Hydraulically activated and mechanically set liner hanger

Abstract

A liner hanger assembly for hanging a liner from a casing string down a wellbore is provided. The liner hanger assembly includes a liner hanger comprising a housing and an actuation mechanism provided with slips operatively coupled to the housing. The actuation mechanism is mechanically operable to have slips engage the surrounding casing string and set the liner. The actuation mechanism has an actuation lock adapted to lock the actuation mechanism, where mechanical operation thereof is prevented, and unlock the actuation mechanism, where mechanical operation thereof is enabled. The liner hanger assembly also includes a running tool comprising a tool body releasably coupled to the housing and an activation mechanism hydraulically operable to cooperate with the actuation lock to enable unlocking the actuation mechanism. Prior to hydraulically operating the activation mechanism, the actuation mechanism is locked. A method for operating the liner hanger assembly is also provided.

Description

HYDRAULICALLY ACTIVATED AND MECHANICALLY SET LINER HANGERTECHNICAL FIELD

[0001] The present disclosure relates to devices, systems and methods for actuating a liner hanger during wellbore completion operations, and more particularly relates to hydraulically activated and mechanically actuated liner hanger assemblies.BACKGROUND

[0002] In downhole operations, liner hangers are often used during completion operations. Liner hangers are used to attach or hang liners from the internal wall of a previous casing string. The attached liners can be cemented in place to lengthen the casing along a wellbore. Known liner hangers are mechanically set (e.g., using a running tool) or hydraulically set (e.g., via pistons and differential pressure).

[0003] Known hydraulically operated liner hangers include pistons assemblies operable, via an increase of the internal pressure of the system, to have the slips engage the downhole end of the previous casing string. The piston can be integrated with or coupled to the walls of the liner hanger. It can also be desirable to provide a wide internal diameter of the liner for any subsequent operations. However, to make room for the piston assembly, which typically includes one or more piston chambers, the wall thickness of the liner is reduced, thereby reducing the pressure rating of the entire system, reducing suitability for high pressure applications (e.g. fracturing).

[0004] There is thus a need for a technology that overcomes at least some of the drawbacks of what is known in the field.SUMMARY

[0005] According to an aspect, a liner hanger assembly for hanging a liner from a casing string down a wellbore is provided. The liner hanger assembly includes a liner hanger comprising a housing and an actuation mechanism provided with slips operatively coupled to the housing, the actuation mechanism being mechanically operable between an unset configuration, where the slips are in a retracted state and spaced from the casing string, and a set configuration, where the slips in an extended state and engage the casing string to set the liner, the actuation mechanismcomprising an actuation lock adapted to operate the actuation mechanism between a locked configuration, where mechanical operation of the actuation mechanism is prevented, and an unlocked configuration, where mechanical operation of the actuation mechanism is enabled. The liner hanger assembly also includes a running tool comprising a tool body releasably coupled to the housing and an activation mechanism hydraulically operable to cooperate with the actuation lock to enable unlocking the actuation mechanism, wherein prior to hydraulically operating the activation mechanism, the actuation mechanism is in the locked configuration.

[0006] According to a possible implementation, mechanical operation of the actuation mechanism includes shifting the housing of the liner hanger along the wellbore via the running tool, and wherein the actuation mechanism comprises a slip actuator operatively coupled to the slips to prevent movement of the slips along the wellbore during mechanical operation of the actuation mechanism.

[0007] According to a possible implementation, the housing comprises slip slots shaped and sized to receive respective slips therein and comprising angled surfaces, and wherein the slip actuator comprises a retaining element configured to at least partially restrict downhole movement of the slips by engaging the casing string.

[0008] According to a possible implementation, the actuation lock comprises a lock pin, and wherein when the locked configuration, the lock pin secures the housing to the slip actuator to prevent relative movement therebetween, and, when in the unlocked configuration, the lock pin releases the slip actuator such that relative movement between the housing and the slip actuator and between the housing and the slips is enabled; and shifting the housing along the wellbore urges the slips outwardly and into the extended state.

[0009] According to a possible implementation, the lock pin extends through the housing and engages the slip actuator to lock the actuation mechanism, and wherein the lock pin is adapted to retract into the housing to disengage the slip actuator and unlock the actuation mechanism.

[0010] According to a possible implementation, the activation mechanism comprises a lock engager having a support base adapted to support the lock pin to prevent retraction of the lock pin and prevent unlocking the actuation mechanism.

[0011] According to a possible implementation, the activation mechanism comprises an activation piston coupled to the lock engager and hydraulically operable to shift the support base such that the lock pin becomes unsupported and allowed to retract to unlock the actuation mechanism.

[0012] According to a possible implementation, the activation mechanism comprises an activation sleeve releasably secured to the housing, the activation sleeve comprising the lock engager proximate a downhole end thereof and one or more piston surfaces defining the activation piston, and wherein hydraulically operating the activation piston releases the activation sleeve from the housing and shifts the activation sleeve along the housing.

[0013] According to a possible implementation, the liner hanger assembly further comprises a release assembly hydraulically operable to release the tool body from the housing to enable retrieval of the running tool.

[0014] A method of operating a liner hanger assembly for hanging a linerfrom a casing string down a wellbore, the method comprising : hydraulically operating an activation mechanism to unlock an actuation mechanism of a liner hanger comprising slips and enable engaging the slips with the casing string; mechanically operating the actuation mechanism via displacement of a running tool for engaging the slips with the casing string, where mechanical operation of the actuation mechanism is prevented prior to hydraulic operation of the activation mechanism.

[0015] According to a possible implementation, the activation mechanism is part of the running tool and includes an activation piston.

[0016] According to a possible implementation, the method further includes, after mechanical operation of the actuation mechanism, hydraulically operating a release assembly to disconnect the running tool from the liner hanger, and retrieving the running tool from the wellbore.

[0017] According to a possible implementation, hydraulic operation of at least one of the activation mechanism and the release assembly includes dropping a ball from surface to occlude internal passages of the running tool and increasing a fluid pressure along the liner hanger assembly.

[0018] According to a possible implementation, the release assembly is part of the running tool and includes a release piston.

[0019] According to a possible implementation, hydraulic operation of the release assembly includes a release sequence initiated by hydraulic operation of the release piston, and wherein the fluid pressure required to initiate the release sequence is greater than the fluid pressure required to hydraulically operate the activation piston.

[0020] According to a possible implementation, during the release sequence, the activation piston and the release piston cooperate to provide a combined piston area and increase an amount of force generated.

[0021] According to another aspect, a completion method for a wellbore provided with a casing string section is provided. The method includes : running a liner hanger comprising a liner downhole via a running tool and to a desired depth; hydraulically operating an activation mechanism to unlock an actuation mechanism of the liner hanger comprising slips and enable engaging the slips with the casing string section; mechanically operating the actuation mechanism via displacement of the running tool for engaging the slips with the casing string section and setting the liner, where mechanical operation of the actuation mechanism is prevented prior to hydraulic operation of the activation mechanism; and cementing the liner along the wellbore.

[0022] According to a possible implementation, the method further includes, prior to cementing the liner, hydraulically operating a release assembly to disconnect the running tool from the liner hanger; and retrieving the running tool from the wellbore.

[0023] According to a possible implementation, the method further includes, following the cementing of the liner, setting a liner top packer provided uphole of the liner hanger.

[0024] According to a possible implementation, setting the liner top packer is done via the running tool during the retrieval of the running tool from the wellbore.BRIEF DESCRIPTION OF DRAWINGS

[0025] Figure 1 is a schematic representation of a well completion system provided with a downhole assembly according to an implementation and including a running tool and a liner hanger.

[0026] Figure 2A is a cross-sectional view of the liner hanger shown in Figure 2A, showing slips in their respective slots, according to an implementation.

[0027] Figure 2B is a side view of the liner hanger shown in Figure 1 , showing slips provided about a liner mandrel, according to an implementation.

[0028] Figure 3 is an axial cross-sectional view of the running tool shown in Figure 1 , showing a running tool connector, according to an implementation.

[0029] Figure 4A is a cross-sectional view of the downhole assembly shown in Figure 1 , operated in a Run-ln-Hole (RIH) configuration, according to an implementation.

[0030] Figure 4B is a cross-sectional view of the downhole assembly shown in Figure 1 , operated in an occluded configuration, according to an implementation.

[0031] Figure 4C is a cross-sectional view of the downhole assembly shown in Figure 1 , operated in an activated configuration, according to an implementation.

[0032] Figure 4D is a cross-sectional view of the downhole assembly shown in Figure 1 , operated in an actuated configuration, according to an implementation.

[0033] Figure 5A is an enlarged view of the corresponding section shown in Figure 4A, showing fluid flow between an inner passage and different areas of the running tool, according to an implementation.

[0034] Figure 5B is a radial cross-sectional view of the running tool shown in Figure 4B, taken along line 5B-5B and showing setting pins extending through an activation sleeve, according to an implementation.

[0035] Figure 6A is a top view of the running tool shown in the downhole assembly of Figure 4A, showing an activation lock when the downhole assembly is operated in the RIH configuration, according to an implementation.

[0036] Figure 6B is a cross-sectional view taken along line 6B-6B shown in Figure 6A, showing pins of the activation lock when the downhole assembly is operated in the RIH configuration, according to an implementation.

[0037] Figure 6C is a cross-section view of an alternate implementation of the activation lock shown in Figure 6B.

[0038] Figure 7A is an enlarged view of the corresponding section shown in Figure 4C, showing the position of the slips when operating the downhole assembly in the activated configuration, according to an implementation.

[0039] Figure 7B is an enlarged view of the corresponding section shown in Figure 4C, showing a lock pin disengaged from a slip actuator when operating the downhole assembly in the activated configuration, according to an implementation.

[0040] Figure 8A is a top view of the running tool shown in the downhole assembly of Figure 4C, showing the activation lock when the downhole assembly is operated in the activated configuration, according to an implementation.

[0041] Figure 8B is a cross-sectional view taken along line 8B-8B shown in Figure 8A, showing pins of the activation lock when the downhole assembly is operated in the activated configuration, according to an implementation.

[0042] Figure 9 is an enlarged view of the corresponding section shown in Figure 4D, showing the position of the slips when operating the downhole assembly in the actuated configuration, according to an implementation.

[0043] Figure 10A is a cross-sectional view of the downhole assembly shown in Figure 4D, showing the downhole assembly during a first step of a release sequence, according to an implementation.

[0044] Figure 10B is an enlarged view of the corresponding section shown in Figure 10A, showing the position of a release sleeve during the first step of the release sequence, according to an implementation.

[0045] Figure 11 A is a cross-sectional view of the downhole assembly during a second step of the release sequence following the first step shown in Figure 10A, according to an implementation.

[0046] Figure 11 B is an enlarged view of the corresponding section shown in Figure 11 A, showing the position of the release sleeve during the second step of the release sequence, according to an implementation.

[0047] Figure 12A is a top view of the running tool shown in Figure the downhole assembly of Figure 11 A, showing the activation lock during the second step of the release sequence, according to an implementation.

[0048] Figure 12B is a cross-sectional view taken along line 12B-12B shown in Figure 12A, showing sheared pins of the activation lock during the second step of the release sequence, according to an implementation.

[0049] Figure 13 is a cross-sectional view of the downhole assembly during a third step of the release sequence following the second step shown in Figure 11 A, according to an implementation.

[0050] Figure 14 is a cross-sectional view of the downhole assembly during a fourth step of the release sequence following the third step shown in Figure 13, according to an implementation.

[0051] Figure 15 is a perspective view of a load connector for limiting downhole movement of inner components of the downhole assembly during the release sequence, according to an implementation.DETAILED DESCRIPTION

[0052] As will be explained below in relation to various implementations, the present disclosure describes apparatuses, systems and methods for setting a liner hanger along a wellbore, such as in preparation for wellbore completion operations.

[0053] In some implementations, the present disclosure describes devices, systems and methods associated with downhole assemblies provided with a running tool and a liner hanger. The liner hanger assembly includes integrated mechanisms configuredto prevent prematurely setting the liner hanger prior to activation, and enable release and retrieval of the running tool, among others, from the wellbore once the liner hanger is set. In some implementations, the liner hanger includes an actuation mechanism configured to set (e.g., connect) the liner hanger along the wellbore, an activation mechanism configured to selectively enable operation of the actuation mechanism, and a release assembly configured to enable disconnection and retrieval of one or more parts of the liner hanger assembly (e.g., the running tool) from the wellbore.

[0054] As will be further described below, the activation mechanism can enable maintaining a high running capacity by preventing the actuation mechanism from operating while running the liner hanger downhole (e.g., using the running tool). Once the desired depth is reached, the activation mechanism can be operated to enable operation of the actuation mechanism. It is therefore noted that the activation mechanism can function as a lock for the actuation mechanism. For instance, prior to operating the activation mechanism, the actuation mechanism is locked, thereby preventing the liner hanger to be accidently and / or prematurely set along the wellbore. Upon operation of the activation mechanism, the actuation mechanism is unlocked and operable to set the liner hanger along the wellbore. In this implementation, the activation mechanism is hydraulically operable, for example, via sealed fluid passages configured to increase the fluid pressure within the liner hanger assembly. Once activated (e.g., unlocked), the actuation mechanism can be mechanically operated, for example, via displacement of the liner hanger, or parts thereof, using the running tool, to set the liner hanger at the desired depth. Once set, the release assembly can be operated to disengage the running tool from the liner hanger, thereby enabling retrieval of the running tool, leaving the liner hanger connected to the wellbore. In this implementation, the release assembly is hydraulically operable, for example, via a further increase in fluid pressure along the liner hanger assembly.

[0055] It should be noted that the liner hanger assembly enables securing a liner string (or casing) along the wellbore at the desired depth. Once secured, downhole operations can be accomplished, such as completion operations including cementing the wellbore and setting packers at desired locations. It is noted that, by combining hydraulic activation and mechanical actuation, the present disclosure describes a hybrid, two-stage liner hanger assembly.

[0056] With reference to Figure 1 , completion of a wellbore 2 extending from a surface 1 into a reservoir 5 typically involves running a liner 3 into the wellbore to a desired depth and then anchoring, or setting, the liner in place, and optionally finalizing completion by cementing the annulus between the liner and the wellbore using techniques known in the art. The liner is anchored, in some instances, to a cemented surface or intermediate casing 4 using a liner hanger 14, typically attached to an uphole end to the liner 3. The liner 3 may be run into the wellbore anchored to a running tool 12 suspended from the surface 1. The running tool 12 may include other elements (not shown) for manipulation of the wellbore, including, but not limited to, a wiper plug, which may be released after the liner is anchored and cementing has begun, for example. Reference herein to a liner hanger assembly 10 is intended to refer to the combination of a liner hanger 14 and a running tool 12. The running tool and liner hanger cooperate to set the liner along the wellbore.

[0057] Referring to Figures 2A to 3, the liner hanger 14 includes a housing 16 defining a central bore 18 engageable by the running tool 12, and the running tool 12 similarly includes a tool body 15 defining an inner passage 20 extending therethrough. In this implementation, the liner hanger 14 includes an actuation mechanism 100 provided with slips 102 operable to extend outwardly to engage the surrounding wellbore or previously installed casing for setting the liner at the desired depth. However, during deployment of the liner hanger assembly 10, the actuation mechanism 100 can be operated in a locked configuration, thereby preventing the slips 102 from engaging the wellbore and setting the liner hanger 14 prematurely, for example. As will be described further below, the liner hanger assembly 10 includes an activation mechanism 200 operable to shift the actuation mechanism 100 from the locked configuration to an unlocked configuration to enable the slips 102 to extend out and engage the wellbore. The liner hanger assembly 10 also includes a release assembly 300 operable to disconnect the running tool 12 from the liner hanger 14 to enable retrieving the running tool from the wellbore once the liner hanger 14 is set.

[0058] Figures 4A to 4D illustrate various configurations for liner hanger assembly 10, including run-in-hole (RIH) configuration (Figure 4A), an occluded configuration (Figure 4B), an activated configuration (Figure 4C), and an actuated configuration (Figure 4D). The RIH configuration is adapted for running the liner hanger assembly10 down the wellbore to a desired depth. In the RIH configuration, the running tool 12 is coupled to the liner hanger 14 at one or more locations to enable running the liner hanger 14 downhole using the running tool 12. For instance, the running tool 12 can be inserted within the central bore 18 and coupled directly to the housing 16 of the liner hanger 14. Moreover, when in the RIH configuration, the actuation mechanism 100 is in the locked configuration to maintain the slips 102 in a retracted state, such as against or proximate to the housing 16 of the liner hanger 14. As seen in Figure 2B and 5A, the housing 16 of the liner hanger 14 includes slip slots 22 shaped and sized to receive respective slips 102. It is thus noted that, when the actuation mechanism is in the locked configuration, the slips 102 are in the retracted state and positioned within respective slip slots 22. In some implementation, the slips 102 are fully contained within the slip slots 22 when in the retracted state. In other words, the slips 102 do not protrude out from the slip slots 22 further than the outer diameter of the housing 16, although other configurations are possible.

[0059] During deployment of the liner hanger assembly 10, i.e., when in the RIH configuration, the inner passage 20 of the running tool 12 remains substantially clear of obstructions to have a substantially unobstructed fluid flow therethrough and across the liner hanger assembly 10. It should be noted that, by maintaining the actuation mechanism 100 in the locked configuration and keeping the inner passage 20 relatively clear, the liner hanger assembly 10 can be run downhole at a generally constant running capacity. For instance, the liner hanger assembly 10 can be deployed via the running tool 12 at a tensile capacity between about 150,000 pounds and 250,000 pounds, such as at about 200,000 pounds. It is further noted that, prior to the operation of the activation mechanism 200, the actuation mechanism 100 is, and remains, in the locked configuration, thereby preventing accidental, premature or otherwise unwanted extension of the slips 102 and setting of the liner along the wellbore.

[0060] Once the liner hanger assembly 10 has reached the desired depth / position along the wellbore, the activation mechanism 200 can be operated to unlock the actuation mechanism 100. In this implementation, the activation mechanism 200 is configured to be hydraulically operated, such as via fluid flow pumped downhole. For instance, and with reference to Figure 4B, an occluding device 202, configured to atleast partially occlude the inner passage of the running tool 12, can be provided. The occluding device 202 can be an integrated occluding device adapted to be run downhole along with the liner hanger assembly 10, or an independent occluding device adapted to be deployed downhole separately from the liner hanger assembly. In this implementation, the occluding device 202 includes a ball 204 dropped from the surface and configured to engage a ball seat 206 of the running tool 12, thereby blocking the inner passage 20. It is appreciated that, once the inner passage 20 is blocked, fluid pressure can be increased within the inner passage 20 of the liner hanger assembly 10 uphole of the occluding device 202 for operating the activation mechanism 200. It is noted that Figure 4B illustrates the liner hanger assembly 10 in an occluded RIH configuration.

[0061] With reference to Figures 4B, 4C, and 4D, occlusion of the inner passage 20 allows fluid pressure along the wellbore to be increased within the liner hanger assembly 10 (e.g., uphole of the occluding device 202). The fluid pressure within the liner hanger assembly 10 increases for operating the activation mechanism 200 to, in turn, permit activation of the actuation mechanism 100. In other words, hydraulic operation of the activation mechanism 200 (e.g., via an increased internal pressure of the liner hanger assembly) can shift the actuation mechanism 100 from the locked configuration to the unlocked configuration. When in the unlocked configuration, the actuation mechanism 100 can be operated to move the slips 102 from the retracted state (Figures 4A to 4C) to the extended or engaged state (Figure 4D). It is thus noted that Figure 4C illustrates the liner hanger assembly 10 in a non-actuated activated configuration, and that Figure 4D illustrates the liner hanger assembly 10 in an actuated activated configuration.

[0062] In this implementation, the actuation mechanism 100 is configured to be mechanically operated, such as via displacement of one or more components of the liner hanger assembly 10. For example, further displacement of the running tool 12 along the wellbore can urge (e.g., shift, slide, move, etc.) components of the liner hanger assembly 10 in a corresponding direction for operation of the actuation mechanism 100.

[0063] Operation of the actuation mechanism 100 operates the liner hanger 14 and sets the liner at the desired location along the wellbore. Once set, the releaseassembly 300 can be operated to disconnect the running tool 12 from the liner hanger 14, thereby enabling retrieval of the running tool 12 while leaving the liner connected to the wellbore. In this implementation, the release assembly 300 is configured to be hydraulically operated via fluid flow pumped downhole. It is noted that the occluding device 202 remains in place during operation of the actuation mechanism 100 such that continued pumping of fluid down the wellbore can further increase the fluid pressure within the liner hanger assembly 10. As will be described further below, the release assembly 300 is operable to perform multiple steps (illustrated in Figures 10A to 14), simultaneously and / or in rapid succession to disconnect the running tool 12 from the liner hanger 14 and release the occluding device from within the inner passage 20. With the running tool disconnected from the liner hanger 14 and the occluding device removed (e.g., unseated), the running tool can be retrieved from the wellbore.

[0064] Referring to Figures 4A to 7B, in this implementation, the actuation mechanism 100 is releasably and slidably coupled about the housing 16 and is operable between the locked configuration (shown in Figures 4A, 4B, and 5) and the unlocked configuration (shown in Figures 4C, 7A and 7B). More specifically, when in the locked configuration, the actuation mechanism 100 is secured to the housing 16 such that displacement of the running tool 12 (e.g., downhole) correspondingly displaces the liner hanger 14 and the actuation mechanism 100 in the same direction. This configuration (e.g., the RIH configuration) can be useful when running the liner hanger assembly 10 downhole as the slips are prevented from extending outwardly and the entire assembly can be displaced as a single, multi-part, unit. Upon shifting the actuation mechanism 100 in the unlocked configuration, one or more parts of the liner hanger assembly 10 are disconnected from each other, thereby enabling relative movement therebetween. As a result, the slips 102 can be outwardly biased to engage the wellbore, thereby setting the liner hanger 14 in the desired position, at the desired depth.

[0065] In some implementations, the housing 16 includes a top housing 24 and a liner mandrel 26 connected to one another to at least partially prevent relative movement therebetween. In other words, displacement of the housing 16 includes displacement of the top housing 24 and the liner mandrel 26 together. As seen in Figures 4A, 7Aand 9, the slip slots 22 are defined along the liner mandrel 26 portion of the housing 16, with the slips 102 being configured to engage respective slip slots 22 when in the retracted state (as seen in Figures 4B and 7A). In this implementation, the actuation mechanism 100 includes a slip actuator 110 configured to engage and assist in shifting the slips 102 from the retracted state to the extended state (the extended state being illustrated in Figures 4D and 9).

[0066] The slip actuator 110 can be releasably and slidably connected to the housing 16 on a first side thereof and adapted to engage the wellbore (or surrounding casing) on a second side thereof. While operating the actuation mechanism 100 in the locked configuration, the slip actuator 110 is adapted to be displaced together with the housing 16, whereas, when operating the actuation mechanism 100 in the unlocked configuration, the slip actuator 110 is disconnected from the housing 16, enabling relative movement therebetween. In this implementation, the slip actuator 110 is adapted to slide along the housing 16 when in the unlocked configuration of the actuation mechanism. More specifically, engagement of the slip actuator 110 with the wellbore enables the slip actuator 110 to remain substantially static while the housing 16 is urged downhole by the running tool 12. The slips 102 can be operatively coupled to the slip actuator 110 and adapted to slidably engage the housing 16. As such, the slips 102 can similarly be held in place as the housing 16 is displaced downhole.

[0067] Still referring to Figures 4A, 7A and 9, in some implementations, each slip slot22 includes inclined surfaces 23, and the slips 102 include similarly inclined slip surfaces 103 adapted to slidably engage respective inclined surfaces 23 of the slip slots 22. As previously mentioned, the slips 102 are adapted to extend outwardly upon mechanical operation of the actuation mechanism 100. More specifically, displacing the running tool 12 downhole, when in the unlocked configuration of the actuation mechanism, urges the liner mandrel 26 downhole, which brings the inclined surfaces23 in sliding engagement with the inclined slip surfaces 103. The shape and configuration of the slips and slip slots urges the slips 102 outwardly and away from the liner mandrel 26, as illustrated in Figures 4D and 9. The slips 102 can include a gripping outer surface 105 configured to grip into the wellbore (or surrounding casing) to set the liner hanger in position. The gripping outer surface 105 can have any suitableconfiguration, such as including serrated sections, for example, as illustrated in Figures 7 A and 9.

[0068] In some implementations, and with reference to Figure 4B, 4C, 5A and 9, the slip actuator 110 can include a setting sleeve 114 slidably coupled about the housing 16, a slip cage 116 connected to the setting sleeve 114 on a first side thereof, and a retaining element 118 connected to the setting sleeve 114 on a second side thereof, opposite the slip cage 116. Each one of the slips 102 has a first end 102a pivotally connected to the slip cage 106, and a second end 102b, opposite the first end. In some embodiments, the second end 102b is coupled to the liner mandrel 26. The retaining element 118 is configured to prevent, or at least restrict downhole movement of the setting sleeve 114 by engaging the surrounding wellbore or casing string. It should therefore be understood that the housing 16, including the liner mandrel 26 and the slip slots 22, is adapted to be displaced downhole, while the setting sleeve 114, the slip cage 116 and the slips 102 are generally retained in position by the retaining element 118. This configuration enables the slips 102 to extend outwardly, as previously described. It should also be noted that, since the each of the first end 102a and the second end 102b is coupled to the slip cage 106 and the liner mandrel 26, respectively, the slips 102 are adapted to “bulge” outwardly in order to engage the surrounding wellbore, as shown in Figure 4D, among others.

[0069] In this implementation, the retaining element 118 includes a resilient element 120 shaped and biased outwardly and away from the liner mandrel 26 (e.g., towards the wellbore or surrounding casing). The resilient element 120 can thus engage the wellbore to maintain the slip actuator 110 in place as the housing 16 is displaced downhole. The resilient element 120 can include a bow spring 122 having a first end connected to the setting sleeve 114 and an arcuate body configured to bulge out to engage the wellbore and restrict downhole movement of the slip actuator 110 and of the slips 102. Alternatively, the resilient element 120 can include a spring stack coupled to the slip actuator 110 for preventing, or at least restricting downhole movement thereof as the housing is displaced downhole. As the downhole assembly is run downhole (e.g., in the RIH configuration), the spring stack can be secured in a preloaded state, where the spring stack is compressed. Once the liner hanger has reached the desired depth / position along the wellbore, the spring stack can bereleased from the preloaded state to enable an uphole force to be applied on the setting sleeve, thereby driving the slips 102 outwardly and into the wellbore (or surrounding casing).

[0070] As seen in Figures 4A to 5A, the running tool 12 is coupled to the top housing 24 via a running tool connector 302. The running tool connector 302 urges the top housing 24 along the wellbore during displacement of the running tool 12. In this implementation, the actuating mechanism 100 includes an actuation lock configured to releasably connect the liner mandrel 26 to the slip actuator 110. During operation of the actuation mechanism 100 in the locked configuration, the actuation lock 124 is adapted to secure the liner mandrel 26 to the slip actuator 110, such as to the setting sleeve 114, in order to prevent relative movement therebetween. Upon operating the actuation mechanism 100 in the unlocked configuration, the actuation lock 124 is adapted to release the slip actuator 110 to enable relative movement between the housing 16 and the slip actuator 110 (e.g., between the liner mandrel 26 and the setting sleeve 114).

[0071] The actuation lock 124 (Figure 7B) can include at least one lock pin 126 shaped and configured to extend from the liner mandrel 26 and engage the slip actuator 110 (e.g., the setting sleeve 114), thereby establishing the connection therebetween. It is thus noted that displacement of the running tool 12 urges the top housing 24 in the corresponding direction, which similarly urges the liner mandrel 26 in displacement, which in turn displaces the slip actuator 110 (when in the locked configuration). It is further noted that, in this implementation, the running tool 12, the housing 16 and the actuation mechanism 100 are mechanically connectable to one another. In other words, a mechanical fastener and / or physical component extends between or otherwise connects at least two of these components to one another.

[0072] In some implementations, the lock pin 126 extends through a thickness of the liner mandrel 26 such that a head portion 128 thereof extends from a first side of the liner mandrel 26 to engage the slip actuator 110, and a base portion 130 thereof extends from a second side of the liner mandrel 26. As seen in Figures 5 and 7B, in addition to the lock pin 126, the actuation lock 124 can include a lock recess 132 defined on a component of the slip actuator 110 and configured to receive the head portion 128 of the lock pin 126 therein for connecting the housing to the slip actuator.In this implementation, the lock recess 132 is defined along the setting sleeve 114, although other configurations are possible. The head portion 128 and the lock recess 132 can have complementarily-shaped profiles to assist in retaining the head portion 128 in the lock recess 132. It is thus noted that the complementarily-shaped profiles can assist in maintaining the connection between the housing and the slip actuator to prevent relative movement therebetween. In some implementations, the complementarily-shaped profiles can include a pair of jagged surfaces and / or any other suitable configuration.

[0073] Still with reference to Figures 5A and 7B, the lock pin 126 is adapted to be maintained in engagement with the slip actuator 110 by the activation mechanism 200, or at least a component thereof. Upon operation of the activation mechanism 200, the lock pin 124 is allowed to retract from the lock recess 132, thereby releasing the slip actuator 110 and operating the actuation mechanism 100 in the unlocked configuration. The liner hanger can then be set at the desired depth by mechanically operating (e.g., displacing) the running tool to urge the slips 102 outwardly to engage the wellbore.

[0074] Referring to Figures 4B to 7B, in this implementation, the activation mechanism 200 is adapted to slidably engage the central bore of the liner hanger 14 and is operable to shift the actuation mechanism 100 from the locked configuration to the unlocked configuration. For instance, the activation mechanism 200 can include an activation sleeve 212 configured to be in engagement with the actuation lock 124 for operation of the actuation mechanism 100 from the locked configuration to the unlocked configuration. In other words, the position of the activation sleeve 212 along the central bore 18 can prevent the activation lock 124 (e.g., the lock pin 126) from releasing the slip actuator 110 when in a first position and allow the activation lock to release the slip actuator when in a second position. Upon operation of the activation mechanism 200, the activation sleeve 212 is adapted to slide along the central bore from the first position to the second position to disengage the actuation lock 124, thus operating the actuation mechanism in the unlocked configuration.

[0075] In some implementations, the activation mechanism 200 is hydraulically operable to shift the activation sleeve 212 and release the actuation lock 124. For example, the activation sleeve 212 can cooperate with, or be part of a piston assembly210. The piston assembly 210 is configured to slide one or more components of the activation mechanism (e.g., the activation sleeve 212) along central bore 18 of the liner hanger 14 upon hydraulic operation thereof. It should be noted that, as used herein, the expression “hydraulic operation” and variants thereof, can refer to the operation of a component through the use of one or more fluids. For example, components can be operated under certain conditions, such as during injection of fluids at a predetermined flowrate, upon reaching a fluid pressure threshold, or simply from the presence of a certain type of fluid (e.g., dissolving components configured to degrade upon contact with fluid).

[0076] With reference to Figures 4B and 5A, the activation sleeve 212 can include a lock engager 214 configured to cooperate with the lock pin 126 to prevent and enable disengagement of the lock pin 126 from the slip actuator 110. In this implementation, the lock engager 214 is defined proximate the downhole end of the activation sleeve 212 and includes a support base 216 and a groove 218 adjacent one another. The support base 216 and the groove 218 cooperate to define a stepped profile of the lock engager 214 with surfaces at different elevations. As seen in Figure 5A, when the actuation mechanism is locked, the base portion 130 of the lock pin 126 is adapted to rest on the support base 216 of the lock engager 214, which prevents retraction of the lock pin 126 from the slip actuator. In other words, the support base 216 provides a barrier or mechanical interference configured to physically prevent disengagement of the lock pin 126 from the slip actuator. Upon sliding the activation sleeve 212, as seen in Figure 7B, the lock pin 126 becomes aligned with the groove 218 of the lock engager 214, which is illustratively lower than the support base 216, to enable disengagement of the lock pin 126 from the slip actuator. As previously described, disengagement of the lock pin 126 from the slip actuator 110 corresponds to operation of the actuation mechanism 100 in the unlocked configuration.

[0077] In this implementation, and as seen in Figure 4B, hydraulic operation of the activation mechanism 200 can be initiated by deploying the occluding device 202 to block the inner passage 20 of the running tool 12 and enable increasing the fluid pressure within the liner hanger assembly 10. The piston assembly 210 can include one or more piston areas against which the fluid pressure can generate a shifting forceto displace the corresponding component of the activation mechanism 200, such as the activation sleeve 212, for example.

[0078] With reference to Figures 5A and 5B, the activation sleeve 212 can be slidably positioned between the housing 16 of the liner hanger 14 and the tool body 15 of the running tool 12. The piston assembly 210 can include ports 215, such as through the tool body 15, enabling fluid communication between the inner passage 20 and the activation sleeve 212. In addition, sealing elements 220, such as O-rings, can be provided between the components of the liner hanger assembly 10 to assist in directing fluid pressure within the desired piston area(s) and / or against desired surfaces. In this implementation, fluid flow (F) is allowed between the inner passage 20 and one or more piston areas 225 of the activation sleeve 212 to generate a shifting force thereon. Still referring to Figures 5A and 5B, fluid can flow along paths defined through the ports 215 and / or along interstices to reach a first piston area 225a communicating with an inner surface 212a of the activation sleeve 212. In some implementations, the activation sleeve 212 can define additional piston areas 225, such as a second piston area 225b, communicating with an outer surface 212b of the activation sleeve 212. It should be noted that the fluid pressure within the liner hanger assembly 10 is generally the same within each one of the piston areas 225. Therefore, it is appreciated that each surface having a radial component in communication with the piston areas 225 can assist in shifting the activation sleeve 212. In other words, the surface area of the different surfaces can be cumulative for generating a greater shifting force to the activation sleeve, although other configurations are possible.

[0079] In some implementations, the activation mechanism 200 can be provided with an activation lock 224 configured to releasably connect the activation sleeve 212 to the running tool 12 (e.g., to the tool body 15). With reference to Figures 6A and 6B in addition to Figures 5A and 5B, prior to engaging the occluding device 202 and increasing the fluid pressure along the liner hanger assembly 10, the activation lock 224 secures the activation sleeve 212 to the tool body 15 in order to prevent relative movement therebetween. Upon blocking the inner passage 20 via the occluding device 202 and “charging up” (e.g., increasing the internal pressure of) the liner hanger assembly 10, the activation lock 224 is adapted to at least partially release the activation sleeve 212 to enable relative movement between the activation sleeve 212and the tool body 15. In other words, the activation sleeve 212 is allowed to move upon operation of the liner hanger assembly 10 in the occluded RIH configuration, as seen in Figure 4B, and upon increasing the pressure along the liner hanger assembly 10.

[0080] The activation lock 224 can include at least one setting pin 226 shaped and configured to extend from the activation sleeve 212 and engage the tool body 15, thereby establishing a mechanical connection therebetween. It is thus noted that, while the setting pin 226 is in place, displacement of the running tool 12 (e.g., downhole) urges the activation sleeve 212 in the corresponding direction. The setting pin 226 is adapted to prevent relative movement between the activation sleeve 212 and the tool body 15 while the pressure along the liner hanger assembly is below an activation pressure threshold. It is thus noted that the pressure within the liner hanger assembly can be progressively increased without necessarily disconnecting the activation sleeve 212 from the tool body 15. Once the pressure reaches the activation pressure threshold, the setting pin 226 is adapted to release the tool body 15 and enable movement of the activation sleeve 212.

[0081] In this implementation, the setting pin 226 corresponds to a setting shear screw 228 configured to rupture or break upon sustaining a predetermined force, such as the shifting force generated by the activation pressure threshold, for instance (Force = psi x Area of Piston). It is appreciated that, upon breaking the setting shear screw 228, the activation sleeve 212 is adapted to move downhole as fluid pressure continues to generate the shifting force on the surfaces of the piston areas 225. As will be described further below, the activation lock 224 can further include a limiter 230 configured to limit downhole movement of the activation sleeve 212 following the disconnection of the setting pin 226. As the activation sleeve 212 is released and shifted downhole, the lock engager 214 is correspondingly displaced, thereby releasing the lock pin 126 of the actuation mechanism 100 (seen in Figures 4C and 7B). As previously described, releasing the lock pin 126 “activates” the actuation mechanism 100 (e.g., operates the actuation mechanism 100 in the unlocked configuration), and enables setting the liner hanger along the wellbore. In other words, shifting the activation sleeve 212 downhole shifts the liner hanger assembly 10 to the non-actuated activated configuration (seenin Figure 4C), and enables operation of the actuation mechanism 100 to shift the liner hanger assembly 10 to the actuated activated configuration (seen in Figure 4D).

[0082] With reference to Figures 6A, 6B, 8A and 8B, the limiter 230 of the activation lock 224 can include a tab 232 extending from one of the activation sleeve 212 and the tool body 15, and a slot 234 defined along the other one of the activation sleeve 212 and the tool body 15. In this implementation, the slot 234 is defined in a thickness of the tool body 15 and the tab 232 extends from the activation sleeve 212. More specifically, the slot 234 extends longitudinally (e.g., parallel to the longitudinal axis of the liner hanger assembly 10) and is shaped and configured to receive the tab 232 therein. The tab 232 includes a head 233 configured to engage the slot, and is thus restricted to move along the slot 234. In other words, the slot 234 (e.g., the walls thereof) is adapted to restrain or limit movement of the head of the tab.

[0083] In some implementations, and as seen in Figure 6B, when operating the liner hanger assembly in the RIH or occluded RIH configuration, the setting pin 226 connects the activation sleeve 212 to the tool body 15, and the tab 232 is located proximate a first end of the slot 234. Once the activation mechanism 200 is operated, the setting pin 226 breaks and the activation sleeve 212 is shifted, thus operating the liner hanger assembly in the activated configuration. As seen in Figure 8B, the setting pin 226 is broken and the tab 232 abuts against a second end of the slot 234. It should be understood that the abutment between the tab 232 and the second end of the slot 234 prevents further downhole movement of the activation sleeve. In other words, the second end of the slot 234 limits downhole movement of the activation sleeve. It is appreciated that the configuration of the limiter described above is exemplary only, and that other configurations are possible.

[0084] In this implementation, the limiter 230 includes a plurality of tabs 232 engaging respective slots 234 defined along the tool body 15. As will be described further below, this configuration of the activation lock can assist in preventing premature operation of the release assembly 300. For instance, and as seen in Figure 8A, a plurality of tabs 232 abutting against the second end of respective slots 234 can prevent damages to the tabs 232 when compared to a single tab 232. More particularly, a plurality of tabs 232 can be adapted to sustain larger shifting forces by dividing the forces substantially equally between the tabs. In contrast, a single tab 232 can sustain the entirety of theshifting force, which can break or otherwise damage the tab 232, thus enabling further downhole movement of the activation sleeve 212 (which may be unwanted).

[0085] In some implementations, the tabs 232 include shear pins 232A configured to break (e.g., shear) upon sustaining a predetermined or desired force. Upon breaking the shear pins 232A, further downhole movement of the activation sleeve 212 is allowed, which can be part of the operation sequence of the release assembly 300, as will be described below.

[0086] With reference to Figure 6C, an alternate implementation of the tabs 232 (e.g., the shear screws 232A seen in Figures 6A and 8A) is shown. In this alternate implementation, the tab is a shear screw 232B having a larger diameter and which is configured to withstand greater forces, for example, than the setting pin of the activation lock or the individual shear screw 232A of the limiter described above. By providing the larger shear screw 232B (configured to withstand greater forces), it is appreciated that the number of shear screws can be reduced, such as to a single shear screw 232B per limiter 230 (down from three shear screws 232A).

[0087] With reference to Figures 10A to 14, in this implementation, the release assembly 300 is operable to disconnect the running tool 12 from the liner hanger 14 in order to enable retrieval of the running tool 12. It should be understood that that the running tool 12 can be retrieved once the liner hanger 14 is set downhole, e.g., once the actuation mechanism is activated and actuated. As will be described further below, operation of the release assembly 300 also enables release of the occluding device 202 from the inner passage 20. It is noted that releasing the occluding device 202 can clear, at least partially, the inner passage 20 of the running tool 12, which can enable, or at least facilitate retrieval operations.

[0088] In some implementations, the running tool 12 is releasably coupled to the liner hanger 14. For instance, the running tool 12 can be coupled to the liner hanger 14 via the running tool connectors 302 (commonly referred to as “dogs”) configured to interlock with one another to enable urging the top housing 24 along the wellbore during displacement of the running tool 12. More specifically, the running tool 12 can include an inner connector 304 extending from the tool body 15, and the liner hanger 14 can include an outer connector 306 extending from the housing 16. The inner andouter connectors 304, 306 can have complementarily-shaped features enabling cooperation (e.g., the interlocking thereof) and prevent relative movement therebetween when connected.

[0089] In this implementation, each one of the inner and outer connectors 304, 306 includes a set of teeth 308 configured to engage with the set of teeth 308 of the other one of the connectors to connect the running tool and liner hanger together. In some implementations, the sets of teeth 308 can be configured to prevent relative movement between the running tool and liner hanger when displacing the running tool in a first direction (e.g., downhole), and allow movement of the running tool relative to the liner hanger when displacing the running tool in a second direction (e.g., uphole). Alternatively, the sets of teeth 308 can be configured to prevent relative movement between the running tool and liner hanger in both the first and second directions. In some implementations, relative rotational movement between the running tool and liner hanger can also be prevented. Prevention of the relative rotational movement can be provided by the running tool connectors 302, another component of the running tool assembly, or a combination thereof, for example.

[0090] It should be noted that the angle of the surfaces defining the teeth 308 allows and / or prevents the relative movement between the running tool and the liner hanger. For example, the teeth 308 can have respective perpendicular surfaces adapted to engage one another to prevent relative movement and enable dragging the liner hanger 14 downhole with the running tool 12. The teeth can also have respective angled surfaces adapted to enable relative movement between the running tool 12 and the liner hanger 14 upon the application of sufficient force in the corresponding direction. For example, the running tool 12 can be ratchetted in various positions relative to the liner hanger 14 upon the application of sufficient force in the uphole direction. It is noted that the angle of the angled surfaces 312 can determine the amount of force required to move (e.g., ratchet) the running tool 12 relative to the liner hanger 14. It should be understood that angles nearing a perpendicularity with the running tool and / or the liner hanger (e.g., proximate to 90 degrees) can result in a greater required force to move the running tool, for example, when compared to smaller angles, such as 75 degrees, 60 degrees, 50 degrees, 45 degrees, 30 degrees, 20 degrees, etc.

[0091] With reference to Figures 10A to 11 A, in addition to Figure 4D, in some implementations, the tool body 15 of the running tool 12 can include multiple components connected to one another, including components of the release assembly 300. In this implementation, the tool body 15 includes an inner sleeve 315 which defines the inner passage 20, and a connector sleeve 314 coupled about the inner sleeve 315 and adapted to house the inner connectors 304. The connector sleeve 314 includes a slot 316 defined therein for receiving the inner connector 304 therein. The slot 316 extends through a thickness of the connector sleeve 314 such that the inner connector 304 is adapted to engage the outer connector 306 with a top side thereof (e.g., comprising the teeth), and to engage the inner sleeve 315 with a bottom side thereof.

[0092] In this implementation, prior to operating the release assembly 300, the connector sleeve 314 and the inner sleeve 315 are connected together such that relative movement therebetween is prevented. It should also be noted that the running tool connectors 302 are maintained in engagement with one another as the running tool assembly 10 is run downhole, during operation of the activation mechanism and during operation of the actuation mechanism. In other words, and as previously mentioned, the running tool 12 remains releasably connected to the liner hanger 14 prior to operation of the release assembly 300. It should therefore be noted that mechanical activation of the actuation mechanism via the running tool is prevented due to the connection between the inner and outer connectors 304, 306. More particularly, in this implementation, the activation sleeve 212 is not adapted to be shifted downhole via downhole movement of the running tool 12.

[0093] In this implementation, the inner sleeve 315 is adapted to support and maintain the inner connector 304 within the slot 316 and in engagement with the outer connector 306. As will be described in greater detail further below, operation of the release assembly 300 can enable relative movement between the connector sleeve and the inner sleeve such that the inner connector 304 becomes unsupported and allowed to disengage the outer connector 306. The running tool 12 thus becomes disconnected from the liner hanger 14 and can be retrieved from the wellbore.

[0094] In this implementation, the inner sleeve 315 includes a mandrel 318 provided with an inner shoulder 320 adapted to contact the bottom side of the inner connector304 to prevent disengagement of the inner connector 304 from the outer connector 306. The inner shoulder 320 can extend outwardly from the mandrel 318 such that an outer diameter (OD) of the inner sleeve 315 is greater along the inner shoulder 320 than along the rest of the mandrel 318. Upon operation of the release assembly 300, the inner sleeve is shifted to position the inner shoulder adjacent to the inner connector 304, thereby enabling the inner connector 304 to retract and disengage the outer connector 306. It is noted that the inner connector “falls” inwardly and abuts the mandrel 318 of the inner sleeve upon moving the inner shoulder 320. It is therefore noted that the difference between the OD of the mandrel 318 and the OD of the inner shoulder 320 is at least similar to the size (e.g., height) of the teeth in order to enable disengagement between the inner and outer connectors.

[0095] It should be understood that, in this implementation, the inner connectors 304 are slidably coupled to the connector sleeve 314 and adapted to slide (e.g., inwardly) upon moving the inner sleeve 315 and unsupporting the inner connector 304. In other words, the inner connector 304 is independently movable relative to the connector sleeve 314 and the inner sleeve 315, and is adapted to move away from the outer connector 306 (e.g., in a straight line). In alternate implementations, the inner connector 304 can be integrally formed with at least one of the inner sleeve and the connector sleeve, and / or configured to disengage the outer connector 306 upon rotational movement of the tool body 15. It is thus appreciated that disconnection of the running tool from the liner hanger can be accomplished via axial movement, rotational movement or a combination thereof.

[0096] Similarly, the outer connector 306 can be integrally formed with the housing 16 (e.g., as seen in Figures 2A, 4D and 10A) or can be secured thereto via any suitable manner, such as mechanical fasteners, press-fit connection, adhesive, etc.

[0097] Still with reference to Figures 10A to 11A, in this implementation the tool body 15 also includes a release sleeve 325 releasably coupled to the inner sleeve 315 and the connector sleeve 314. More specifically, the release sleeve 325 is adapted to establish the connection between the connector sleeve 314 and the inner sleeve 315 such that these components can be displaced along the wellbore together. The release sleeve 325 is illustratively provided between the inner sleeve 315 and the activation sleeve 212 and can include ports or openings 326 enabling fluid flow intothe piston areas 225. As seen in Figure 5A, fluid is adapted to flow from the inner passage 20 of the inner sleeve, through the ports 215 to reach the release sleeve 325, and through the openings 326 to reach the activation sleeve 212.

[0098] It should be noted that, when in the actuated activated configuration (Figure 4D), and prior to operating the release assembly, the liner hanger assembly 10 is relatively static. For example, the slips are in engagement with the surrounding wellbore, thus preventing movement of the housing 16. The limiter 230 prevents further downhole movement of the activation sleeve 212 (e.g., the tabs 232 abut against the end of respective slots 234 defined in the release sleeve 325), and the tool body 15 (e.g., the inner sleeve, the connector sleeve and the release sleeve) is prevented from further downhole movement due to the connection between the running tool connectors 302.

[0099] In some implementations, operation of the release assembly 300 can include a release sequence of successive and / or simultaneous steps. For example, from the actuated activated configuration (Figure 4D) the release sequence can be initiated by increasing the fluid pressure along the liner hanger assembly 10, i.e. , the release assembly 300 is hydraulically operable. With the occluding device 202 (e.g., the ball 204) still in the seated configuration, pumping fluid downhole can increase the fluid pressure within the liner hanger assembly 10. In this implementation, the seat 206 is part of a collet 208 coupled to the inner sleeve 315. As such, increasing the fluid pressure within the inner passage 20 increases the shifting force applied to the ball 204, to the collet 208 and to the inner sleeve 315.

[0100] As seen in Figures 9 and 10B, the inner sleeve 315 is releasably coupled to the release sleeve 325 via a breakable connector 328 (e.g., a shear screw). The initial step of the release sequence can therefore include shifting the inner sleeve 315 downhole upon reaching a release pressure threshold and breaking the breakable connector 328. It should be noted that the fluid pressure generating the shifting force on the ball is substantially the same as the fluid pressure within the piston areas and generating shifting forces of the activation sleeve and on the inner sleeve. It is further noted that the limiter 230 is configured to sustain a greater force than the breakable connector 328 to maintain the activation sleeve in position while the inner sleeve 315 is shifted downhole.

[0101] In this implementation, the downhole movement of the inner sleeve 315 during the initial step of the release sequence can be limited. For example, the inner sleeve 315 can include a load connector 330 connected to and extending from the inner sleeve 315 and adapted to engage another component within the liner hanger assembly to limit downhole movement of the inner sleeve during the initial step of the release sequence. Still with reference to Figures 9 and 10B, the activation sleeve 212 can include a load shoulder 332 defining an abutment surface 333 for the load connector 330. As mentioned, the limiter 230 prevents further downhole movement of the activation sleeve 212. Therefore, engagement of the load connector 330 with the load shoulder 332 blocks further downhole movement of the inner sleeve 315. It should be understood that, in this configuration (i.e. , at this step of the release sequence), both the activation sleeve 212 and the inner sleeve 315 are blocked from further downhole movement by the limiter. In this implementation, the load connector 330 extends from the inner sleeve 315 and is shaped and adapted to slide along the release sleeve 325, such as along one of the openings 326 thereof, for example.

[0102] In some implementations, and as seen in Figure 15, the load connector 330 can be L-shaped and include a first section 330a extending from the inner sleeve to the activation sleeve, and a second section 330b adapted to extend over the release sleeve. The first section can be adapted to guide the load connector along the opening of the release sleeve, while the second section can be adapted to keep the load connector in position between the inner sleeve and the activation sleeve. However, it is appreciated that this configuration is exemplary and that other shapes, sizes and configurations are possible for enabling cooperation between the inner sleeve and the activation sleeve, such as T-shaped load connectors, for example.

[0103] Now referring to Figures 11A to 12B, in addition to Figures 9 to 10B, following the initial step of the release sequence, fluid pressure can be further increased along the liner hanger assembly 10. Similar to the initial step, the ball is still in the seated configuration, and the components of the liner hanger assembly 10 are substantially static. As mentioned, the load connector 330 abuts the load shoulder 332 of the activation sleeve, which is held in place by the limiter 230. In this configuration, the fluid pressure within the liner hanger assembly 10 can generate a shifting force on each surface in communication with the piston areas and the inner passage, such asthe ball, the inner and outer surfaces 212a, 212b of the activation sleeve, an uphole side of the load connector 330, the surfaces of the inner sleeve, etc.

[0104] In this implementation, upon reaching a predetermined fluid pressure, the cumulative shifting force generated on the inner sleeve and the activation sleeve can be sufficient to destroy (e.g., collapse, break, remove, etc.) the limiter 230, thus enabling further downhole movement of both the inner sleeve and the activation sleeve. More particularly, and as seen in Figures 12A and 12B, the shear pins 232A have sheared, enabling relative movement between the activation sleeve 212 and the release sleeve 325. As seen in Figure 11 B, upon breaking the shear pins 232A of the limiter 230, the fluid pressure urges the activation sleeve further downhole which subsequently breaks the base portion of lock pin 126. It is noted that the head portion is held in place within the recess 132 as the activation sleeve shears the base portion during downhole movement. It should be noted that, during this step of the release sequence (e.g., the second step), the shear screws 232A and the lock pin 126 can be broken in rapid succession or generally simultaneously.

[0105] Now referring to Figures 13 and 14, following the second step of the release sequence, the activation sleeve 212 is urged downhole via fluid pressure until it abuts against a release sub 340 secured at a downhole end of the release sleeve 325. It is noted that the uphole end 342 of the release sub 340 is secured to the release sleeve 325 and positioned within an annulus defined between the release sleeve 325 and the housing 16 (similar to the activation sleeve). As such, in this implementation, the release sub 340 is adapted to prevent further downhole movement of the activation sleeve. The inner sleeve 315 is similarly urged downhole by the fluid pressure within the liner hanger assembly 10. As seen in Figure 13, the inner sleeve 315 is shifted downhole, which disengages the inner shoulder 320 from the inner connector 304. The inner connector 304 is then free to retract and disengage the outer connector 306. The inner sleeve is urged downhole in this manner until the load connector 330 engages once again the load shoulder 332.

[0106] With reference to Figure 14, the release sub 340 is adapted to define a release chamber 344 having an inner diameter greater than or substantially equal to the outer diameter of the release sleeve 325. It should thus be understood that the inner diameter of the release chamber 344 is greater than the outer diameter of the innersleeve 315 and of the collet 208 (which is similar to that of the inner sleeve). In this implementation, upon engagement of the load connector 330 with the load shoulder 332 (e.g., the third step of the release sequence), the inner sleeve 315 at least partially engages the release sub 340, thereby positioning the collet 208 within the release chamber 344. In some implementations, the collet 208 is configured to expand radially outwardly to deform the seat 206 and release the ball. As such, positioning the collet 208 within the release chamber 344 provides sufficient space for the collet to expand and release the ball. It is appreciated that, prior to positioning the collet 208 within the release chamber 344, the collet engages the inner surface of the release sleeve, which prevents outward expansion thereof. The seat 206 is thus maintained and the ball 204 kept in place to occlude the inner passage 20.

[0107] Upon release of the ball 204 (e.g., the fourth step of the release sequence), the running tool 12, having been disconnected from the liner hanger 14, can be pulled out and retrieved from the wellbore. It is appreciated that, prior to pulling the running tool 12 from the wellbore, an operator may choose to move the running further downhole to confirm the disconnection from the liner hanger 14 (e.g., confirm the proper operation of the release assembly 300). Once confirmed, the running tool 12 is free to be retrieved, thus leaving the liner hanger 14 coupled in place at the desired location / depth down the wellbore.

[0108] From the above, it should be noted that the release assembly is hydraulically operated, and that the release sequence is initiated upon reaching the release pressure threshold. Once initiated, the release sequence includes in fast succession, shearing of the breakable connector 328, shearing of the shear screws 232A, shearing of the lock pin 126, disengagement of the running tool connectors 302 and release of the collet 208 and ball 204.

[0109] The components of the piston assembly 210 and the release assembly 300 can be configured and designed to resist an / or generate predetermined amounts of force in order to execute the release sequence in the proper order. For instance, in this implementation, the limiter 230 is configured to break at a force greater than the force required to break the breakable connector 328. This configuration ensures that step one of the release sequence, as described herein, is performed before step two. Similarly, the size of the piston surface areas can be designed to enable the generationof a sufficient shifting force to enable movement of the corresponding component and / or enable breaking the required connector, for example.

[0110] In some implementations, the setting pins 226 of the activation lock (see Figures 6A and 6B) can be adapted to withstand 1400 Ibf each prior to breaking. Therefore, in an assembly provided with four (4) setting pins, the activation pressure threshold should generate a shifting force on corresponding piston surfaces equal to or greater than 5600 Ibf (i.e., 4x1400 Ibf). For example, the activation pressure threshold can be between 1500 psi and 2500 psi. It should be noted that, in order to prevent undesired, accidental and / or premature operation of the release assembly, the release pressure threshold has to be at least greater than the activation pressure threshold. The release pressure threshold can be greater than the activation pressure threshold by increasing the number of fasteners connecting the inner sleeve to the release sleeve, by providing fasteners configured to withstand greater forces and / or by providing piston surfaces shaped and configured to generate lower axial forces.

[0111] In this implementation, the breakable connector 328 connecting the inner sleeve to the release mandrel is adapted to withstand 1400 Ibf (e.g., is the substantially identical to the setting pin). The release assembly 300 can include any suitable number of breakable connectors 328 to maintain the inner sleeve connected during hydraulic operation of the activation mechanism, for example. In this implementation, the release assembly 300 includes ten (10) breakable connectors 328, such that the release pressure threshold should generate a shifting force on corresponding piston surfaces equal to or greater than 14,000 Ibf (i.e., 10x1400 Ibf). For example, the release pressure threshold can be between 3000 psi and 4000 psi. In order to prevent accidental and / or premature collapse of the limiter, the shear screws connecting the activation sleeve to the release mandrel (i.e., the shear screws of the limiter) can be adapted to withstand a shifting force at least greater than 14,000 Ibf. For example, the assembly can be provided with twelve (12) shear screws 232A, each configured to withstand 1400 Ibf. Therefore, the fluid pressure required to break the shear screws 232A should be sufficient to generate a shifting force equal to or greater than 16,800 Ibf (12x1400 Ibf).

[0112] The piston assembly 210 can include an outer piston, defined by surfaces of the activation sleeve, and an inner piston, defined by surfaces of the inner sleeve. Itshould be understood that the surfaces defining the pistons have a radial component, i.e., are not parallel to the longitudinal axis of the liner hanger assembly 10, to enable the fluid pressure to generate a shifting force to move the corresponding sleeve downhole. In some implementation, the fluid pressure required to activate the liner hanger assembly (e.g., the activation pressure threshold) acts upon the surfaces of the outer piston, whereas the fluid pressure required to initiate the release sequence (e.g., the release pressure threshold) acts upon the surfaces of the inner piston. It is noted that the fluid pressure along the liner hanger assembly acts upon the surfaces of both pistons simultaneously. However, the force generated on the inner piston during operation of the activation mechanism is insufficient to break the breakable connectors 328 and shift the inner sleeve, and the force generated on the outer piston during the initial step of the release sequence is insufficient to break the shear screws 232A and shift the activation sleeve further downhole.

[0113] Once the release sequence has been initiated and the load connector has engaged the load shoulder, it is noted that the activation sleeve and the inner sleeve are both retained by the shear screws 232A of the limiter 230 (see Figures 10A and 10B). The fluid pressure therefore generates a cumulative shifting force on the outer piston and the inner piston since both pistons are retained by the same shear screws 232A. Therefore, while the force required to collapse the limiter (e.g., 16,800 Ibf in the example above) is greater than the force required to initiate the release sequence (e.g., 14,000 Ibf in the example above), the required fluid pressure can be only slightly greater or even lower than the release pressure threshold since the piston area is larger (Force = psi x Area of Piston). In other words, the piston area of the outer piston and the piston area of the inner piston are added together for calculating the shifting force acting on the shear screws 232A. For example, in the example above, the fluid pressure required to break the shear screws 232A can be between 2500 psi and 3500 psi.

[0114] The described example implementations are to be considered in all respects as being only illustrative and not restrictive. For example, various components of the liner hanger assembly are tubular, such as the housing, the tool body, the sleeves (e.g., activation sleeve, inner sleeve, release sleeve), etc. Therefore, the components and features described herein and cooperating with these tubular components can berepeated about the circumference of the corresponding component. For example, the actuation mechanism can include six (6) slips provided at regular intervals about the liner mandrel. It should be appreciated that the repeated features can be repeated any suitable number of times, and can be provided at regular and / or irregular intervals.

[0115] It will be appreciated from the foregoing disclosure that there is provided various implementations of a hydraulically activatable and mechanically operable liner hanger. The liner hanger can therefore correspond to a hybrid-set hanger, with a corresponding running tool having a hydraulically operable release assembly. It is noted that, by adopting a hybrid-set hanger, a slip piston chamber can be avoided, enabling thicker wall thicknesses and a higher pressure rating of the overall system. It is also noted that, prior to activation, the running tool prevents the slips from setting until 1) the desired depth is reached; 2) a ball is dropped; 3) the activation mechanism is hydraulically operated; and 4) the actuation mechanism is mechanically operated.

[0116] Once the liner hanger is set, additional downhole operations can be conducted. For example, isolation devices (e.g., packers) can be deployed and set, cementing operations can be done, etc. Once disconnected form the liner hanger and retrieved, the running tool can be used to perform some of these (or other) downhole operations. For example, the running tool can be configured to re-engage the wellbore string proximate the packer (e.g., the liner top packer) for enabling mechanical actuation thereof, among other possibilities. The running tool can include additional portions or subassemblies configured to engage with components proximate the packer to set the packer. The packer can be set by the running during retrieval operations of the running tool (e.g., during uphole movement of the running tool), or via a secondary downhole deployment of the running tool. Once the packer is set, in some implementations, the running tool can be completely retrieved and removed from the wellbore.

[0117] In the present disclosure, an implementation is an example or embodiment of the liner hanger assembly. The various appearances of “one implementation,” “an implementation” or “some implementations” do not necessarily all refer to the same implementations. Although various features may be described in the context of a single implementation, the features may also be provided separately or in any suitable combination. Conversely, although the liner hanger assembly may be described herein in the context of separate implementations for clarity, it may also be embodied in asingle implementation. Reference in the specification to “some implementations”, “an implementation”, “one implementation”, or “other implementations”, means that a particular feature, structure, or characteristic described in connection with the implementations is included in at least some implementations, but not necessarily in all implementations.

[0118] As used herein, the terms “coupled”, “coupling”, “attached”, ’’connected” or variants thereof as used herein can have several different meanings depending in the context in which these terms are used. For example, the terms coupled, coupling, connected or attached can have a mechanical connotation. For example, as used herein, the terms coupled, coupling or attached can indicate that two elements or devices are directly connected to one another or connected to one another through one or more intermediate elements or devices via a mechanical element depending on the particular context.

[0119] Similarly, positional descriptions such as “top”, “bottom”, “above”, “under”, “below”, “left”, “right”, “front”, “rear”, “parallel”, “perpendicular”, “transverse”, “inner”, “outer”, “internal”, “external”, and the like should, unless otherwise indicated, be taken in the context of the figures and should not be considered limiting.

[0120] In the above description, the same numerical references refer to similar elements. Furthermore, for the sake of simplicity and clarity, namely so as to not unduly burden the figures with several references numbers, not all figures contain references to all the components and features, and references to some components and features may be found in only one figure, and components and features of the present disclosure which are illustrated in other figures can be easily inferred therefrom. The implementations, geometrical configurations, materials mentioned and / or dimensions shown in the figures are optional, and are given for exemplification purposes only.

[0121] In addition, although the optional configurations as described herein and illustrated in the accompanying drawings comprises various components and although the optional configurations of the liner hanger assembly may consist of certain geometrical configurations as explained and illustrated herein, not all of these components and geometries are essential and thus should not be taken in theirrestrictive sense, i.e. should not be taken as to limit the scope of the present disclosure. It is to be understood that other suitable components and cooperations thereinbetween, as well as other suitable geometrical configurations may be used for the implementation and use of the liner hanger assembly, and corresponding parts, as briefly explained and as can be easily inferred herefrom, without departing from the scope of the disclosure.

Claims

CLAIMS1. A liner hanger assembly for hanging a liner from a casing string down a wellbore, the liner hanger assembly comprising : a liner hanger comprising a housing and an actuation mechanism provided with slips operatively coupled to the housing, the actuation mechanism being mechanically operable between an unset configuration, where the slips are in a retracted state and spaced from the casing string, and a set configuration, where the slips in an extended state and engage the casing string to set the liner, the actuation mechanism comprising an actuation lock adapted to operate the actuation mechanism between a locked configuration, where mechanical operation of the actuation mechanism is prevented, and an unlocked configuration, where mechanical operation of the actuation mechanism is enabled; a running tool comprising a tool body releasably coupled to the housing and an activation mechanism hydraulically operable to cooperate with the actuation lock to enable unlocking the actuation mechanism, wherein prior to hydraulically operating the activation mechanism, the actuation mechanism is in the locked configuration.

2. The liner hanger assembly of claim 1 , wherein mechanical operation of the actuation mechanism includes shifting the housing of the liner hanger along the wellbore via the running tool, and wherein the actuation mechanism comprises a slip actuator operatively coupled to the slips to prevent movement of the slips along the wellbore during mechanical operation of the actuation mechanism.

3. The liner hanger assembly of claim 2, wherein the housing comprises slip slots shaped and sized to receive respective slips therein and comprising angled surfaces, and wherein the slip actuator comprises a retaining element configured to at least partially restrict downhole movement of the slips by engaging the casing string.

4. The liner hanger assembly of claim 2 or 3, wherein the actuation lock comprises a lock pin, and wherein when the locked configuration, the lock pin secures the housing to the slip actuator to prevent relative movement therebetween, and, when in the unlocked configuration, the lock pin releases the slip actuator such that : relative movement between the housing and the slip actuator and between the housing and the slips is enabled; and shifting the housing along the wellbore urges the slips outwardly and into the extended state.

5. The liner hanger assembly of claim 4, wherein the lock pin extends through the housing and engages the slip actuator to lock the actuation mechanism, and wherein the lock pin is adapted to retract into the housing to disengage the slip actuator and unlock the actuation mechanism.

6. The liner hanger assembly of claim 5, wherein the activation mechanism comprises a lock engager having a support base adapted to support the lock pin to prevent retraction of the lock pin and prevent unlocking the actuation mechanism.

7. The liner hanger assembly of claim 6, wherein the activation mechanism comprises an activation piston coupled to the lock engager and hydraulically operable to shift the support base such that the lock pin becomes unsupported and allowed to retract to unlock the actuation mechanism.

8. The liner hanger assembly of claim 7, wherein the activation mechanism comprises an activation sleeve releasably secured to the housing, the activation sleeve comprising the lock engager proximate a downhole end thereof and one or more piston surfaces defining the activation piston, and wherein hydraulically operating the activation piston releases the activation sleeve from the housing and shifts the activation sleeve along the housing.

9. The liner hanger assembly of any one of claims 1 to 8, further comprising a release assembly hydraulically operable to release the tool body from the housing to enable retrieval of the running tool.

10. A method of operating a liner hanger assembly for hanging a liner from a casing string down a wellbore, the method comprising : hydraulically operating an activation mechanism to unlock an actuation mechanism of a liner hanger comprising slips and enable engaging the slips with the casing string; mechanically operating the actuation mechanism via displacement of a running tool for engaging the slips with the casing string, where mechanical operation of the actuation mechanism is prevented prior to hydraulic operation of the activation mechanism.

11. The method of claim 10, wherein the activation mechanism is part of the running tool and includes an activation piston.

12. The method of claim 10 or 11 , further comprising, after mechanical operation of the actuation mechanism, hydraulically operating a release assembly to disconnect the running tool from the liner hanger, and retrieving the running tool from the wellbore.

13. The method of claim 12, wherein hydraulic operation of at least one of the activation mechanism and the release assembly includes dropping a ball from surface to occlude internal passages of the running tool and increasing a fluid pressure along the liner hanger assembly.

14. The method of claim 13, wherein the release assembly is part of the running tool and includes a release piston.

15. The method of claim 14, wherein hydraulic operation of the release assembly includes a release sequence initiated by hydraulic operation of the release piston, and wherein the fluid pressure required to initiate the release sequence is greater than the fluid pressure required to hydraulically operate the activation piston.

16. The method of claim 15, wherein, during the release sequence, the activation piston and the release piston cooperate to provide a combined piston area and increase an amount of force generated.

17. A completion method for a wellbore provided with a casing string section, comprising : running a liner hanger comprising a liner downhole via a running tool and to a desired depth; hydraulically operating an activation mechanism to unlock an actuation mechanism of the liner hanger comprising slips and enable engaging the slips with the casing string section; mechanically operating the actuation mechanism via displacement of the running tool for engaging the slips with the casing string section and setting the liner, where mechanical operation of the actuation mechanism is prevented prior to hydraulic operation of the activation mechanism; and cementing the liner along the wellbore.

18. The method of claim 17, further comprising, prior to cementing the liner : hydraulically operating a release assembly to disconnect the running tool from the liner hanger; and retrieving the running tool from the wellbore.

19. The method of claim 18, further comprising, following the cementing of the liner, setting a liner top packer provided uphole of the liner hanger.

20. The method of claim 19, wherein setting the liner top packer is done via the running tool during the retrieval of the running tool from the wellbore.

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