Downhole test tool and method of use

Abstract

A circulation test tool and method of performing a circulation test in a wellbore during single-trip casing cutting and removal. An anchor mechanism (20), a mechanical-set retrievable packer (22) and a cutting mechanism (18) allow gripping and cutting of casing (14) with the mechanical set-retrievable packer (22) being set after the cut to carry out the circulation test. The well is kept under control during the cut by application of tension on the drill string to set the packer (22) at any time. The arrangement provides full annulus flow pass at the packer during cutting. Embodiments describe additional features of a drill to dress a cement plug or a settable bridge plug.

Claims

1. A downhole casing cutting and removal assembly located on a work string, having a bore therethrough, for performing a circulation test after the cut is complete, the assembly comprising: a spear for casing removal, the spear comprising an anchor mechanism configured to grip a section of a tubular in a wellbore for removal thereof; a packer assembly being a mechanical tension-set retrievable packer configured to rapidly seal an annulus between the work string and the tubular; and a cutting mechanism configured to cut the tubular; wherein the anchor mechanism of said spear is located between the packer assembly and the cutting mechanism; wherein in a first configuration the anchor mechanism grips the tubular as the cutting mechanism cuts the tubular and the packer assembly is unset so that cuttings can be circulated up the annulus; and wherein in a second configuration the anchor mechanism grips the tubular, the cutting mechanism is stopped and the packer assembly is set with the annulus sealed so that a circulation test can be performed by pumping fluid from the annulus, through the cut and behind the cut tubular to surface.

2. The assembly according to claim 1 wherein the anchor mechanism is configured to grip a section of a casing located in a wellbore.

3. The assembly according to claim 1 wherein the anchor mechanism is configured to be reversibly set at different axial positions in the casing.

4. The assembly according to claim 1 wherein the assembly has a tool body with a central through bore.

5. The assembly according to claim 4 wherein the mechanical tension-set retrievable packer is configured to seal the downhole tubular providing a fluid passageway only through the central through bore.

6. The assembly according to claim 4 wherein the mechanical-set retrievable packer comprises at least one port providing selective fluid communication between the central through bore and an outer surface of the packer below the packer element.

7. The assembly according to claim 1 wherein the anchor mechanism comprises a cone and at least one slip, the at least one slip being configured to bear against the cone to engage an inner diameter of a section of the downhole tubular.

8. The assembly according to claim 7 wherein the at least one slip is locked against the downhole tubular by application of an upward force on the tool in the range from 2,000 lbs to 15,000 lbs (8896 to 66723 N).

9. The assembly according to claim 1 wherein the anchor mechanism is hydraulically actuated.

10. The assembly according to claim 9 wherein the anchor mechanism is actuated by pumping fluid into the central through bore in the tool above a pre-set flow rate threshold.

11. The assembly according to claim 10 wherein the flow rate threshold is in the range of 50 to 500 gpm (0.0032 to 0.0315 m.sup.3/sec).

12. The assembly according to claim 11 wherein the flow rate threshold is 250 gpm (0.0158 m.sup.3/sec).

13. The assembly according to claim 1 wherein the mechanical tension-set retrievable packer is operated by application of an upward force in the range from 20,000 lbs to 80,000 lbs (88964 to 355858 N).

14. The assembly according to claim 1 wherein the mechanical tension-set retrievable packer includes a packer element which is compressed by tension applied to a lower end and weight applied to an upper end.

15. The assembly according to claim 1 wherein the cutting mechanism comprises a plurality of knives arranged circumferentially around the tool and a sleeve configured to move the knives between a storage position where the knives are retracted and do not engage the downhole tubular and an operational position where the knives are extended and engage the downhole tubular.

16. The assembly according to claim 1 wherein the cutting mechanism is hydraulically actuated and rotates relative to the anchor mechanism.

17. A method of performing a circulation test in a wellbore, the method comprising: (a) running a casing cutting and removal assembly comprising: a spear for casing removal, the spear comprising an anchor mechanism configured to grip a section of a tubular in a wellbore for removal thereof; a packer assembly being a mechanical tension-set retrievable packer configured to rapidly seal an annulus between the work string and the tubular; and a cutting mechanism configured to cut the tubular; the anchor mechanism being located between the packer assembly and the cutting mechanism; wherein in a first configuration the anchor mechanism grips the tubular as the cutting mechanism cuts the tubular and the packer assembly is unset so that cuttings can be circulated up the annulus; and wherein in a second configuration the anchor mechanism grips the tubular, the cutting mechanism is stopped and the packer assembly is set with the annulus sealed so that a circulation test can be performed by pumping fluid from the annulus, through the cut and behind the cut tubular to surface; into the wellbore; (b) actuating the anchor mechanism to grip a section of a tubular; (c) actuating the cutting mechanism to cut the tubular while pumping fluid through a bore of the work string to circulate cuttings up an annulus between the work string and the tubular; (d) deactivating the cutting mechanism; (e) actuating the packer assembly to seal the annulus; and (f) pumping fluid through the bore of the work string to circulate through the cut and behind the cut tubular to surface as a circulation test in the wellbore.

18. The method according to claim 17 wherein the method comprises the step of determining circulation behind the cut tubular at surface; wherein on noting circulation behind the cut tubular at surface, the method includes the further steps of unsetting the packer and 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; and wherein on not obtaining circulation behind the cut tubular at surface, the method includes the further steps of: (a) unsetting the packer and anchor mechanism; (b) locating the cutting mechanism at a higher position on the tubular; (c) actuating the anchor mechanism to grip a section of a tubular; (d) actuating the cutting mechanism to cut the tubular while pumping fluid through a bore of the work string to circulate cuttings up an annulus between the work string and the tubular; (e) deactivating the cutting mechanism; (f) actuating the packer assembly to seal the annulus; and (g) pumping fluid through the bore of the work string to circulate through the cut and behind the cut tubular to surface as a circulation test in the wellbore.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) There will now be described, by way of example only, various embodiments of the invention with reference to the drawings, of which:

(2) FIGS. 1A to 1F provide schematic illustrations of a method according to an embodiment of the present invention;

(3) FIG. 2A is a sectional view of an anchor mechanism of a casing cutting and removal assembly in a run-in state according to an embodiment of the present invention;

(4) FIG. 2B is a sectional view of the anchor mechanism of FIG. 2A in an operational state;

(5) FIG. 3A is a sectional view of a packer assembly of a casing cutting and removal assembly in a run-in state according to an embodiment of the present invention;

(6) FIG. 3B is a sectional view of the packer assembly of FIG. 3A in an operational state;

(7) FIG. 3C is a sectional view of sections A to A′ of the packer assembly of FIG. 3A;

(8) FIG. 4A is a sectional view of a cutting mechanism of a casing cutting and removal assembly in a run-in state according to an embodiment of the present invention;

(9) FIG. 4B is a sectional view of the cutting mechanism of FIG. 4A in an operational state; and

(10) FIG. 4C is a sectional view of the cutting mechanism of FIG. 4A in an cutting state.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

(11) Referring initially to FIG. 1(a) of the drawings there is illustrated a casing cutting and removal assembly, generally indicated by reference numeral 10, run into a wellbore 12 which is lined with casing 14 or other tubular. Casing cutting and removal assembly 10 includes, from a first end 16, a cutting mechanism 18, an anchor mechanism 20 and a packer assembly 22 arranged on a drill string 23 or other tool string according to an embodiment of the present invention.

(12) The cutting mechanism 18, anchor mechanism 20 and packer assembly 22 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.

(13) FIGS. 2A and 2B are enlarged longitudinal sectional views of the anchor mechanism 20 of the casing cutting and removal assembly 10 in accordance with a first embodiment of the invention. The tool 10 has an elongate body 13 providing a mandrel 15 with a central bore 25 through which fluid is configured to be pumped.

(14) The anchor mechanism 20 comprises a cone 24 circumferentially disposed about a section of the downhole tool 10. A plurality of slips 26 are configured to move along the surface of the cone 24. The slips 26 have a grooved or abrasive surface 26a on its outer surface to engage and grip the casing.

(15) The slips 26 are configured to move between a first position shown in FIG. 2A on the cone 24 in which the slips 26 are positioned away from surface of the casing, and a second position in which the slips 26 engage the surface of the casing as shown in FIG. 2B.

(16) The slips 26 are connected to a sleeve 30. The sleeve 30 is movably mounted on the body 13 and is biased in a first position by a spring 36 as shown in FIG. 2A. It will be appreciated that any spring, compressible member or resilient member may be used to bias the sleeve in a first position.

(17) A shoulder 32 of the sleeve 30 is in fluid communication with the main tool bore 25 via a flow path 34. The sleeve 30 is configured to move from a first sleeve position shown in FIG. 2A to a second fluid position shown in FIG. 2B when fluid is pumped into bore 25 above a pre-set circulation threshold through flow path 34 to apply fluid pressure to shoulder 32 of the sleeve 30. Thus by the application of fluid pressure in the central through bore, the slips 26 will engage the inner surface 17 of the casing 14.

(18) If tension is applied by overpulling the drill string 23 and the tool 10, the slips are further forced outwards to grip the inner surface 17 of the casing 14. This anchors the tool 10 to the casing 14 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 23.

(19) A bearing 39 on the tool body 12 connects the anchor mechanism 20 with the tool body 13. The anchor mechanism 20 is rotatably mounted on the body and is configured to secure the tool against the wellbore casing. An upward force applied to the tool body 13 may also apply pressure to the bearing 39 and may facilitate the rotation of lower tool body 13a which will be connected to the cutting mechanism 18 and thus allow rotation thereof.

(20) FIGS. 3A and 3B are enlarged longitudinal sectional view of the packer assembly 22. FIG. 3C shows a cross-section view of line A-A′ of FIG. 3A. Like parts to those in FIGS. 2A and 2B have been given the same reference numeral to aid clarity. The packer assembly 22 comprises a packer element 40. The packer element 40 is typically made from a material capable of radially expanding when it is axially compressed such as rubber or other elastomeric material.

(21) The mandrel 15 is movable in relation to the body 13. A spring compression ring 48 is mounted on the second end 15b of the mandrel. The spring compression ring 48 is configured to engage a first end 46a of spring 46. The second end 46b of the spring 46 is connected and/or engages shoulder 44 on the tool body 12. The mandrel is movably mounted on the body 12 of the tool 10 and is biased to a first position shown in FIG. 3A by spring 46.

(22) The mandrel is configured to move from a first mandrel position shown in FIG. 3A to a second mandrel position shown in FIG. 3B when an upward tension or force is applied to the tool 10 via the drill string 23.

(23) In the first mandrel position ports 50 are blocked by the second end 14b of the mandrel. In the second sleeve position ports 50 are open and in fluid communication with the annulus 28 below the packer element 40.

(24) In the first mandrel position the spring force of spring 46 maintains the position of the mandrel 15 relative to the body 12. The packer element 40 is not compressed and ports 50 are covered by the mandrel.

(25) In the second mandrel position the mandrel 15 moves relative to the body, the upward force acting on the tool 10 and mandrel moves the spring compression ring 48 in a direction X which compresses the spring 46. A lower gauge ring 52 mounted on the mandrel 14 engages a first edge 40a of the packer element 40. An upper gauge ring 54 mounted on the tool body engages a second edge 40b of the packer element.

(26) An upward force acting on the tool 10 moves the lower gauge ring 52 toward the upper gauge ring 54 compressing the packer element 40. Compression of the packer element 40 causes it to radially expand to contact the casing and seal the annulus of the wellbore.

(27) The above-example describes a tension-set packer assembly. The upward force or tension applied to the tool has a pre-set lower threshold such that the spring force of spring 46 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 46. The lower threshold may be adjustable to change the minimum force or tension required to overcome the spring force of spring 46.

(28) FIGS. 4A, 4B and 4C are longitudinal sectional views of a cutting mechanism 18 in a casing cutting and removal assembly 10 when connected to a tool string in accordance with an embodiment of the invention in different phases of operation. Like parts to those of the earlier Figures have been given the same reference numeral to aid clarity.

(29) FIG. 4A is a longitudinal section through the cutting mechanism 18. The cutting mechanism 18 has an elongate body 13 with a first end 52 and a second end (not shown). The first end 52 is designed for insertion into the wellbore first and is configured to be coupled to a lower tool or string. The lower tool may comprise at least one hydraulically operable tool connected to the drill string. The tool body 13 comprises a cutting system 42 configured to cut a casing.

(30) FIG. 4A shows the tool in a circulation mode where fluid flows through a circulation flow path through the tool.

(31) An annular sleeve 51 is slidably mounted in the bore 25. The sleeve 51 is configured to move axially between a first position shown in FIG. 4A and second position shown in FIG. 4C. Intermediate positions may be selected as shown in FIG. 4B. The sleeve 51 comprises a shoulder 53 which is configured to engage with a pivot arm 35 connected to the cutting knife 33. The shoulder 53 of the sleeve 51 is configured to pivotally move the knives 33 between a knife storage position shown in FIG. 4A and a knife deployed position shown in FIG. 4C.

(32) An annular port closing sleeve 55 is slidably mounted in the bore 25. The port closing sleeve 55 is configured to move axially between a first position shown in FIG. 4A and second position shown in FIG. 4B. The annular port closing sleeve 55 is configured to engage sleeve annular sleeve 51 such that in a first position port 51a on the sleeve 51 is open and in a second position port 51a is closed.

(33) The annular sleeve 51 comprises a bypass channel 62. The bypass channel 62 is in fluid communication with bore 25 through ports 51a. The annular sleeve 51 is movably mounted in the tool and is biased in a first position by a spring 57.

(34) The annular port closing sleeve 55 is held in a first position relative to the body 13 by shear screws 64. The annular sleeve 51 is held in a first position relative to the body 13 by shear screws 64a. Fluid flowing through the upper drill string flows through the circulation flow path. Fluid flows from bore 25 through ports 51a into bypass channel 62. The flow continues through channel 86 into the lower drill string bore (not shown).

(35) FIG. 4B shows the cutting mechanism 18 when switched to a cutting operation mode. In this mode the annular port closing sleeve 55 is moved to a second position where it blocks ports 51a on the sleeve 51 closing the circulation flow path. Ports 55a on the port closing sleeve 55 are opened allowing fluid flow through the first flow path denoted as “A” in FIG. 4B. However, in FIG. 4B there is not sufficient fluid flow through the first flow path to operate the cutting system 42.

(36) A fluid displacement member 60 is disposed in the bore 25 and is configured to introduce a pressure difference in the fluid upstream of the displacement member and the fluid downstream of the displacement member 60.

(37) When the tool is switched to a cutting operation mode the bore 25 is in fluid communication with the annular space 28 through a first flow path denoted by arrow “A” in FIG. 4B. The first flow path comprises ports 55a, channel 78 located between the sleeve 51 and the displacement member 60, a port 79 in the sleeve 51, an outlet 80 in the body 13 and into the annular space 28. The fluid displacement member 60 acts to direct the fluid into channel 78.

(38) FIG. 4C shows the tool during a cutting operation. Fluid flows through the first flow path to actuate the cutting system 42.

(39) The sleeve 51 is configured to be moved from a knife retracted position shown in FIG. 4B to a knife deployed position shown in FIG. 4C when fluid pressure is applied to shoulder 55b of the sleeve 55. When fluid pressure applied to shoulder 55b is sufficient to overcome the spring force of spring 57 the sleeve 51 moves toward the first end 52 of the cutting mechanism 18. The fluid displacement member 60 remains stationary.

(40) In FIG. 4C the annular sleeve 51 is located in a knife deployed position wherein the flow area of the nozzle 74 is reduced by the movement of the sleeve 51 toward end 52. The reduced flow area increases the fluid pressure through the nozzle 74. Measuring and/or monitoring the fluid pressure through the nozzle 74 may provide an indication of the movement of the annular sleeve 51 and the movement of the knives to a cutting operational position as shown in FIG. 4C.

(41) FIG. 4C shows that the cutting mechanism 18 comprises a second flow path denoted by arrow “B”. The fluid inlet of the second flow path is a port (not shown) located on the lower drill string or a tool located below the tool 10.

(42) The second flow path passes through a channel 86 in the annular sleeve 51 and into a channel 78 located between the sleeve 51 and the displacement member 60. In channel 78 the fluid from the second flow path joins the fluid passing through the first flow path. The fluid exits the tool body into the annular space 28 via port 79 in the sleeve 51 and through an outlet 80 in the body 13 and into the annular space 28.

(43) Optionally, the second flow path may comprise a screen to prevent casing cutting and solids from entering the tool 10 via the second flow path.

(44) The outlet 80 is dimensioned such that it is larger than the port 79 on the sleeve 51. This is to ensure that fluid flow through port 79 and outlet 80 is maintained as the sleeve moves between the first and second positions shown in FIGS. 4A and 4C. This provides an axially movable venturi flow path which moves as the axial position of the sleeve 51 moves. Such a venturi flow path diverts the cuttings down the annulus 28. This is preferential to carrying the cuttings to surface were they must be disposed of and can damage the packer element.

(45) In use, the casing cutting and removal assembly 10 is assembled on a drill string 23, in the order of the packer assembly 22, the anchoring mechanism 20 and the cutting mechanism 18. There may also be a drill 19 mounted on the end 16 for dressing a cement plug 21 already located in the casing 14. Alternatively, a bridge plug (not shown) could replace the drill 19 and be set in the casing 14 in place of the cement plug 21.

(46) Referring to FIG. 1A of the drawings, the casing cutting and removal assembly 10 is run-in the wellbore 12 and casing 14 until it reaches the cement plug 21. At this point a wellbore integrity test can be performed using the anchor mechanism 20 and the packer assembly 22, if desired. With the cutting mechanism 18, anchor mechanism 20 and packer assembly 22 all held in inactive positions, fluid can be pumped at a fluid pressure below a pre-set threshold through the bore 25 of the drill string 23 to hydraulically activate the drill 19. This does not actuate the cutting mechanism 18, anchor mechanism 20 or the packer assembly 22. The drill 19 is used to dress the cement plug 21.

(47) The casing cutting and removal assembly is then pulled up to locate the knives 33 of the cutting mechanism 18 at a desired location to cut the casing 14. At this position, the anchor mechanism 20 is hydraulically actuated to grip the casing surface 17 to secure the axial position of the tool 10 in the wellbore. The fluid circulation rate through bore 25 is increased above the pre-set threshold rate. Referring to FIGS. 2A and 2B, fluid flows through flow path 34 and acts on shoulder 32 of the sleeve 30 in the anchor mechanism 20. The pre-set threshold is set by the spring force of spring 36. In this example, the first pre-set threshold is 250 gallons per minute (gpm) (0.0158 m.sup.3/sec).

(48) The fluid pressure of the fluid above the pre-set threshold overcomes the spring force of spring 36. The sleeve 30 moves along the longitudinal axis of the tool body 13 to the second position shown in FIG. 2A. A slip retaining ring 38 is secured to the sleeve 30 and is connected to the slips 26. The sleeve 30 and slip retaining ring 38 push the slips 26 along the slope 11 of cone 24.

(49) The slips 26 extend outward and engage the surface of casing 14. The slips provide friction to maintain the position of the tool 10 within the casing.

(50) The tool 10 is then anchored to the casing by reversibly setting the anchor mechanism 20. To set the anchor mechanism an upward tension or pulling force is applied to the drill string as shown by arrow X in FIG. 2B. In this example 10,000 lbs (44482 N) upward tension or pulling force is applied to set the anchor, although it will be appreciated that the anchor mechanism may be configured to set at different tension or pulling forces.

(51) The tension or pulling force causes the slips to be wedged or locked between the surface of the cone 24 of the tool and the casing 14 of the wellbore. At this point the tool will remain at this location even if the fluid pressure in the bore 25 is stopped or reduced below the pre-set threshold.

(52) If the anchor mechanism 20 is not set the anchor mechanism reverts to its first position shown in FIG. 2A when the fluid pump is stopped or fluid pressure is reduced below the pre-set threshold. The spring force of spring 36 moves the sleeve 30 to the first position shown in FIG. 2A. The slips 26 which are in contact with the slip retaining ring 38 are pulled along the slope 11 of cone 24 and moved away from the surface of casing 15.

(53) Once the anchor mechanism 20 has engaged the casing 14 and is set, as illustrated in FIG. 1B, the cutting mechanism 18 can be actuated. Note that the casing 14 is held in tension when the cutting mechanism 18 is operated.

(54) Operation of the cutting apparatus will now be described with reference to FIGS. 4A, 4B and 4C. In FIG. 4A, the cutting mechanism 18 is shown in a tool run in phase, with the cutting system 42 in a retracted storage position. This is as for FIGS. 1A and 1B. In this retracted position fluid pumped into bore 25 enters the circulation flow path as denoted by arrow “C” in FIG. 4A. Fluid flow through this circulation flow path does not actuate the knives and they remain in a retracted position as shown in FIG. 4A while allowing the transfer of torque and fluid to the drill bit 19.

(55) In order to switch the cutting mechanism 18 to a cutting operation position as shown in FIG. 4B, a ball 90 is dropped in the bore of the tool string and is carried by fluid flow through bore 25 until it is retained by the shoulder 55b of the port closing sleeve. Fluid pressure acts on the ball sheering screws 64, 64a and moves the port closing sleeve 55 and sleeve 51 to a second position where ports 51a on the sleeve 51 are closed and ports 55a on the port closing sleeve 255 are opened. This closes the circulation path “C” and opens a first flow path denoted by arrow “A” in FIG. 4B.

(56) The first flow path passes from the bore 25 through ports 55b, through a channel 78 located between the sleeve 51 and the displacement member 60, a port 79 in the sleeve 51 and through an outlet 80 in the body 13 and into the annular space 28.

(57) FIG. 4C show the actuation of the cutting mechanism 18 when in a cutting operation position. Fluid is pumped into the tool string and flows through the first flow path to actuate the cutting system 42.

(58) During the cutting operation the anchor mechanism 20 remains substantially stationary relative to the cutting mechanism 18, with rotation of the cutting mechanism being made possible via the bearing 39.

(59) The fluid pumped into bore 25 acts against shoulder 55a of the port closing sleeve 55. When the fluid pressure is sufficient to overcome the spring force of spring 57 the port closing sleeve 55 and sleeve 51 are moved towards end 52 of the downhole tool. Axial movement of the sleeve 51 towards first end 52 of the tool causes shoulder 53 of the sleeve 51 to act against the pivot arm 35 to rotate the knife 33 from a retracted storage position to an extended operational position.

(60) FIG. 4C shows that the cutting mechanism 18 comprises a second flow path denoted by arrow “B”. The fluid inlet of the second flow path is port (not shown) located on the lower tool string or a tool located on the lower tool string.

(61) The second flow path passes from a bore of a lower tool string (not shown) to channel 86 in the annular sleeve 51 through channel 62 and into a channel 78 located between the sleeve 51 and the displacement member 60. In channel 78 the fluid from the second flow path joins the fluid passing through the first flow path. The fluid exits the tool body into the annular space 28 via port 79 in the sleeve 51 and through an outlet 80 in the body 13 and into the annular space 28.

(62) The first flow path and the second flow path are in fluid communication in channel 78 located between the sleeve 51 and the displacement member 60. Fluid flowing through channel 78 along the first flow path induces a venturi effect in the second flow path denoted by arrow “B” in FIG. 4C and draws fluid up through the lower drill string and through the second flow path.

(63) Fluid flow through the first flow path directs fluid flow into the annular space 28. As the flow through the first flow path creates a venturi effect in the second flow path and induces fluid flow in the second flow path from the bore of a lower drill string (not shown) it creates a localised recirculation of fluid.

(64) The bore of lower drill string and/or drill 19 connected to the lower drill string may have ports in fluid communication with the annular space 28. The recirculation of fluid directs the flow of fluid from the outlet 80 which entrains cuttings during the cutting operation and moves the fluid and cuttings further downhole toward the ports on the lower drill string and/or a tool. This action allows the cuttings to be moved further downhole away from the cutting site.

(65) The axially movable venturi flow path provides a driving force to actuate the cutting system 42 and induces localised recirculation of fluid around the tool to ensure that the casing cuttings are removed from the cutting site.

(66) This is as illustrated in FIG. 1C which arrows showing the direction of fluid flow. It is noted that upward flow travels in the annulus 28 passed the packer assembly 22 without any obstructions in the annulus 28 at the location of the packer assembly 22.

(67) If a kick occurs in the wellbore 12 for any reason, the packer assembly can be rapidly set to seal the wellbore by simply applying greater tension to the drill string 23 to set the packer. This is described hereinafter with reference to setting the packer for a circulation test.

(68) When the cutting mechanism 18 has finished cutting the casing, the cutting mechanism is deactivated. The rotation the tool string is stopped to stop the rotation of the cutting mechanism. Optionally, the fluid pump is deactivated. The absence of fluid pressure on the shoulder 55a of the sleeve 55 causes the spring force of spring 57 to act on the sleeve 51 to move the sleeve 51 to a position shown in FIG. 4B. The movement of the sleeve moves the shoulder 53a to engage the pivot arm 35 to rotate the knives to a retracted position.

(69) To perform a circulation test the packer assembly 22 is first set to seal the casing 14. To set the packer an upward tension or pulling force is applied to the drill string as shown by arrow X in FIG. 3A. In this example 60,000 lbs of upward tension or pulling force is applied to the drill string.

(70) The axial position of the tool body 13 in the wellbore is maintained by the anchor mechanism 20 gripping the casing. The mandrel 15 connected to the upper drill string is moved to a second position shown in FIG. 3B by the upward tension or pulling force. The lower gauge ring 54a mounted on the mandrel 15 engages a first edge 40a of the packer element 40 resulting in axial compression of the packer element between lower gauge ring 54a mounted on the mandrel 15 and upper gauge ring 54b mounted on the tool body. As the packer element is axially compressed it radially expands to engage the casing and seals the casing annulus 28. The upward force is maintained to seal of the wellbore.

(71) Ports 50 in the mandrel are opened allowing fluid communication between the bore 25 and the annulus 28 below the packer assembly. This is as illustrated in FIG. 1D.

(72) The annulus 28 is now sealed off and pressurised fluid pumped through the drill string 23 will enter the annulus 28 and travel through the cut 29 in the casing 14. While fluid can travel down between the casing 14 and the formation 31 it will be stopped at cement 41. In this way, the fluid will be forced upwards between the casing 14 and the formation 31 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 14 to stick when removed. The casing 14 can now be removed.

(73) On completion of the circulation test, the upward force or tension applied to the drill string is reduced to allow the spring 46 of the packer assembly 22 to move the mandrel 15 to a first position shown in FIG. 3A. The packer element 40 returns to its original uncompressed state and moves away from the well casing 14.

(74) To unset and release the anchor mechanism a downward force is applied in the direction shown as “Y” in FIG. 2B which momentarily moves the cone 24 away from the slips 26 which is sufficient to allow the spring force of the spring 36 to pull the slips 26 along the slope 11 of the cone and away from the casing 14 to the first position shown in FIG. 2A.

(75) The tool 10 is now relocated to a new axial position in the casing 14 with the anchor mechanism 20 located at an upper end of the cut section of casing 43. In this position the anchor mechanism 20 is activated to grip the casing section 43 as described above and as illustrated in FIG. 1E.

(76) By pulling the drill string 23 and the casing cutting and removal assembly 10 from the wellbore 12, the cut section of casing 43 is removed from the wellbore 12. The wellbore 12 now contains the casing stub 45 and cement plug 21 as shown in FIG. 1F.

(77) 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 43 and the formation 31 which will prevent movement and subsequent recovery of the cut casing section 43. The drill string 23 and casing cutting and removal assembly 10 and then pulled up the casing to locate the knives 33 of the cutting mechanism 18 at a location higher in the well on the cut casing section 43.

(78) At this new position the method is undertaken again starting from FIG. 1B with the anchor mechanism 20 being reset. As the anchor mechanism 20, cutting mechanism 18 and packer assembly 22 are all retrievable, they can be operated multiple times in a single trip in the wellbore 12 until a section of casing is removed.

(79) The principal advantage of the present invention is that it provides a robust and reliable casing cutting and removal assembly in a casing cutting and removal assembly suitable for deployment downhole which 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.

(80) A further advantage of at least one embodiment of the present invention is that it provides a method of performing a circulation test in a casing cutting and removal operation at multiple locations within a wellbore.

(81) 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.