WO2020161219A1

WO2020161219A1 - Improvements in or relating to well abandonment and slot recovery

Info

Publication number: WO2020161219A1
Application number: PCT/EP2020/052946
Authority: WO
Inventors: Timothy O'rourke
Original assignee: Ardyne Holdings Limited
Priority date: 2019-02-07
Filing date: 2020-02-06
Publication date: 2020-08-13
Also published as: GB201901716D0; GB2581338A; GB2581338B

Abstract

A downhole assembly and method of operating an actuator on a pipe string in a well bore. A ball seat sub and a circulation sub are mounted around the hydraulic actuator. A first ball dropped through the assembly to the ball seat sub seals the pipe string and allows unlimited pressure to be increased to operate the actuator. Dropping a second ball opens a radial port in the circulation sub to allow the pipe string and assembly to be pulled while daring fluid through the radial port. A method of casing recovery is described wherein the actuator operates a hydraulic jack and the assembly also includes a casing spear and optionally a casing cutter. Recovery is achieved by simple drop ball operation.

Description

IMPROVEMENTS IN OR RELATING TO

WELL ABANDONMENT AND SLOT RECOVERY

The present invention relates to apparatus and methods for well abandonment and slot recovery and in particular, though not exclusively, to an apparatus and method 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. This provides a need to provide tools which can pull long lengths of cut casing from the well to reduce the number of trips required to achieve casing recovery However, the presence of drilling fluid sediments, partial cement, sand or other settled solids in the annulus between the outside of the casing and the inside of a surrounding downhole body e.g. outer casing or formation can act as a binding material limiting the ability to free the casing when pulled. Stuck casings are now a major issue in the industry.

Traditionally, cut casing is pulled by anchoring a casing spear to its upper end and using an elevator/top drive on a drilling rig. However, some drilling rigs have limited pulling capacity, and a substantial amount of power is lost to friction in the drill string between the top drive and the casing spear, leaving insufficient power at the spear to recover the casing. Consequently, further trips must be made into the well to cut the casing into shorter lengths for multi-trip recovery.

To increase the pulling capability, a downhole power tool (DHPT) available from the present Applicants, has been developed. After the casing has been located and engaged with a casing spear, hydraulically-set mechanically releasable slips anchor the DHPT to the wall of the larger ID casing above. A static pressure is applied to begin the upward movement of the cut casing, with the DHPT downhole multi-stage hydraulic actuator functioning as a hydraulic jack. After the stroke is completed, the anchors are released. The power section can be reset and the anchor re-engaged as many times as required. The DHPT is described in US 8,365,826 to TIW Corporation, the disclosure of which is incorporated herein in its entirety by reference.

As in many downhole operations, it is practical to drive a hydraulic actuator by means of a liquid, typically a drilling fluid, which is pumped through a pipe string in which the tool is included. The actuator is then hydraulically connected in such a way that fluid may flow out of a port in the pipe string and into the actuator. When pressure is to be created for driving an actuator in a downhole tool, it is known to close to the flow of drilling fluid by means of a valve, which is placed below said port. A well- known solution is to arrange a valve seat below the port and let a valve body, such as a ball, into the fluid flow. The ball follows the fluid flow, and when the ball lands in the valve seat, the fluid flow through the pipe string is blocked. The pressure at the port upstream of the valve seat may then easily be determined by means of a pump and other equipment on the surface, so that the actuator can work with the desired force.

While this provides a simple valve, a difficulty arises when it is time to pull the DHPT and recovered casing from the well. As the pipe string is blocked, fluid cannot drain through the string and we have a so-called wet string which is more difficult to pull and handle at surface. One solution to this has been to combine the drop ball valve with a rupture or burst disc sub. The rupture disc sub is a tool activated by applying pressure from surface to burst a rupture disc to allow communication between the pipe string and the annulus at a predetermined pressure. However, a disadvantage of this arrangement is that the pressure required to activate the actuator must be kept below the predetermined pressure until recovery is required while sufficient pressure must be able to be applied to burst the rupture disc when recovery is required. Similar disadvantages occur if a sliding sleeve moveable over a port, held by shear screws, is used instead of the rupture disc.

More complicated and expensive solutions are also known for said valve. Valves that are operated via a separate hydraulic circuit with associated hydraulic lines are complicated and often come into conflict with other components of the tool. Valves that are operated by the drill string being rotated have drawbacks in terms of safety because of the risk of loosening threaded connections in the pipe string so that it is no longer pressure-tight. An ALO valve is available from Ardyne AS, Norway, which operates by opening and closing the pipe string by the application of tension on the pipe string as described in EP3063364 and incorporated herein by reference. This requires manipulation of the pipe string in the well to operate.

It is an object of the present invention is to provide a downhole assembly and method of operating an actuator on a pipe string in a well bore which obviates or mitigates at least some of the disadvantages of the prior art.

According to a first aspect of the present invention there is provided a downhole assembly comprising, in order on a pipe string :

a ball seat sub, the ball seat sub including a first valve ball seat having a first clearance diameter for the flow of fluid along a throughbore of the pipe string;

a hydraulic actuator, operated by fluid flow through a port from the throughbore to perform a task by the assembly downhole; and

a circulation sub, the circulation sub including a second valve ball seat having a second clearance diameter for the flow of fluid along the throughbore of the pipe string to the hydraulic actuator and an obturating member connected to said second ball valve seat, the obturating member being moveable over an aperture giving access to an annulus outside the pipe string from the throughbore, wherein:

the second clearance diameter is greater than the first clearance diameter so that the pipe string can be sealed by the dropping of a first ball from surface through the circulation sub and hydraulic actuator to seat in the first valve ball seat and thereby allow operation of the hydraulic actuator; and the obturating member moves from a first position in which the aperture is closed to a second position in which the aperture is open, by the dropping of a second ball from surface to seat in the second valve ball seat.

In this way, the actuator can be operated by simply dropping a ball from surface through the pipe string. There is then no limit to the fluid pressure which can be applied to operate the hydraulic actuator. When the assembly is to be pulled, a second ball can be dropped to seat in the ball seat above the actuator and allow fluid to drain from the pipe string through the aperture. There can be no premature shearing of rings, pins or screws as the first valve ball seat is not connected to the obturating member. There can also be no premature bursting of rupture discs as these are not present and accordingly the assembly requires no redress in the field, as the drop balls need only be removed for the downhole assembly to be re-run.

Preferably, the obturating member is resettable between the second and first positions. This can be achieved by having the obturating member spring mounted, the second valve ball seat or second drop ball being deformable, and a third drop ball which is sized to block the aperture. This arrangement of circulation sub is described in US7055605, which is incorporated herein in its entirety by reference. In this way, the closing the aperture allows the pressure to be increased at the actuator again so that the actuator can be activated again, in the event that it deactivated when the aperture was opened and pressure in the throughbore dropped. The circulation sub may allow multi-operation through the use of an indexing sleeve connected to the obturating member. This arrangement of circulation sub is described in US7416029, which is incorporated herein in its entirety by reference. The WELL COMMANDER available from MiSWACO is a multi-cycle ball activated circulation sub. In this way, the actuator can be repeatedly operated while in the well.

Preferably the assembly includes a hydraulic jack, the hydraulic jack comprising an anchor for axially fixing the apparatus to a tubular in the well, and a mandrel connectable to a lower pipe string axially moveable relative to the anchor by activation of the hydraulic actuator. In this way, the downhole assembly is a downhole pulling tool.

Preferably, the assembly includes a casing spear connected to the lower pipe string below the ball seat sub. In this way, the downhole assembly can be used to recover casing in a well bore.

The downhole assembly may include a casing cutter connected to the lower pipe string below the casing spear. In this way, casing may be cut and pulled on the same trip into the well bore.

Preferably, the hydraulic jack includes a housing supported in the well by the string and enclosing the hydraulic actuator, the hydraulic actuator comprising a plurality of axially stacked pistons generating a cumulative axial force, each of the plurality of pistons axially movable in response to the fluid entering a plurality of the ports; and wherein movement of the pistons also moves the mandrel, with the mandrel being an inner mandrel extending from the housing. In this way, a great pulling force can be created downhole at the jack. Preferably the hydraulic jack is the DHPT supplied by Ardyne AS. Alternatively, the hydraulic jack includes an outer housing arranged around an upper mandrel connected to the pipe string and enclosing the hydraulic actuator, the hydraulic actuator comprising a plurality of axially stacked pistons generating a cumulative axial force, each of the plurality of pistons axially movable in response to the fluid entering a plurality of the ports; and wherein movement of the pistons also moves the mandrel, with the mandrel being a lower mandrel extending from a lower end of the outer housing. In this way, an alternative arrangement of a hydraulic jack is provided. The hydraulic jack may be as described in GB2533022, the contents of which are incorporated herein by reference.

Preferably, in the hydraulic jack the plurality of axially stacked pistons include a plurality of inner pistons each secured to the inner mandrel and a plurality of outer pistons each secured to a tool housing supported by the string. Preferably, the axial force generated by the plurality of pistons acts simultaneously on the anchor and on the tool mandrel, such that the tool anchoring force increases when the axial force on the tool mandrel increases. Preferably, the anchor includes a plurality of slips circumferentially spaced about the mandrel for secured engagement with an interior wall in the well. Preferably, an axial force applied to the plurality of slips is reactive to the force exerted on the casing spear by the plurality of pistons.

Preferably the casing spear comprises: a sliding assembly mounted on the inner mandrel; at least one gripper for gripping onto an inner wall of the length of casing, the gripper being coupled to the sliding assembly; the sliding assembly being operable for moving the gripper between a first position in which the gripper is arranged to grip onto the inner wall of the length of casing in at least one gripping region of the length of casing and a second position in which the gripper is held away from the inner wall; and a switcher which, when advanced into the length of casing, locks the sliding assembly to the inner mandrel with the gripper in the second position; and, when the casing spear is pulled upward out of the length of casing and the switcher exits the end of the length of casing, automatically allows engagement of the length of casing by the gripper in the first position. In this way, the length of casing is automatically gripped into engagement with the casing spear when the casing spear is at the top of the length of casing. Preferably the casing spear is the Typhoon® Spear supplied by Ardyne AS.

According to a second aspect of the present invention there is provided a method of operating an actuator on a pipe string in a well bore, comprising the steps:

(a) locating a downhole assembly according to the first aspect on the pipe string;

(b) running the pipe string into the well bore to a position at which the downhole assembly is to perform a task on operation of the hydraulic actuator;

(c) dropping the first ball down the throughbore of the pipe string from surface to pass through the circulation sub and hydraulic actuator to seat in the first valve ball seat and seal the pipe string at the ball seat sub;

(d) increasing fluid pressure in the throughbore at the port to operate the hydraulic actuator and perform the task with the downhole assembly;

(e) dropping the second ball down the throughbore of the pipe string from surface to seat in the second ball valve seat and seal the pipe string at the circulation sub;

(f) increasing pressure at the second ball valve seat to move the obturating member from the first position to the second position to open the aperture and allow fluid flow from the throughbore to an annulus outside the downhole assembly; and (g) pulling the pipe string and downhole assembly from the well bore while allowing fluid to drain from the throughbore to the annulus via the aperture. In this way, the actuator can be operated by simply dropping a ball through the pipe string and fluid can drain from the pipe string when POOH by simply dropping a second ball through the pipe string.

Preferably the hydraulic actuator operates a hydraulic jack. In this way the task is to provide a downhole pulling tool.

Preferably the method includes attaching a casing spear to a cut section of casing and pulling the cut section of casing as the task. Preferably the method includes attaching a casing cutter to the downhole assembly and cutting casing in the well bore to provide the cut section of casing.

The method may include the additional steps of closing the aperture, expelling the second ball through the second ball valve seat, increasing pressure to operate the hydraulic actuator again, dropping a further ball to seat in the second ball valve seat, and opening the aperture between steps (f) and (g). These additional steps may be repeated. 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.

Additionally, while relative terms such as 'above' and 'below' are used, this does not limit the invention to being used in a vertical well bore. The invention has equal application in inclined or deviated well bores.

Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings of which:

Figure 1 is a schematic illustration of a downhole assembly according to an embodiment of the present invention;

Figures 2(a) is a part sectional view of an actuator section of a hydraulic jack and Figure 2(b) is a part sectional view of an anchor of the hydraulic jack, according to an embodiment of the present invention; Figures 3(a) and 3(b) are a sectional view through a circulation sub, according to an embodiment of the present invention;

Figures 4(a) is a sectional view through a circulation sub, with Figures 4(b)-(d) illustrating positions of an index pin in a groove of the sleeve in the sub of Figure 4(a), according to an embodiment of the present invention; and

Figures 5(a)-(d) illustrate apparatus and method for casing recovery in a wellbore, using a downhole assembly, according to an embodiment of the present invention.

Reference is initially made to Figure 1 of the drawings which illustrates a downhole assembly, generally indicated by reference numeral 10, located on a pipe string 12 in a well bore 13. The assembly 10 includes a ball seat sub 14, a hydraulic actuator 16 and a circulation sub 18, in order according to an embodiment of the present invention.

From an upper end, being closer to the surface of the well bore, the pipe string 12 has the circulation sub 18 mounted therein. The circulation sub 18 has ball valve seat 20 with a sleeve 22 attached thereto. The sleeve 22 is initially held in place by shear screws 24 as is known in the art. The sleeve 22 is first positioned to cover an aperture 26 giving access between a throughbore 28 of the pipe string 12 and an annulus 30 around the assembly 10. The ball valve seat 20 has a clearance for the flow of fluid and passage of drop balls with diameters smaller than the clearance diameter, centrally along the throughbore 28.

The hydraulic actuator 16 may be any arrangement driven by an increase in fluid pressure. In the illustration of Figure 1, the fluid flows through a port 32 to move an inner mandrel 34 which forms a lower portion of the pipe string 12. Below the hydraulic actuator 16, the assembly 10 has a ball seat sub 14 mounted in the pipe string 12. The ball seat sub 14 provides a second ball valve seat 36 which is affixed to the inner wall of the pipe string 12. The second ball valve seat 36 has a clearance diameter which is smaller than that of the first ball valve seat 20 in the circulation sub 18. Fluid can also pass through the second ball valve seat 36 along the throughbore 28 of the pipe string 12. The ball seat sub 14, hydraulic actuator 16 and circulation sub 18 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. In use, the assembly 10 is mounted on a pipe string 12 with the sleeve 22 covering the aperture 26. The pipe string is run in the well and fluid can fill the throughbore 28. With the assembly 10 at the desired position in the well a first drop ball 38 is released from surface and carried in the pumped fluid down the throughbore 28. The first drop ball 38 is sized to pass through the first ball valve seat 20 as its diameter is less than that of the clearance diameter in the seat 20. The ball 38 passes through the actuator 16 and is stopped at the second ball valve seat 36 in the ball seat sub 14 as its diameter is greater than that of the clearance diameter in the seat 36. The ball 38 when seated seals the throughbore 28 and blocks the passage of fluid through the pipe string 12 at the ball seat sub 14. By continuing to pump fluid from surface, the fluid pressure will increase above the ball 38 and consequently fluid entering the port 32 on the hydraulic actuator 16 will have an increased pressure. This pressure will continue to increase and operate the actuator 16. In this embodiment the inner mandrel 34 will move relative to the upper pipe string 12. As the ball valve seat 36 is fixed, the ball 38 will remain in the seat 36 and a maximum pressure can be applied to operate the actuator 16. When the pipe string 12 is ready to be pulled, a second drop ball 40 is released into the throughbore 28 from surface. The second drop ball 40 has a greater diameter than the first drop ball 38 and is sized to seat in the first ball valve seat 20. It has sufficient weight to reach the seat 20 and seal the throughbore 28 at the circulation sub 18, above the actuator 16. By continuing to pump fluid from surface, the pressure will increase upon the ball 40 and eventually the pressure upon the ball 40 and seat 20 will be sufficient to shear the screws 24 holding the sleeve 22 in place. On shearing the sleeve 22 together with the seat 20 and ball 40 will move downwards until they reach a stop 42. The movement of the sleeve 22 will have been sufficient to clear the aperture 26 and thus fluid can now flow from the throughbore 28 to the annulus 30. On pulling the pipe string 12 out of the well bore 13, fluid in the throughbore 28 above the ball valve seat 20 can drain through the aperture 30 so that the pipe string 12 is empty when it reaches the surface. This removes the requirement to handle a wet string at surface. There will be fluid in the section of pipe string 12 between the ball valve seats 20,36 but this should be a manageable quantity of fluid to handle at surface.

By removing the balls 38, 40 and repositioning the sleeve 22 with the replacement of the shear screws 24, the assembly is available to be run again with a minimum of redress required. In an embodiment the hydraulic actuator 16 operates a hydraulic jack 44. A hydraulic jack 44 is illustrated in Figures 2(a) and 2(b). The hydraulic jack 44 has an anchor 128 and an actuator 116 system which pulls an inner mandrel 130 up into a housing 132 of the jack 44. In the preferred embodiment the hydraulic jack is the DHPT available from Ardyne AS. It is described in US 8,365,826 to TIW Corporation, the disclosure of which is incorporated herein in its entirety by reference. Referring to Figures 2(a) and 2(b) there is illustrated the main features of the hydraulic jack 44. Figure 2(a) shows a portion of the actuator system 116. The jack 44 has an outer housing 132 with a connection 134 to the pipe string 12. There is an inner mandrel 130 which can move axially within the housing 132. A series of spaced apart outer pistons 136 are connected into the housing 132. A series of spaced apart inner pistons 138 are connected to the inner mandrel 130. The pistons 136,138 are stacked between each other so that an upper end face 140 of an inner piston 138 will abut a lower end face 142 of an outer piston 136. Only one set of pistons 136,138 are shown but this arrangement is repeated along the mandrel 130 to provide five sets of pistons 136,138. The inner mandrel 130 includes a number of ports 144 arranged circumferentially around the mandrel 130, at the upper end of each outer piston 136, when the inner piston 138 rests on the outer piston 136. A chamber 146 is provided at this location so that fluid can enter the ports 144 to operate the actuator 116 and will act on the lower end face 148 of the inner piston 138. This will move the piston 138 upwards, crossing a vented space 150, until the upper end face 140 of the inner piston 138 abuts the lower end face 142 of the outer piston 136. This movement constitutes a stroke of the jack 44.

Movement of the inner mandrel 130 is driven by movement of the inner pistons 138. As there are multiple stacked pistons 138, the combined cross-sectional areas of the end faces 140 when fluid pressure is applied generates a considerable lifting force via the inner mandrel 130.

Flydraulic jack 44 also includes an anchor 128, shown in Figure 2(b). Anchor 128 has a number of slips 152 arranged to ride up a cone 154 by the action of fluid entering a chamber 156 and moving the cone 154 under the slips 152. The outer surface 158 of the slips 152 is toothed to grip an inner surface of the casing in which the anchor 128 is positioned. The anchor 128 is connected to the outer housing 132 so that the inner mandrel 130 can move axially relative to the anchor 128 when the anchor is set to grip the casing.

There is an alternative jack which may be used. This jack has the anchor located at the upper end and the hydraulic jack includes an outer housing arranged around an upper mandrel connected to the pipe string and enclosing the hydraulic actuator, the hydraulic actuator comprises a plurality of axially stacked pistons generating a cumulative axial force, each of the plurality of pistons axially movable in response to the fluid entering a plurality of the ports; and wherein movement of the pistons also moves the mandrel, with the mandrel being a lower mandrel extending from a lower end of the outer housing. This hydraulic jack is as described in GB2533022, the contents of which are incorporated herein by reference.

While Figure 1 shows a simplified circulation sub 18, a circulation sub 218 which allows the aperture 30 to be repeatedly opened and closed is illustrated in Figures 3(a)-(b). In use, sub 218 is attached in the pipe string 12 with the sleeve 220 held in the closed position which obturates outlet aperture 230. The sleeve 220 is held in this closed position by the location of collet 222 in recess 228.

To operate the sub, ball 236 is dropped down the axial through passage in the fluid flow and comes to rest against shoulder 234. Ball 236 seals against shoulder 234 and blocks fluid flow through the sub 128. The fluid pressure pushes ball 236 and consequently sleeve 220 in the axial direction of fluid flow through passage 28. Sleeve 220 comes to rest against shoulder 238 and radial port 232 is aligned with the outlet aperture 230. Fluid flow is now radially from the tool via port 230. This radial flow allows the pipe string 12 to drain as the assembly 10 is POOFI. When the radial fluid flow is required to be stopped a further ball 240 is dropped into the throughbore 28 at the surface. Ball 240 is carried in the fluid and forced against port 232 thereby sealing the radial port 230. Ball 240 is made of steel to withstand the downhole pressure exerted upon it. However, the consequential increase in fluid pressure in the throughbore 28 causes ball 236, which is made of a deformable plastic, to be extruded through the seat 234. Ball 236 is then forced against lower seat 242 and because the distance between the seats 234 and 242 is relatively small, i.e. approximately 6 inches for ball diameters of 2 inches and 1.75 inches and inner passage diameter of 3.75 inches, the resulting pressure differential at the base of the sleeve 220 causes the sleeve 220 to move upwards to the closed position. As the sleeve 220 moves upwards ball 240 is released into the axial fluid flow and falls through seat 234. With radial aperture 230 now closed, all fluid pressure is substantially against ball 236 and the ball 236 is extruded by deforming through the seat 242 and falls into the ball catcher 244. Ball 236 is held within the ball catcher 244 by the retaining pin 246. Ball 240 falls through seat 242 and is also held within the ball catcher 244.

An increase in fluid pressure at the actuator 16 below the sub 218 can now be used to operate the actuator 16 once more. If radial flow is required again the above procedure may be repeated without the need for removing the sub 218 from the borehole. This procedure may be repeated until the ball catcher is full whereby the assembly 10 is returned to the surface for the catcher 244 to be emptied.

This circulation sub 218 is as described in US7055605 which is incorporated in its entirety herein by reference.

A further embodiment of a re-settable circulation sub 318, is shown in Figures 4(a) to 4(d). In use, sub 318 is connected to the pipe string 12 using the box section 320 and the pin section 322. As shown in FIGS. 4(a) and 4(b), spring 352 biases a sleeve 330 against an index pin 360 such that the pin 360 is located in the base of longitudinal portion 364 of the groove 362. This is referred to as the first position of the sub 318. In this position, sleeve ports 332 are located above body apertures 324, thus preventing fluid flow radially through these apertures due to their misalignment. All fluid flow is down the throughbores 28. This can be considered as the run-in position for the sub 318. When radial flow is required to the annulus 30, drop ball 368 is then released down the throughbore 28 of the pipe string 12 from a surface. Ball 368 travels by fluid pressure and/or gravity to the ball seat 334 of the sleeve 330. The ball 368 is guided by the conical surface 338 to the ball seat 334. When the ball 368 reaches the seat 334 it effectively seals the throughbore 28 and prevents axial fluid flow through the sub 318.

Consequently fluid pressure builds up behind the ball 368 and the sleeve 330, including the ball 368, moves against the bias of the spring 352, to an intermediate position. The spring 352 is compressed into a now smaller chamber 348. Fluid has been expelled from the chamber 348. The index pin 360 is now located at the apex 363 of the groove 362 next to the longitudinal portion 364. This is as illustrated in FIG. 4(c).

Consequently the sleeve ports 332 have crossed the body apertures 324 and are now located below them. Fluid flow down the throughbore 28 is prevented by the ball 368.

As pressure increases on the ball 368 it is released from the ball seat 334 by passing through the throat 340. The ball 368 travels by fluid pressure until it is stopped further through the sub 318 or the pipe string 12. On release of the pressure, spring 352 moves the sleeve 330 against the index pin 360 such that the sleeve travels to a second position. Fluid has been drawn into the chamber 348 and this drawing and expelling of fluid provides a hydraulic damping effect on the impact on the pin 360. Index pin 360 is now located in a base 365 of the groove 362 and the port 332 and aperture 324 are aligned. This is illustrated in FIG. 4(d). In this second position fluid is expelled radially from the sub 318 through the now aligned port 332 and aperture 324. The sub 318 is locked in this position by virtue of the stop 366 on the groove 362 which prevents movement of the sleeve 330 for small variations in fluid pressure. In this position fluid can be drained from the pipe string 12 and the pressure in the throughbore will decrease. In order to close the aperture 324, a second ball is dropped from the surface through the pipe string 12. The second ball, and indeed any ball subsequent to this, is identical to the first ball 368. The second ball will travel to rest in the ball seat 334. On the build up of fluid pressure behind the ball, sleeve 330 will move downwards against the bias of the spring 352. Consequently the index pin 360 will be relocated into the next apex 363 of the groove 362 and thus the tool is returned to the intermediate position. When the ball passes through the throat 340, the pin 360 and sleeve 330 will move relatively back to the first position and the ball will come to rest by the first ball 368. The index pin 660 has located in the next longitudinal portion 364. Effectively the sub 318 is reset and by dropping further balls the sub 318 can be repeatedly cycled in an open and closed manner as often as desired. The intermediate position can be considered as a primed position. Reference is now made to Figures 5(a)-(d) which illustrate a method of casing recovery using a downhole assembly 110. Those parts referred to in Figures 1 to 4 have been given the same reference numeral. The assembly 110 now includes a casing spear 46 and a casing cutter 48. The assembly 110 is mounted on the pipe string 12 and pipe string 12 is a drill string typically run from a rig (not shown) via a top drive/elevator system which can raise and lower the string 12 in the well 13. The casing cutter 48 and casing spear 46 are run into a first casing 52 in the well 13. The well 13 has a second casing 54 in which the first casing 52 is located. In an embodiment, casing 12 is 9 5/8" in diameter while the outer casing 54 is 13 3/8" diameter. In a preferred embodiment the casing spear 46 comprises: a sliding assembly mounted on an inner mandrel; grippers 56 for gripping onto an inner wall 50 of the length of casing 52, the grippers 56 being coupled to the sliding assembly; the sliding assembly is operable for moving the grippers 56 between a first position in which the grippers 56 are arranged to grip onto the inner wall 50 of a length of casing 52 in at least one gripping region of the length of casing 52 and a second position in which the grippers 56 is held away from the inner wall 50; and a switcher which, when advanced into the length of casing 52, locks the sliding assembly to the inner mandrel with the grippers 56 in the second position; and, when the casing spear 46 is pulled upward out of the length of casing 52 and the switcher exits the end of the length of casing 52, automatically allows engagement of the length of casing 52 by the grippers 56 in the first position. In this way, the length of casing 52 is automatically gripped into engagement with the casing spear 46 when the casing spear 46 is at the top 58 of the length of casing 52. In a preferred embodiment the casing spear 48 is the Typhoon® Spear supplied by Ardyne AS.

Casing cutter 48 may be any tool which is capable of cutting casing downhole in a well bore. A pipe cutter, section mill, jet cutter, laser cutter and chemical cutter are a non-exhaustive list of possible casing cutters.

As shown in Figure 5(a) the downhole assembly 10 is run in the well and the casing cutter 48 has been used to cut the casing 52 to separate it from the remaining casing string. The cut casing may be over 100m in length. It may also be over 200m or up to 300m. Behind the casing 52 there may be drilling fluid sediments, partial cement, sand or other settled solids in the annulus between the outside of the casing 52 and the casing 54. This material 60 can prevent the casing 52 from being free to be pulled from the well 13. On run-in the sleeve 330 is arranged so that the aperture 324 is covered and all flow is along the throughbore 28. With the casing 52 cut, the pipe string 12 is raised so that the casing spear 46 grips the upper end 58 of the casing 52.

To operate the hydraulic jack 44, a first drop ball 38 is released from surface into the throughbore 28 (though there could be a ball release sub in the string 12 above the assembly 110 if desired). The first drop ball 38 travels by fluid pressure and/or gravity to the ball valve seat 14 of ball seat sub 14, having passed through the circulation sub 318 and the hydraulic jack 44 with actuator 116. The ball 38 when seated seals the throughbore 28 and blocks the passage of fluid through the pipe string 12 at the ball seat sub 14. By continuing to pump fluid from surface, the fluid pressure will increase above the ball 38 and consequently fluid entering the ports 144 on the hydraulic actuator 16 will have an increased pressure. Initially fluid will enter the chamber 156 of the anchor 128 and set the slips 152 against the inner wall 62 of the outer casing 54. With the hydraulic jack 44 held in place, fluid at the increased pressure will enter the actuator 116, through ports 144 and move the pistons 138 thereby raising the inner mandrel 130 relative to the upper pipe string 12. As the inner mandrel 130 forms a lower pipe string 12 and is connected to the casing spear 46, the cut section of casing 52 is raised. As the ball valve seat 36 is fixed, the ball 38 will remain in the seat 36 and a maximum pressure can be applied to operate the actuator 116. This is as illustrated in Figure 5(b).

It is hoped that the jack 44 can make a full stroke to give maximum lift to the casing 52. This is illustrated in Figure 5(b). If the casing 52 is still stuck only a partial stroke will be achieved. In either case, the anchor 128 is unset, by setting down weight and the hydraulic jack 44 is repositioned by pulling on the pipe string 12 to extend the mandrel 130 from the outer housing 132 of the jack 144.

When the pipe string 12 is to be pulled, a second drop ball 368 is released into the throughbore 28 from surface. The second drop ball 368 has a greater diameter than the first drop ball 38 and is sized to seat in the ball valve seat 334 of sleeve 330 in the circulation sub 318. It has sufficient weight to reach the seat 334 and seal the throughbore 28 at the circulation sub 318, above the actuator 116. By continuing to pump fluid from surface, the sub 318 can be operated to move the indexing sleeve

330 as described hereinbefore with reference to figures 4(a)-(d) which opens the radial aperture 324. Fluid can now flow from the throughbore 28 to the annulus 30. On pulling the pipe string 12 out of the well bore 13, fluid in the throughbore 28 can drain through the aperture 324.

If the section of casing 52 is free, the pipe string 12, downhole assembly 110 and recovered casing 52 can be raised out of the well 13 as illustrated in Figure 5(d). On raising the string 12, fluid will drain through the aperture 324 so that the pipe string 12 is empty when it reaches the surface. This removes the requirement to handle a wet string at surface. There will be fluid in the section of pipe string 12 between the circulation sub 118 and ball seat sub 14 but this should be a manageable quantity of fluid to handle at surface. If the section of casing 52 is not free, the pipe string 12 will stop when the inner mandrel 130 is fully extended, at Figure 5(c). To use the hydraulic jack 44 again, a further ball must be dropped. The further ball may be identical to ball 368. As described with reference to Figures 4(a)- (d), this further ball will close the aperture 324. The fluid pressure at the actuator 116 can be increased to operate the slips 152 again before the pistons 138 are moved to raise the casing spear 46 and cut section of casing 52 with the increased force from the jack 44. This is illustrated in Figure 5(b) again and the steps can be repeated as shown in Figures 5(b) and 5(c) by dropping further balls until the casing 52 is free and can be recovered as shown in Figure 5(d). As the circulation sub 118 has an indexing sleeve 330, this can be repositioned repeatedly by the dropping of a ball to open and close the aperture 324. The dropped balls will travel through the actuator 116 and come to rest on the ball 38 in the ball seat sub 14. Alternatively a ball catcher 244, may be located in the circulation sub 118.

While this method of casing recovery has been described using the circulation sub 318 which is multi-circulating, the downhole assembly can use any of the circulation subs 18, 218 described herein or variations thereof. If the basic sub 18 is used, the second drop ball will only be deployed if the casing 52 is free when the pipe string 12 is pulled.

The principle advantage of the present invention is that it provides a downhole assembly and method of operating a hydraulic actuator on a pipe string in a well bore which operates by simple drop ball operation while being able to drain the pipe string on POOFI.

A further advantage of the present invention is that it provides a downhole assembly and method of operating a hydraulic actuator on a pipe string in a well bore which allows a maximum fluid pressure to be applied to operate the actuator while being able to drain the pipe string on POOH.

A still further advantage of the present invention is that it provides a downhole assembly and method for casing recovery in a well which operates by simple drop ball operation while being able to drain the pipe string on POOH. 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 with the invention being defined within the scope of the claims.

Claims

1. A downhole assembly comprising, in order on a pipe string :

a hydraulic actuator, operated by fluid flow through a port from the throughbore to perform a task by the assembly downhole; and a circulation sub, the circulation sub including a second valve ball seat having a second clearance diameter for the flow of fluid along the throughbore of the pipe string to the hydraulic actuator and an obturating member connected to said second ball valve seat, the obturating member being moveable over an aperture giving access to an annulus outside the pipe string from the throughbore, wherein:

2. A downhole assembly according to claim 1 wherein the circulation sub is resettable by movement of the obturating member and passage of the second drop ball through the second valve ball seat.

3. A downhole assembly according to claim 2 wherein an indexing sleeve is connected to the obturating member to control the movement.

4. A downhole assembly according to any preceding claim wherein the assembly includes a hydraulic jack, the hydraulic jack comprising an anchor for axially fixing the assembly to a tubular in the well, and a mandrel connectable to a lower pipe string axially moveable relative to the anchor by activation of the hydraulic actuator.

5. A downhole assembly according to any preceding claim wherein the assembly includes a casing spear connected to the pipe string below the ball seat sub.

6. A downhole assembly according to claim 5 wherein the assembly includes a casing cutter connected to the pipe string below the casing spear.

7. A downhole assembly according to claim 4 wherein the hydraulic jack includes a housing supported in the well by the string and enclosing the hydraulic actuator, the hydraulic actuator comprising a plurality of axially stacked pistons generating a cumulative axial force, each of the plurality of pistons axially movable in response to the fluid entering a plurality of the ports; and wherein movement of the pistons also moves the mandrel, with the mandrel being an inner mandrel extending from the housing.

8. A downhole assembly according to claim 4 wherein the hydraulic jack includes an outer housing arranged around an upper mandrel connected to the pipe string and enclosing the hydraulic actuator, the hydraulic actuator comprising a plurality of axially stacked pistons generating a cumulative axial force, each of the plurality of pistons axially movable in response to the fluid entering a plurality of the ports; and wherein movement of the pistons also moves the mandrel, with the mandrel being a lower mandrel extending from a lower end of the outer housing.

9. A downhole assembly according to claim 7 or claim 8 wherein the axial force generated by the plurality of pistons acts simultaneously on the anchor and on the mandrel, such that the anchoring force increases when the axial force on the mandrel increases.

10. A downhole assembly according to claim 4 wherein the anchor includes a plurality of slips circumferentially spaced about the assembly for secured engagement with an interior wall of the tubular in the well.

11. A downhole assembly according to claim 5 wherein the casing spear comprises: a sliding assembly mounted on an inner mandrel; at least one gripper for gripping onto an inner wall of a length of casing in the well, the gripper being coupled to the sliding assembly; the sliding assembly being operable for moving the gripper between a first position in which the gripper is arranged to grip onto the inner wall of the length of casing in at least one gripping region of the length of casing and a second position in which the gripper is held away from the inner wall; and a switcher which, when advanced into the length of casing, locks the sliding assembly to the inner mandrel with the gripper in the second position; and, when the casing spear is pulled upward out of the length of casing and the switcher exits the end of the length of casing, automatically allows engagement of the length of casing by the gripper in the first position.

12. A method of operating an actuator on a pipe string in a well bore, comprising the steps:

(a) locating a downhole assembly according to any one of claims 1 to 11 on the pipe string; (b) running the pipe string into the well bore to a position at which the downhole assembly is to perform a task on operation of the hydraulic actuator;

(c) dropping the first ball down the throughbore of the pipe string from surface to pass through the circulation sub and hydraulic actuator to seat in the first valve ball seat and thereby seal the pipe string at the ball seat sub;

(d) increasing fluid pressure in the throughbore at the port to operate the hydraulic actuator and thereby perform the task with the downhole assembly;

(e) dropping the second ball down the throughbore of the pipe string from surface to seat in the second ball valve seat and thereby seal the pipe string at the circulation sub;

(f) increasing pressure at the second ball valve seat to move the obturating member from the first position to the second position to open the aperture and allow fluid flow from the throughbore to an annulus outside the downhole assembly; and

(g) pulling the pipe string and downhole assembly from the well bore while allowing fluid to drain from the throughbore to the annulus via the aperture.

13. A method of operating an actuator on a pipe string in a well bore according to claim 12 wherein the hydraulic actuator operates a hydraulic jack.

14. A method of operating an actuator on a pipe string in a well bore according to claim 12 or claim 13 wherein the method includes attaching a casing spear to a cut section of casing and pulling the cut section of casing as the task.

15. A method of operating an actuator on a pipe string in a well bore according to claim 14 wherein the method includes attaching a casing cutter to the downhole assembly and cutting casing in the well bore to provide the cut section of casing.

16. A method of operating an actuator on a pipe string in a well bore according to any one of claims 12 to 15 wherein the method includes the additional steps of closing the aperture, expelling the second ball through the second ball valve seat, increasing pressure to operate the hydraulic actuator again, dropping a further ball to seat in the second ball valve seat and opening the aperture, between steps (f) and (g).

17. A method of operating an actuator on a pipe string in a well bore according to claim 16 wherein the additional steps are repeated.