire length of spring 246 is not illustrated but indicated by the cross lines. The second end 46b 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 Figure 2A by spring 246.

At a first end 214 the packer 222 is connected to the resettable mechanism 10 of Figures 1A and IB. Those parts of Figures 1A to ID viewable on the drawings are marked. The operating member 22 thus forms the mandrel 215 and body 12 is integral with body 213 which can be considered as body 20 on Figures 1A and IB.

The mandrel is configured to move from a first mandrel position shown in Figure 2A to a second mandrel position shown in Figure 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 240a of the packer element 240. An upper gauge ring 254 mounted on the tool body 213 engages a second edge 240b 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 (15000 kg). 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 piston 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 Figure 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 Figure 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 Figure IB, 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 Figure 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 Figures 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 Figure 3D. In this example 60,000 lbs (266894 N) of upward tension or pulling force is applied to the drill string. As described hereinbefore the load applied is great enough to overcome the check valve pressure 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 Figure 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. The ability to circulate up through 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 Figure 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 Figure 3F.

In the event that the circulation test is negative, that is fluid flow 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 Figure 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.