Systems and methods for installation and / or tensioning of casing

Abstract

A system and method for installing and tensioning casing (230) in a well are disclosed. A lower end of the casing (230) is secured within the well, after which a tensile load is applied at the upper end to tension the casing. While under tension, the upper end is axially locked by a locking mechanism (240) comprising radially movable locking members (250) with engaging profiles (241, 242) configured to mate with corresponding profiles on the casing. The locking mechanism may include tapered surfaces and / or threaded actuating components to translate axial or rotational input into radial movement. The system mitigates thermally induced compressive failure in high-temperature wells and is applicable to geothermal, hydrocarbon, and other energy-production wells. Associated casings, wellheads, and methods of energy extraction and power generation using the tensioned system are also provided.

Description

TITLE

[0001] “Systems and methods for installation and / or tensioning of casing”FIELD OF THE INVENTION

[0002] The present invention relates to systems and methods for installation and / or tensioning of casing, and specifically to systems and methods for installation and / or tensioning of casing in geothermal wells and / or in other wells such as hydrocarbon wells.BACKGROUND OF THE INVENTION

[0003] General methods of installing wellheads and casing involve first drilling a wellbore, before inserting a casing pipe into the wellbore. The casing prevents the well from collapsing and shields the well from external contaminants. Casing also serves to isolate different geological formations, preventing fluid mixing and maintains the overall well integrity. Once casing is positioned, cement can be pumped down the casing and circulated up between the casing and the borehole wall such that cement is circulated from the shoe of the casing to surface. This cementing process secures the casing, seals off potential contamination areas, and provides structural reinforcement to the wellbore. The wellhead, containing valves, fittings, and controls for monitoring and managing well operations such as pressure and temperature, can then be installed atop the casing. Multiple casings can be provided by repeating said steps of drilling; inserting and positioning the casing pipe; and cementing. With the casing(s) installed, the well can be finalized by installing additional equipment like pumps or extraction devices specific to the geothermal recovery or hydrocarbon production system.

[0004] There are a number of problems with this method. One of most significant disadvantages of this method is the cost of cementing. However, as noted above, current methods require the cement for securing the casing, sealing off potential contamination areas, and providing structural reinforcement to the wellbore.

[0005] This is a particularly key issue in the field of geothermal energy extraction, where present operational costs involved in geothermal energy extraction are preventing the widespread use of geothermal energy from being an economically viable solution for the future. An example of a geothermal system 1 is shown in Fig.l. The system 1 shown in the example is aclosed-loop geothermal system. This geothermal system works by circulating a heat transfer fluid such as water through a closed loop of pipes within the system. The primary function of the system is to extract the earth's natural heat in order to provide energy for a number of applications. There are typically very large temperature differentials within the system 1, particularly where the heated heat transfer fluid e.g. water reaches the surface. These large temperature differentials can put significant strain on the materials used in the system (e.g. for the piping, wellheads, cementing), gradually leading to pipe fatigue, for instance, due to expansion and contraction of the pipes in the system; leading to leaks, cracks, or even pipe ruptures. In particular, thermally induced forces can lead to compressive failure (e.g. during the production of high temperature formation fluids), leading to production downtime and expensive repairs. It is envisaged that embodiments of the present invention will be particularly beneficial for use in relatively hotter geothermal wells such as advanced geothermal system (AGS) but would also be beneficial in all other types of geothermal wells, such as (but not limited to) those specified in the IADC Geothermal Well Classification guide (the whole contents of which are incorporated herein by reference) (as may be amended in the future) but which is currently available at https: / / iadc.org / drillbits / iadc-geothermal-well-classification-now-available / and which lists the various types of geothermal well that are currently classified as hydrothermal, low enthalpy, high enthalpy, enhanced geothermal systems (EGS), advanced geothermal system (AGS), hot dry rock (HDR), hot sedimentary aquifers (HSA), closed loop geothermal systems (CLGS), advanced closed loop (ACL), and underground thermal energy storage (UTES).

[0006] It is an objective of this present invention to provide a means which seeks to overcome or at least mitigate some, most or all of the above problems.STATEMENTS OF THE INVENTION

[0007] According to a first aspect in accordance with the present invention, there is provided a method of tensioning a casing, the method comprising the steps of:a. securing a lower end of a casing within a well;b. tensioning the casing by applying a tensile load to the casing via an upper end of the casing; andc. axially securing the upper end of the casing, whilst the casing is tensioned, by moving one or more engaging profiles provided on at least one radially moveable locking member into engagement with one or more corresponding engaging profiles providedon the outer surface at the upper end of the casing, to thereby lock the tensioned casing within the well.

[0008] According to a second aspect in accordance with the present invention, there is provided a casing for a borehole, the casing comprising an upper end and a lower end, the upper end of the casing having an attachment means for attachment to a tension pulling means, and wherein the lower end of the casing is securable within the well, and wherein the upper end of the casing further comprises a locking means for attachment to a locking mechanism to permit the upper end of the casing to be locked within a borehole in a tensioned state, wherein the locking means comprises one or more engaging profdes provided on the outer surface at the upper end of the casing, wherein the said one or more engaging profdes provided on the outer surface at the upper end of the casing corresponds to one or more engagement profdes formed on a contact surface of a radially moveable locking member of the locking mechanism.

[0009] According to a third aspect in accordance with the present invention, there is provided a tensioning system, the system comprising:a casing, said casing comprising:an upper end,a lower end securable within a well,an attachment means at an upper end thereof for permitting attachment of a tension pulling means, anda locking means at an upper end thereof for attachment to a locking mechanism, wherein the locking means comprises one or more engaging profdes provided on the outer surface at the upper end of the casing;a tension pulling means attachable to said attachment means of the casing and configured to apply a tensile load to the casing via said upper end thereof; anda locking mechanism configured to selectively lock against said locking means of the casing such that the axial position of the upper end of the casing is locked in place, wherein said locking mechanism includes at least one radially moveable locking member having one or more engaging profdes, which correspond to the one or more engaging profdes of the locking means, andwherein the one or more engaging profdes of the at least one radially moveable locking member is / are configured to be selectively movable into engagement with said one or more corresponding engaging profdes of the locking means.

[0010] According to a fourth aspect in accordance with the present invention, there is provided an apparatus for locking tension into a tensioned casing, the apparatus comprising:a. a radially moveable locking member comprising a contact surface having one or more engaging profdes formed thereon;b. wherein the one or more engaging profiles formed on the contact surface of the radially moveable locking member corresponds to one or more engagement profiles of a locking means provided on the outer surface at the upper end of the casing.

[0011] Optionally, the one or more engaging profiles formed on the contact surface of the radially moveable locking dog comprise one or more circumferentially extending formations and more preferably comprise one or more annular projections and / or grooves. Further optionally, the one or more engaging profiles formed on the contact surface of the casing comprise one or more circumferentially extending formations and more preferably comprise one or more annular projections and / or grooves.

[0012] Typically, the method further comprises the step of securing a lower end of a second casing within a well. Optionally, the method further comprises the step of tensioning the second casing by applying a tensile load to the second casing via an upper end of the second casing. Optionally, the method further comprises the step of securing the upper end of the second casing whilst the second casing is tensioned to lock the tensioned second casing.

[0013] Optionally, the method further comprises the step of drilling a hole for a first casing. Optionally, the method further comprises the step of attaching a first casing head to a first casing body, optionally via a connector. Optionally, the method further comprises the step of inserting the first casing into the wellbore. Optionally, the method further comprises the step of securing the outer surface of the length of the first casing in place within the wellbore. Optionally, the method further comprises the step of cementing a lower portion of the length of the first casing in place and preferably comprises the step of cementing a lower portion of the outer surface of the length of the first casing in place. Optionally, the method further comprises the step of attaching a tension pulling tool to the first casing and preferably comprises the step of attaching a tension pulling tool to the upper end of the first casing. Optionally, the method further comprises the step of lifting the tension pulling tool to thereby apply tension to the first casing. Optionally, the method further comprises the step of activatinga locking mechanism to axially secure the tensioned first casing and preferably comprises the step of activating the locking mechanism to axially secure the tensioned first casing at or towards the upper end thereof. Optionally, the method further comprises the step of removing the tension pulling tool from the first casing preferably after the locking mechanism has axially secured the tensioned first casing at or towards the upper end thereof.

[0014] Optionally, the method further comprises the step of drilling a hole for second casing. Optionally, the method further comprises the step of attaching a second casing head to a second casing body, optionally via a connector. Optionally, the method further comprises the step of inserting the second casing into the wellbore. Optionally, the method further comprises the step of securing the outer surface of the length of the second casing in place within the wellbore . Optionally, the method further comprises the step of cementing a lower portion of the length of the second casing in place and preferably comprises the step of cementing a lower portion of the outer surface of the length of the second casing in place. Optionally, the method further comprises the step of attaching a tension pulling tool to the second casing and preferably comprises the step of attaching a tension pulling tool to the upper end of the second casing. Optionally, the method further comprises the step of lifting the tension pulling tool to thereby apply tension to the second casing. Optionally, the method further comprises the step of activating a locking mechanism to axially secure the tensioned second casing and preferably comprises the step of activating the locking mechanism to axially secure the tensioned second casing at or towards the upper end thereof. Optionally, the method further comprises the step of removing the tension pulling tool from the second casing preferably after the locking mechanism has axially secured the tensioned second casing at or towards the upper end thereof.

[0015] Optionally, the method further comprises the step of drilling a hole for third casing. Optionally, the method further comprises the step of attaching a third casing head to a third casing body, optionally via a connector. Optionally, the method further comprises the step of inserting the third casing into the wellbore. Optionally, the method further comprises the step of securing the outer surface of the length of the third casing in place within the wellbore. Optionally, the method further comprises the step of cementing a lower portion of the length of the third casing in place and preferably comprises the step of cementing a lower portion of the outer surface of the length of the third casing in place. Optionally, the method further comprises the step of attaching a tension pulling tool to the third casing and preferably comprises the step of attaching a tension pulling tool to the upper end of the third casing. Optionally, the method further comprises the step of lifting the tension pulling tool to therebyapply tension to the third casing. Optionally, the method further comprises the step of activating a locking mechanism to axially secure the tensioned third casing and preferably comprises the step of activating the locking mechanism to axially secure the tensioned third casing at or towards the upper end thereof. Optionally, the method further comprises the step of removing the tension pulling tool from the third casing preferably after the locking mechanism has axially secured the tensioned third casing at or towards the upper end thereof.

[0016] Optionally, the casing comprises a casing head portion and a casing body portion. Optionally, a lower end of the head portion is connected to an upper end of the body portion to form the casing.

[0017] Optionally, the system comprises a pipe connector means.

[0018] Optionally, the lower end of the head portion is connected to the upper end of the body portion via the pipe connector means. Optionally, an upper end of the body portion includes a frustoconical outer peripheral surface. Optionally, a lower end of the head portion includes frustoconical inner peripheral surface. Optionally, said frustoconical outer peripheral surface corresponds to said frustoconical inner peripheral surface. Optionally, said frustoconical inner and outer peripheral surface are configured to engage telescopically with one another, optionally such that they overlie one another when the upper end of the body portion is inserted into the lower end of the head portion.

[0019] Optionally, one of the frustoconical outer peripheral surface (of the upper end of the body portion) and the frustoconical inner peripheral surface (of the lower end of the head portion) comprises axially spaced circumferentially extending grooves in its frustoconical surface; whilst the other optionally comprises corresponding axially spaced circumferentially extending annular projections or teeth in its frustoconical surface. Optionally, said circumferential grooves and corresponding teeth are configured to resist axial forces and ensure metal -to-metal contact. Optionally, a radial passage is provided communicating with an axially extending recess intersecting at least some of the grooves centrally of the groove region. Optionally, the passage may be adapted for connection to a source of liquid.

[0020] Optionally, the step of installing the lower end of the head portion to the upper end of the body portion, includes pushing the upper end of the body (optionally telescopically) intothe lower the end of the head portion, optionally until metal-to-metal contact is obtained between parts of the frustoconical surfaces.

[0021] Optionally, the conicity and the tooth and groove lengths of the pin and box members are arranged so that initial metal-to-metal contact is obtained between the crest surface of each tooth.

[0022] Optionally, the step of installing the lower end of the head portion to the upper end of the body portion, includes, once metal-to-metal contact has been made, applying an axial force between the head portion and the body portion to progressively bring them together and engage the teeth in the respective grooves, until such point as the teeth along the peripheral surfaces of the head and body portion of the casing begin to mesh.

[0023] Optionally, the step of installing the lower end of the head portion to the upper end of the body portion, includes, injecting pressurised hydraulic fluid into the coupling (i.e. between the head and body portion) through one or more inlet ports. Optionally, the fluid is injected between the respective peripheral surfaces which expands the head portion and or contracts the body portion to thereby allow the body portion to be fully pushed into the head portion. Optionally, the step of installing the lower end of the head portion to the upper end of the body portion further includes, releasing the pressure such that the head portion contracts around the body portion and such that the annular teeth of the body portion are fully engaged in the annular grooves of the head portion and the annular teeth of the head portion are fully engaged in the annular grooves of the body portion. Advantageously, the wedging action of the teeth converts radial preload of the coupling into an extremely high axial preload that maintains coupling stiffness and enhances axial and bending fatigue characteristics.

[0024] Optionally, the system comprises a tensioning tool connection means. Optionally, an upper end of the casing comprises a tensioning tool connection means to permit connection to a tensioning pull tool (to enable application of a tensile force to the casing during the tension applying process). Optionally, an uppermost portion of the outer surface of the casing comprises an outer threaded profde defining a tensioning attachment profile. Optionally, said tensioning attachment profile is configured to permit connection to a tensioning pull tool having a corresponding inner threaded profile for engaging said first threaded profile during application of a tensile force to the casing.

[0025] Optionally, the casing is tensioned by applying a tensile load to the casing via an upper end thereof. Optionally, a tension pulling tool is used to connect to the upper end of the casing (optionally via tensioning attachment profde) and to apply a tensile force thereto. Optionally, the tension pulling tool is configured to connect with a standard drill string. Advantageously, this enables the application of said tensile force by lifting the drill string in an upwards direction to enable application of tensile force to the casing during the tension applying process.

[0026] Optionally, the system comprises a wellhead. Optionally, the wellhead includes axially adjacent sections. Optionally, said axially adjacent sections comprise at least one set of an upper section of wellhead, and a lower section of wellhead.

[0027] Optionally, the system further comprises a clamping arrangement configured to secure axially adjacent sections of wellheads together. Optionally, the clamping arrangement comprises a profiled outer surface provided on at least one of the upper section of the wellhead or the lower section of the wellhead. Optionally, a set of radially movable clamping dogs are provided within (e.g. housed within) the other of the at least one of the upper section of the wellhead or the lower section of the wellhead. Optionally, the radially movable clamping dogs are configured to engage with and clamp against said profiled outer surface. Optionally, the radially movable clamping dogs are provided in a circumferential arrangement. Optionally, the profiled outer surface is defined by at least one circumferentially extending groove. Optionally, the radially movable clamping dogs are provided with at least one corresponding circumferentially extending projections on a surface thereof. Optionally, the circumferentially extending projections of each clamping dog are configured to contract around the (or each corresponding) circumferentially extending groove (of the profiled surface) such that the annular projections of the radially movable clamping dogs fully engage with the annular grooves thereby clamping the axially adjacent sections of the wellhead together. Optionally, the radially movable clamping dogs are aligned such that they share a central axis, the central axis projecting through the centre of the circumferentially extending groove(s) (of the profiled surface), thus allowing each of the radially movable clamping dogs to radially move and impinge upon the circumferentially extending groove(s) (of the profiled surface) equally. Optionally, the clamping arrangement further comprises a threaded configuration configured to translate the rotational movement of the radially movable clamping dogs into radial movement of the of the radially movable clamping dogs. In such embodiments, radially movable clamping dogs may comprise a threaded profile on an outer surface thereof (and / or may instead be radially connected to a component having said threaded profile on an outersurface thereof), and a section of the wellhead (i.e. said at least one of the upper or lower section of the wellhead housing the radially movable clamping dogs therein) may include a threaded profde corresponding to said threaded profile of the clamping dogs. Advantageously, embodiments of the present invention having this combination of the threaded configuration (which allows the rotational movement of the clamping dog to be translated into radial movement of the clamping dog), enable a single rotational motion of the or each respective clamping dog to move the clamping dog from the retracted and disengaged configuration to the engaged and locked configuration.

[0028] Optionally, the one or more engaging profiles of the at least one radially moveable locking member includes a set of circumferentially extending annular projections (typically in the form of teeth). Optionally, the one or more engaging profiles on the outer surface at the upper end of the casing includes a corresponding set of circumferentially extending grooves. Optionally, the circumferentially extending annular projections are provided on one of the casings and the wellhead (or optionally provided on any intermediate components securable thereon and / or therebetween), and optionally the corresponding circumferentially extending grooves are provided on the other. Optionally, the circumferentially extending annular projections (or teeth) are configured to move into engagement with the corresponding circumferentially extending grooves during the locking process to axially lock the casing relative to the surface (optionally via the wellhead therebetween) after the casing has been tensioned (and is being held in tensioned, waiting to be locked).

[0029] Preferably a lower portion of the outer surface of the head portion (of the casing) comprises the one or more engaging profiles on the outer surface at the upper end of the casing (which may optionally be axially spaced circumferentially extending grooves). Optionally, the axially spaced circumferentially extending annular projections (which may be teeth) are provided on radially moveable locking members such as locking dogs. Optionally, the radially moveable locking members (and the circumferentially extending annular projections or grooves provided thereon) are configured to move into engagement with said lower portion of the casing (via the circumferentially extending projections or grooves thereon) during the locking process to thereby axially lock the casing in place. Advantageously, embodiments of the present invention having such arrangements of corresponding sets of circumferentially extending annular projections and grooves, provides the ability for the locking mechanism to retract and disengage the casing, for example so that the casing can be re-tensioned after a duration. Optionally, the corresponding sets of circumferentially extending annular projectionsand grooves may be configured such that they allow a certain amount of controlled slipping. Advantageously, such controlled slipping is beneficial to the system as it enables the locking mechanism to retain sealing and tension even in circumstances where there are minor movements within the system. In contrast, alternative systems not having such a controlled slipping arrangement would be required to be shut in and rectified (e.g. via cutting and welding of casing pipe sections as a result of loss of sealing). Moreover, the provision of the upper ends / portions of the casings (which may in preferred embodiments may be inner casings) not being directly secured to the surrounding formation (e.g. via cement) provides the ability for the conductor / casing to be re -tensioned.

[0030] Optionally, the locking mechanism includes an actuating sleeve member for contacting, axially moving and thereby radially moving the radially movable locking members into engagement with the outer surface of the casing. Optionally, the actuating sleeve is aligned with the radially moveable locking members such that they share a central axis (optionally projecting through the centre of the circumferential arrangement of radially moveable locking members and the actuating sleeve, thus allowing the actuating sleeve to axially move and impinge upon each of the radially moveable locking members equally).

[0031] Optionally, an inner surface of the wellhead housing may include a tapered surface. Optionally, the radially moveable locking members may comprise tapered face(s), which correspond with said tapered face of the inner surface of the wellhead housing. Optionally, the or each of the tapered faces of the radially moveable locking members taper from a first dimension (which is preferably a diameter) to a second dimension (which is preferably a diameter) thereof optionally such that in use the tapered face of the radially moveable locking member engages and pushes against the corresponding tapered face of the inner surface of the wellhead. Advantageously, the use of this tapered face ( / interface) allows the axial movement of the actuating sleeve to be translated into radial movement of the radially moveable locking members. This allows one motion of the actuating sleeve to move the radially moveable locking members from the retracted and disengaged configuration to the engaged and locked configuration. It further provides the advantage of allowing a smooth transition between these two configurations, which is desirable so as not to overly stress any of the materials which form the component parts of the locking mechanism (or the wellhead and casing system for that matter).

[0032] Optionally, the locking mechanism may further comprise a screw thread configuration configured to translate the rotational movement of the actuating sleeve into axial movement of the actuating sleeve (and radial movement and locking of the radially moveable locking members thereafter). In such embodiments, the sleeve member may comprise a threaded profile on an outer surface thereof, and a portion of the inner surface of the wellhead may include a threaded profile corresponding to said threaded profile on the outer surface of the sleeve member Advantageously, embodiments of the present invention having the combination of the screw thread configuration (which allows the rotational movement of the actuating sleeve to be translated into axial movement of the actuating sleeve), along with the tapered faces (which allow the axial movement of the actuating sleeve to be translated into radial movement of the radially moveable locking dogs), enables a single rotational motion of the actuating sleeve to move the locking members from the retracted and disengaged configuration to the engaged and locked configuration It provides the advantage of providing an even smoother transition between these two configurations (i.e. compared to embodiments having only the tapered face, and not the screw thread configuration).

[0033] Optionally, the locking mechanism may instead include a latch mechanism, which may optionally be hydraulically or electric motor operated, automatically operated or manually operated. Optionally, said latch mechanism may include radially movable activating members which are configured for contacting and radially moving the radially moveable locking members into engagement with the outer surface of the casing. Optionally, the latch mechanism is configured such that radial movement of the radially movable activating members causes corresponding radial movement of the radially moveable locking members.

[0034] Optionally, the radially movable activating members may directly engage with the radially moveable locking members. Alternatively, the radially movable activating members may engage with the radially moveable locking members via an intermediate retaining mechanism provided between the radially movable activating members and the respective radially moveable locking members. Optionally, the intermediate retaining mechanism is a pack off member. Optionally, the intermediate retaining mechanism is configured to serve the purpose of retaining the radially moveable locking members in a first position in which the radially moveable locking members are in a radially retracted position such that the engaging profiles (i.e., the engagement profile of the radially moveable locking members and the corresponding engaging profiles provided on the outer surface at the upper end of the casing) are spaced apart from one another; and therefore such that, when the radially moveable lockingmembers are in the said first position, axial movement of the upper end of the casing is not inhibited by the radially moveable locking members (i.e., the upper end of the casing can move axially with respect to the radially moveable locking members).

[0035] Optionally, an outer surface(s) of the intermediate retaining mechanism is configured to engage with complementary inner surfaces of the radially moveable locking members. Preferably, with the radially moveable locking members in the said first position and the intermediate retaining mechanism radially retracted (i.e., and in its configuration for retaining the radially moveable locking members in the said first position), a retaining engagement is provided between the radially moveable locking members and the intermediate retaining mechanism. During said retaining engagement, the outer surface(s) of the intermediate retaining mechanism and the complementary inner surfaces of the radially moveable locking members are preferably configured to substantially or fully engage with one another, such that said respective surfaces are engaged substantially or fully in continuous secure contact over substantially the entire extent of their complementary engagement surfaces. Preferably, when the radially moveable locking members are in the first position (i.e., their radially retracted position) and the intermediate retaining mechanism is also in a first position (i.e., in which it is also in a radially retracted position from the casing), radial movement (and typically also axial movement) of the radially moveable locking members is restricted by the intermediate retaining mechanism via the engagement (and preferably the substantial or full engagement) of said complimentary inner and outer surfaces (which effectively acts to retain the radially moveable locking members in their radially retracted position, until such stage that they are required to move radially inwards to lock the tensioned casing in place), whilst the tapered surfaces additionally acts to restrict relative axial movement of the radially moveable locking members.

[0036] At the stage when the radially moveable locking members are required to move radially inwards to lock the tensioned casing in place, the radially movable activating members are typically moved radially inwards causing the intermediate retaining mechanism to correspondingly move radially inwards. Preferably, as the intermediate retaining mechanism gradually moves radially inwards, the radially moveable locking members gradually in turn move radially inwards, whilst also gradually moving in an axially downwards direction; due to i) the reduced retention of the radially moveable locking members inhibited by the radially inwards movement of the intermediate retaining mechanism, which in turn permits at least partial axial movement of the radially moveable locking members, and ii) gravity which causes the radially moveable locking members to move downwards as the tapered surfaces thereofslides along the tapered surface of the inner surface of the wellhead. Optionally, such downward movement causes the respective surfaces to be gradually moved from their substantial or full engagement (with one another) to a partial engagement, in which at least a lower portion of the outer surface(s) of the intermediate retaining mechanism is in contact with at least an upper portion of the complementary inner surfaces of the radially moveable locking members. Advantageously, maintaining at least such partial engagement throughout enables the radially moveable locking members to be selectively retractable at any stage; for example, following tensioning of the casing and locking of said tension via the radially moveable locking members, should the operator wish to remove, increase or otherwise adjust the tension, the operator can move the radially movable activating members in a radially outwards direction causing the intermediate retaining mechanism to correspondingly move radially outwards, and in doing so the intermediate retaining mechanism will typically engage the radially moveable locking members (via said at least partial engagement of the surfaces therebetween) and move the radially moveable locking members radially outwardly towards the first position, with the radially moveable locking members sufficiently retracted from the outer surface of the casing.

[0037] In response to continued radially inwards movement of the radially movable activating members, the intermediate retaining mechanism and the radially moveable locking members will preferably each continue to gradually move radially inwards, and the radially moveable locking members will also typically continue to move gradually axially downwards, until such point as the one or more engaging profiles on the at least one radially moveable locking member have moved into locking engagement with the one or more corresponding engaging profiles provided on the outer surface at the upper end of the casing Advantageously, for embodiments of the present invention having tapered surfaces, the load (e.g., the weight of the tensioned casing) is transferred directly from the casing to the wellhead via these tapered surfaces, rather than being transferred directly from the casing to the wellhead via the radially movable activating members which enables easier control of the radially movable activating members.

[0038] Optionally, radial movement of the radially movable activating members can be controlled any suitable means. Optionally, the radial movement may be hydraulically or electric motor operated or manually operated, and may additionally or otherwise include a threaded arrangement. Optionally, the radially movable activating members are circumferentially arranged around the wellhead. Optionally, each of the radially movable activating members are housed within a respective throughbore formed through a side wall of the wellhead. Optionally, the threaded arrangement is configured to translate the rotationalmovement of the radially movable activating members into radial movement of the intermediate retaining mechanism (and preferably radial movement and locking of the radially moveable locking members thereafter). Optionally, the radially movable activating members may each comprise a threaded profile on an outer surface thereof, and optionally the throughbores (i.e., housing their respective radially movable activating members therein) may each comprise a corresponding threaded profile on an inner surface thereof. The radially movable activating members are preferably connected to the intermediate retaining mechanism via a swivel type connection (not shown) that preferably permits the intermediate retaining mechanism to move radially with the radially movable activating members whilst preventing the intermediate retaining mechanism from rotating around the longitudinal axis of the radially movable activating members as the radially movable activating members rotate around their longitudinal axis.

[0039] According to a fifth aspect in accordance with the present invention, there is provided a method of extracting energy resource, comprising the steps of:a. tensioning a casing in accordance with the first aspect of the present invention; and b. extracting energy resource through the casing, and more preferably through a throughbore of the casing.

[0040] According to a sixth aspect in accordance with the present invention, there is provided a method of generating electricity, comprising the steps of:a. tensioning a casing in accordance with the first aspect of the present invention; and b. extracting energy resource in accordance with the fifth aspect of the present invention; andc. generating electricity from said extracted energy resource.

[0041] Optionally, the method includes the step of installing the casing in the well.

[0042] Optionally, the well is a well that produces fluids. Preferably, the energy resource is geothermal energy resource and the well is a geothermal well. Alternatively, the energy resource is a hydrocarbon energy resource and the well is a hydrocarbon (such as oil and or gas) production well. Further alternatively, the energy resource is water and the well is a water production well, and may be a heated water production well.

[0043] Optionally, the method includes the step of installing the casing in a well, wherein said well is optionally a geothermal well. Alternatively, the well is optionally a hydrocarbon production well.

[0044] Optionally, the method further comprises the step of re-tensioning the casing. Optionally, said step of re-tensioning the casing comprises re-tensioning the casing by applying a tensile load to the casing via an upper end of the casing; and re -securing the upper end of the casing whilst the casing is tensioned to lock the tensioned casing.

[0045] According to a seventh aspect in accordance with the present invention, there is provided a method of re-tensioning a casing comprisinga. tensioning a casing, having a lower end thereof secured within a well, by applying a tensile load to the casing via an upper end of the casing; andb. securing the upper end of the casing whilst the casing is tensioned to lock the tensioned casing.

[0046] It will be understood by the skilled person that, whilst in the embodiment described herein below, the “outer conductor 130” is installed without applying tension thereto, the term “casing” where tension is applied thereto could in certain embodiments also include such a “conductor” or “outer conductor 130” if the operator wished to apply tension to for example the “conductor” or “outer conductor 130” for any particular reason.

[0047] The accompanying drawings illustrate presently exemplary embodiments of the disclosure, and together with the general description given above and the detailed description of the embodiments given below, serve to explain, by way of example, the principles of the disclosure.

[0048] In the description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. 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. The present invention is susceptible to embodiments of different forms. Specific embodiments of the present invention are shown in the drawings, and herein will be described in detail, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention and is not intended to limit the invention tothat illustrated and described herein. 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.

[0049] The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention. Also, optional features described in relation to one embodiment can typically be combined alone or together with other features in different embodiments of the invention. Additionally, any feature disclosed in the specification can be combined alone or collectively with other features in the specification to form an invention.

[0050] Various embodiments and aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features, and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary embodiments and aspects and implementations. The invention is also capable of other and different embodiments and aspects, and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention.

[0051] Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the field relevant to the present invention.

[0052] 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. In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase "comprising", it is understood that we also contemplate the same composition, element or group of elements with transitionalphrases "consisting essentially of’, "consisting", "selected from the group of consisting of’, “including” or "is" preceding the recitation of the composition, element or group of elements and vice versa. In this disclosure, the words “typically” or “optionally” are to be understood as being intended to indicate optional or non-essential features of the invention which are present in certain examples, but which can be omitted in others without departing from the scope of the invention. The following definitions will be followed in the specification. As used herein, the term "wellbore" or “borehole” refers to a wellbore or borehole being provided or drilled in a manner known to those skilled in the art. Reference to up or down will be made for purposes of description with the terms "above", "up", "upward", "upper", or "upstream" meaning away from the bottom of the wellbore or borehole along the longitudinal axis of a work string toward the surface and "below", "down", "downward", "lower", or "downstream" meaning toward the bottom of the wellbore along the longitudinal axis of the work string and away from the surface and deeper into the well, whether the well being referred to is a conventional vertical well or a deviated well and therefore includes the typical situation where a rig is above a wellhead, and the well extends down from the wellhead into the formation, but also horizontal wells where the formation may not necessarily be below the wellhead. Similarly, ‘work string’ refers to any tubular arrangement for conveying tools from a surface into a wellbore. In the present invention, drill string is the preferred work string.

[0053] 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 described herein are understood to include plural forms thereof and vice versa.BRIEF DESCRIPTION OF THE DRAWINGS

[0054] Embodiments of the present invention will now be described, by way of example only and with reference to the accompanying drawings, in which:Fig. 1 is a block diagram of an exemplary closed loop geothermal system which may or may not be an embodiment in accordance with the present invention (depending upon the installation method thereof and / or apparatus used therein);Fig. 2 is a front sectional view of a wellhead and casing system in accordance with the present invention, showing the wellhead base, the outermost conductor and the lower wellhead housing during an initial stage of installation;Fig. 3 is a front sectional view of the wellhead and casing system during the next subsequent stage (from the stage shown in Fig. 2) of installing and tensioning an inner casing;Fig. 4 is a detailed sectional view of the stage shown in Fig. 3, showing the shoe-to-shoe cementing method in accordance with embodiments of the present invention;Fig. 5 is a detailed sectional view of the upper portion of the casing shown in Fig. 3, showing a locking mechanism in accordance with embodiments of the present invention;Fig. 6A is a front sectional view of the wellhead and casing system in accordance with embodiments of the present invention during the tensioning process, showing the point of initial engagement of a tensioning tool in the tensioning process;Fig. 6B is a front sectional view of the wellhead and casing system in accordance with embodiments of the present invention showing a stage of the tensioning process (subsequent to the initial engagement of the tensioning tool shown in Fig. 6A), and specifically showing the midway point of the tensioning process with the casing in a mid-tensioned stage;Fig. 6C is a front sectional view of the wellhead and casing system in accordance with embodiments of the present invention showing a stage of the tensioning process (subsequent to the mid-tensioned stage shown in Fig. 6B), and specifically showing the stage where the casing has been tensioned (and being held at) the desired level of tension, ready to be locked in place;Fig. 6D is a front sectional detailed view of the wellhead and casing system during the tensioning process shown in Fig. 6C, where Fig. 6D is the detailed view of section U of Fig. C, specifically showing the locking mechanism in the retracted configuration (whilst the casing is being held tensioned the desired level of tension, ready to be locked in place);Fig. 7A is a front sectional view of the wellhead and casing system in accordance with embodiments of the present invention during the tension locking stage, showing the locking mechanisms engaged with the casing thereby locking the tensioned casing in place;Fig. 7B is a detailed view of the wellhead of Fig. 7A, where Fig. 7B is the detailed view of section V of Fig. 7A, showing the locking mechanism in the locked stage in which the tensioned casing is locked in place;Fig. 7C is a front sectional view of the wellhead in accordance with embodiments of the present invention subsequent to the tension locking stages shown in Figs. 7A and 7B, showing the tensioning tooling removed from the casing and the tensioned casing locked in place;Fig. 8A is a front sectional view of the wellhead and casing system during a subsequent stage (from the stage shown in Figs. 3 to 7C) of installing and tensioning a second inner casing;Fig.8B is a detailed sectional view of the wellhead of Fig. 8A, detailing the upper portion of the casing shown in Fig. 8B;Fig. 9 is a front sectional view of the wellhead and casing system during a subsequent stage (from the stage shown in Figs. 8A and 8B) of installing a wellhead cap / top section; and Fig. 10 is a front sectional view of an installed / tensioned geothermal wellhead and casing system in accordance with embodiments of the present invention.DETAILED DESCRIPTION OF THE DRAWINGS

[0055] Figure 1 shows an example of a geothermal system 1. The geothermal system 1 shown in the example is a closed-loop geothermal system, also known as an advanced geothermal system (AGS). This geothermal system 1 works by circulating a heat transfer fluid (e.g. water or a water-based solution) through a closed loop (e.g. of under ground formation 2 and / or pipes such as casing) within the system 1. The primary function of the system 1 is to extract the earth's natural heat in order to provide energy for a number of applications. The geothermal system 1 includes a closed loop consisting of a lower lateral section 2, a first vertical section 3, a second vertical section 4, and an upper lateral section 5, which are connected to form the closed loop. The lower lateral section 2 of the geothermal loop is buried deep in the ground 7 and is where the heat transfer fluid absorbs the earth's natural heat. The lower lateral section 2 has a first end 2A and a second opposite end 2B, and extends horizontally between these ends at a depth beneath the surface 6 where the rock is hot. The lower lateral section 2 may in some circumstances be drilled out by the operator of the geothermal system 1 or more usually may be natural fissures through the ground 7 or may be a combination of the two. The lower lateral section 2 may include one or more sub-sections 2i, 2ii, 2iii within it to increase the rate of energy absorption in the lower lateral section 2. The first vertical section 3 extends substantially perpendicularly (or may in some circumstances extend at an angle) from the first end 2A of the lower lateral section 2 towards the surface, while the second vertical section 4 extends substantially perpendicularly (or may in some circumstances extend at an angle) from the second end 2B of the lower lateral section 2 towards the surface. The upper lateral section 5, typically located at or above the surface where the energy in the system 1 is extracted, extends horizontally between its first and second ends, which are connected to the first vertical section 3 and second vertical section 4, respectively, thus completing the closed loop.

[0056] In this system 1, the lower lateral section 2, located at a depth having a high temperature (typically in the region of 275 °C to > 400 °C), absorbs heat from the surrounding rock of the ground 7. In order to do so, cool fluid (e.g. water) is pumped down from the surface towards to the (sub-surface) lower lateral section 2 via means of a fluid injection pumpingmechanism in the form of a fluid or water injection Christmas tree (XT) 8A (optionally provided on a fluid injection wellhead 8) and then through the second vertical section 4 into the lower lateral section 2. As this fluid flows along the lower lateral section 2, it absorbs heat from the surrounding hot rock in the ground 7. The heat transfer fluid then travels upward through the first vertical section 3, which is positioned substantially perpendicularly (or at an angle) from the lower lateral section 2 and rises toward the surface 6. As the heat transfer fluid travels reaches the surface 6, it will arrive at a geothermal wellhead 9, where it will pass through before exiting the sub-surface section of the closed loop system.

[0057] In geothermal systems 1 the temperature of the ground 7 at or near surface level 6 is far less than that of the lower lateral section 2 of the geothermal closed loop where the fluid absorbs heat and is therefore also generally far less than the temperature of the heat transfer fluid traveling upwards to the surface and through the subsea well head. This causes large temperature differentials in the systems 1, and particularly large temperature differentials at upper portions of the piping / casings (i.e. of the first vertical section 3) carrying the heat transfer fluid, which are proximate to the geothermal wellhead 9. These large temperature differentials can cause significant expansion on the casing of the first vertical section 3 relatively quickly after the geothermal system 1 commences operation, and such expansion can put significant strain on the materials used (e.g. for the casing of the first vertical section 3 as well as the cementing therearound as well as the wellhead and other subsurface and surface piping). Gradually, this can lead to pipe fatigue, for instance, due to such expansion and contraction of the casing and / or pipes in the system 1; leading to leaks, cracks, or even casing or pipe ruptures. Once the heat transfer fluid reaches the surface at the upper lateral section 5, the energy from the high-temperature heat transfer fluid (i.e. relative to the fluid temperature of the heat transfer fluid that is pumped from the surface towards to the lower lateral section 2 via the second vertical section) is extracted. To extract energy from the fluid, the heat transfer fluid may may enter, for instance, either heat exchanger units, power generators (e.g. having turbine arrangement) and / or cooling towers, depending on the specific conditions and requirements of the system 1. The closed-loop nature of the system 1 means that the fluid circulates in a continuous cycle, with minimal loss and no exposure to contaminants, making it both environmentally friendly and cost-effective over time.

[0058] A general method of installing a wellhead and casing for a well (e .g. a geothermal well) to provide a geothermal system 1 may involve first drilling a wellbore, before inserting a reinforcing tubular pipe called a casing into the wellbore. The casing prevents the well fromcollapsing and shields the well from external contaminants. Casing also serves to isolate different geological formations, preventing fluid mixing and maintains the overall well integrity. The casing is typically installed once section or length at a time, where the first section is the upper most and has the largest diameter and any / each subsequent (lower) section is / s are progressively more narrow in diameter in order to be able to be lowered into and pass through the already installed first section of casing and also to allow the maximum diameter possible drill bit to pass therethrough to drill the next lowermost section. Once the first section of casing is positioned in the first section of drilled wellbore, cement can be pumped down the internal throughbore of the casing, out of the bottom of the throughbore of the casing and circulated back up the outside of the casing between the outer surface of the casing and the inner surface of the well or borehole wall such that cement the is circulated from the shoe (not shown but which is located on the bottom end of the casing) of the casing up to surface. This cementing process secures the casing, seals off potential contamination areas, and provides structural reinforcement to the wellbore. The wellhead, containing valves, fittings, and controls for monitoring and managing well operations such as pressure and temperature, can then be installed atop the first section of casing. Multiple casings can be provided by repeating said steps of drilling; inserting / lowering and positioning the next section of casing; and cementing until the lowermost end of the casing is in fluid communication with the respective end 2a, 2b of the lower (sub surface) lateral section 2. Two lengths of sections of said casing are completed, one of which forms the first vertical section 3 and the other of which forms the second vertical section 4. With the casing(s) installed, the well can be finalized by installing additional equipment like pumps or extraction devices specific to the geothermal system 1.

[0059] There are a number of problems with this method. One of most significant disadvantages of this method is the high cost of cementing. The costs of cementing operations further are increased in higher temperature environments; higher-cost slurries are required in higher temperature environments. However, as noted above, current methods require the cementing for securing the casing, sealing off potential contamination areas, and providing structural reinforcement to the wellbore.

[0060] An exemplary wellhead and casing system 1000 (and method thereof) in accordance with embodiments of the present invention, will now be described. In this exemplary system / method, there are four main stages that are described. These are as follows:- Stage 1, the installation of an outer conductor and a wellhead base;- Stage 2, the installation and tensioning of a first inner casing;- Stage 3, the installation and tensioning of a second inner casing; and- Stage 4, the final stage including the installation of wellhead cap / top section.

[0061] For ease of reference only, components and features references herein which may be relevant to a specific stage of the exemplary method are referenced such that is clear said components and features correspond to said step, wherever possible. Accordingly, components and features referenced herein relating specifically to the first stage are assigned reference numerals falling within the range of 100 to 199; components and features referenced herein relating specifically to the second stage are assigned reference numerals falling within the range of 200 to 299; components and features referenced herein relating specifically to the third stage are assigned reference numerals falling within the range of 300 to 399; and components and features referenced herein relating specifically to the fourth stage are assigned reference numerals falling within the range of 400 to 499. Additionally, similar components and features of each of the respective stage are indicated with the same reference numeral, but with the addition / reduction of 100, 200 or 300 (e.g. (first) inner casing 230 of Stage 2 corresponds with (second) inner casing 330 of stage 3). The skilled person will however understand that reference numerals assigned herein are not to be construed as limiting the extent of the matter protected by the claims; their sole function being to make the description, claims and drawings easier to understand. It will also be understood by the person skilled in the art that the geothermal system 1 of Figure 1 could be an embodiment in accordance with the present invention if it is installed in accordance with the method described hereinbelow. Otherwise, the person skilled in the art will understand that the geothermal system 1 of Figure 1 will be a conventional geothermal system if it is installed with hitherto conventional installation techniques in which case it will not be an embodiment in accordance with the present invention.STAGE 1 OF EXEMPLARY METHOD IN ACCORDANCE WITH EMBODIMENTS OF THE PRESENT INVENTION - INSTALLATION OF AN OUTER CONDUCTOR 130 AND A WELLHEAD BASE 110

[0062] A first stage (hereinafter referred to as “Stage 1”) of a method in accordance with embodiments of the present invention includes the installation of a first (uppermost and widest diameter) section of casing in the form of an outermost conductor 130 and a wellhead base 110. Fig. 2 is a front sectional view of a wellhead and casing system 1000 in accordance with the present invention, showing the wellhead base 110, the outermost conductor 130 and the lowerwellhead housing 120 at this initial stage of installation. For reference, in the context of the exemplary closed loop geothermal system 1 shown in Fig. 1, the wellhead and casing system 1000 (as shown in Figs. 2 to 10) may, for example, be located on the left-hand side (i.e. the first vertical section 3 which carries the heated heat transfer fluid e.g. water to the surface) of the geothermal system 1 in the block diagram of Fig. 1; with the layers or descending sections of casing forming all (or substantially all) of the first vertical section 3 (running from the upper left comer to the bottom left comer of the closed loop), and the wellhead being provided at the surface at the respective adjoining ends of the first vertical section 3 and the upper lateral section 5. Indeed, it is likely that only the casing of the first vertical section 3 need be installed in accordance with the method in accordance with embodiments of the present invention in order to benefit from the advantages that tensioning the casing (as will be described subsequently) provides in relation to avoiding the problems that expansion of said heated casing would otherwise bring. In other words, the casing of the second vertical section 4 need not be installed in accordance with the method in accordance with embodiments of the present invention because the casing of the second vertical section 4 will mainly only experience colder heat transfer fluid which therefore won’t cause the casing of the second vertical section 4 to expand nearly as much when compared to the casing of the first vertical section 3. That said, the operator of the geothermal system 1 / wellhead and casing system 1000 may decide to install the casing of the second vertical section 4 (as well as the casing of the first vertical section 3) in accordance with the embodiments of the present invention in order to benefit from the other advantages that the present invention provides such as reduction in cement required as will be explained subsequently.

[0063] The first step of Stage 1 of installing an outermost conductor 130 and a wellhead base 110 requires a borehole 101 to be drilled (by a drill bit using conventional drilling techniques) for the outermost conductor 130. The borehole 101 is typically larger in in diameter than the outermost conductor 130 (e.g. by around 4 inch [~ 100 mm]). In the example shown, the outermost conductor 130 is typically an 18 % conductor pipe (i.e. 18 % inch [~ 475 mm] outer diameter), and the borehole 101 that is drilled for the outermost conductor 130 is typically 22 Vi inch [~ 570 mm] in diameter. In an example in accordance with the present invention, the outermost conductor 130 may, for instance, have a length (i.e. typically the length between the shoe of the outermost conductor 130 and the surface 6) of approximately 480 metres. Once the borehole 101 has been drilled, the drill bit (not shown) on the drill string (not shown) is removed from the well, and the wellhead base 110 is placed at the mouth of the borehole 101 and the first section of casing / the outermost conductor 130 is lowered through the wellheadbase 110 until the lower end of the outermost conductor 130 reaches the required depth (for example in the region of 100 metres) and the upper end of the outermost conductor 130 is suitable fixed or secured (e.g. via welding) to the inner bore of the wellhead base 110.

[0064] A lower wellhead housing 120 is then lowered onto the wellhead base 110 and can be fixed thereto by suitable means such as wellhead retention bolts 111 or the like and the lower wellhead housing 120 can be further connected to an upper end of the outermost conductor 130 by for example welding an upper end of the outermost conductor 130 to a lower end of the lower wellhead housing 120, as shown in Fig. 2. The lower wellhead housing 120 may comprise a profiled outer surface 121 on its generally vertically arranged cylindrical and upwardly projecting outer surface. The profiled outer surface 121 shown preferably comprises a LynxLok™ mounting flange profile for use with a LynxLok™ Clamping Arrangement 280, the LynxLok™ Clamping Arrangement 280 being offered by Oil States Industries (UK) Limited of Heartlands, Scotland (although any other suitable clamping arrangements could also be used without departing from the scope of the present invention). The profiled outer surface 121 can be used during a later stage for securing an additional section of the wellhead thereto (as described directly below).LynxLok™ Clamping Arrangement:

[0065] An exemplary clamping arrangement that can be used to secure axially adjacent sections of wellheads (e.g. an “upper” section of the wellhead, and a “lower” section of the wellhead - where upper and lower are used relative in this context as meaning upper / lower to the respective other adjacent section) together will now be described. The clamping arrangement 280 is preferably a LynxLok™ Clamping Arrangement being offered by Oil States Industries (UK) Limited of Heartlands, Scotland (although any other suitable clamping arrangements could also be used without departing from the scope of the present invention) and may comprise a profiled outer surface 121 provided on at least one of the upper or lower generally vertically arranged cylindrical outer surface sections of the wellhead, and a set of radially movable clamping dogs 280 provided within (e.g. housed within) the other of the at least one of the upper or lower section of the wellhead. The radially movable clamping dogs 280 are configured to engage and clamp against with said profiled outer surface 121. The radially movable clamping dogs 280 can be provided in a circumferentially staggered and spaced apart arrangement. The profiled outer surface 121 may be defined by at least one circumferentially extending groove which extends around the entire outer circumference of thegenerally vertically arranged cylindrical outer surface section of the wellhead. The radially movable clamping dogs 280 can be provided with at least one corresponding inwardly projecting and circumferentially extending projection(s) on a radially innermost surface thereof. The corresponding circumferentially extending projections of each clamping dog 280 are configured to extend part-circumferentially around the circumferentially extending groove (of the profiled surface 121) such that (once they’ve been moved radially inwards into their engaged and locked configuration during activation of the clamping arrangement) the annular projections of the radially movable clamping dogs 280 fully engage with the annular grooves thereby clamping the axially adjacent sections of the wellhead together. The radially movable clamping dogs 280 can be aligned such that they share a central axis, the central axis projecting through the centre of the circumferentially extending groove(s) (of the profiled surface 121), thus allowing each of the radially movable clamping dogs 280 to radially move and impinge upon the circumferentially extending groove(s) (of the profiled surface 121) equally. The clamping arrangement may further comprise a threaded configuration which when rotated is configured to translate the rotational movement of the radially movable clamping dogs 280 into said radial movement of the radially movable clamping dogs 280. In such embodiments, radially movable clamping dogs 280 may comprise a threaded profile on an outer surface thereof (and / or may instead be radially connected to a component having said threaded profile on an outer surface thereof), and a section of the wellhead (i.e. said at least one of the upper or lower section of the wellhead housing the radially movable clamping dogs 280 therein) may include a threaded profile corresponding to said threaded profile of the clamping dogs 280. Advantageously, embodiments of the present invention having this combination of the threaded configuration (which allows the rotational movement of the clamping dog 280 to be translated into radial movement of the clamping dog 280), enable a single rotational motion of the or each respective clamping dog 280 to move the clamping dog 280 from the retracted and disengaged configuration to the engaged and locked configuration.

[0066] With the first section of borehole 101 drilled for the outermost conductor 130, the wellhead base 110 can be installed, before lowering the lower end of the outermost conductor 130 into the borehole. The outermost conductor 130 can then be secured in place (e.g. by cementing in place). In this example, cement is pumped into the annulus (between the outermost conductor 130 and the inner surface of the wellbore) at this stage to secure the casing / outermost conductor 130 in place along substantially all of the length of the outermost conductor 130 (i.e. from the shoe (not shown) of the outermost conductor 130 to surface), ensuring that the wellhead base 110 is flat to the ground. The cementing secures the outermostconductor 130, seals off potential contamination areas, and provides structural reinforcement to the wellbore.

[0067] With the outermost conductor 130 installed, the wellhead base 110 can be secured to the lower wellhead housing 120. The wellhead base 110 may be secured to the lower wellhead housing 120 for example by wellhead retention bolts 111 provided therebetween, as shown in Fig.2.

[0068] Afterwards, the area can be cleaned up. Importantly, the subsequent stage(s) of the method typically involves installation of an additional section of the wellhead and casing system 1000 therefore at this stage (i.e. before installing any additional sections of the wellhead and casing system 1000), sealing components (e.g. ring gaskets) can be installed. In this example, a BX Gasket 125 is installed on the lower wellhead housing 120 for providing a seal between the lower wellhead housing 120 and a first intermediate section of the wellhead 220 (as will be subsequently detailed).

[0069] This completes the first stage (of installing the outermost conductor 130 and wellhead base 110) of the present exemplary method in accordance with embodiments of the present invention. In this presently described exemplary method in accordance with embodiments of the present invention, the outermost conductor 130 is not tensioned and locked in place during installation in the same manner as the inner casing(s) (as will be described subsequently in detail below of this presently described exemplary method. Generally, the lengths of the outermost conductor 130 is less than the length of the inner casings, and therefore the cost implication of cementing from the shoe (not shown) of the outermost conductor 130 to surface is proportionally less than the cost implication of cementing from the shoe (not shown) of the respective inner casings to surface. Moreover, the outermost conductor(s) are typically less exposed to larger temperature differentials than the inner casings 230, 330, and particularly less than the innermost conductor 330. However, the skilled person will understand that methods in accordance with embodiments of the present invention optionally may instead include tensioning and locking of the outermost conductor 130 in such a similar manner as the inner casing(s) 230, 330 of this presently described exemplary method.STAGE 2 OF EXEMPLARY METHOD IN ACCORDANCE WITH EMBODIMENTS OF THE PRESENT INVENTION - INSTALLATION AND TENSIONING OF A FIRST INNER CASING 230

[0070] The next stage (hereinafter referred to as “Stage 2”, “second stage” or the like) of the method in accordance with embodiments of the present invention includes the installation and tensioning of a first inner casing 230. Fig.3 is a front sectional view of the wellhead and casing system 1000 during this subsequent stage (from the stage shown in Fig. 2) of installing and tensioning the first inner casing 230.

[0071] The first step of this second stage (of installation and tensioning of a first inner casing 230) also requires a further borehole 201 to be drilled (as best shown in Fig.10); this time for the first inner casing 230. Again, this borehole 201 is typically larger in diameter than the first inner casing 230. In the example shown, the first inner casing 230 is a 13 A conductor pipe (i.e. 13 A inch [~ 340 mm] outer diameter). In an example in accordance with the present invention, the first inner casing 230 may, for instance, have a length (i.e. typically the length between the shoe of the first inner casing 230 and the surface 6) of approximately 900 metres.

[0072] The first inner casing 230 includes a first inner casing head portion 232 and a first inner casing body portion 231; a lower end of the head portion 232 is connected (by a suitable pipe connector means 233 described in detail subsequently) to an upper end of the body portion 231 to form the first inner casing 230.Description of Exemplary Components and Mechanisms of Upper Casing Head:

[0073] With reference to the detailed view of the head portion 232 shown in Fig. 5; the exemplary embodiment of the method and system may include a number of components and mechanisms including the pipe connector means 233, a tensioning tool connection means 234, and a locking mechanism 240. As will be understood by those skilled in the relevant arts, each of said components and mechanisms of the present invention may be practiced alone or in combination with one another (and / or one or more of the other aspects of features of the present invention).Pipe Connector Means:

[0074] For embodiments of the present invention in which the lower end of the head portion 232 is connected to an upper (pin) end of the body portion 231 via a pipe connector means 233. The pipe connector means 233 is preferably a MERLIN™ connector being offered by Oil States Industries (UK) Limited of Heartlands, Scotland (although any other suitable pipe connector means could also be used without departing from the scope of the present invention). An example of a suitable pipe connector means 233 (i.e. a MERLIN™ connector) / method for connecting the upper end of the body portion 231 and the lower (box) end of the head portion 232 (i.e. via said MERLIN™ connector) is described in detail as follows.

[0075] In the example shown in Figs. 3 and 5, the upper end of the body portion 231 includes a frustoconical outer peripheral surface 231a, and the lower end of the head portion 232 includes a corresponding frustoconical inner peripheral surface 232a. These frustoconical inner and outer peripheral surface are configured to engage telescopically with one another such that they overlie one another when the upper end of the body portion 231 is inserted into the lower end of the head portion 232.

[0076] To axially secure the head portion 232 and the body portion 231, one of the frustoconical outer peripheral surface 231a (of the upper end of the body portion 231) and the frustoconical inner peripheral surface (of the lower end of the head portion 232) comprises axially spaced circumferentially extending grooves in its frustoconical surface; whilst the other comprises corresponding axially spaced circumferentially extending annular projections or teeth in its frustoconical surface. These circumferential grooves and corresponding teeth are configured to resist axial forces and ensure metal-to-metal contact, crucial for maintaining joint integrity under pressure.

[0077] A radial passage having an inlet may be provided communicating with an axially extending recess intersecting some of the grooves centrally of the groove region. The inlet of the passage may be adapted for connection to a source of liquid.

[0078] During installation of the lower end of the head portion 232 to the upper end of the body portion 231, the upper end of the body portion 231 is initially pushed (i.e. telescopically) into the lower end of the head portion 232 until metal-to-metal contact is obtained between parts of the frustoconical surfaces. The conicity and the tooth and groove lengths of the pin231 and box 232 members are arranged so that initial metal-to-metal contact is obtained between the crest surface of each tooth. Once metal-to-metal contact has been made, an axial force is applied between the head portion 232 and the body portion 231 to progressively bring them together and engage the teeth in the respective grooves, until such point that the teeth along the peripheral surfaces of the head 232 and body 231 portions of the inner casing 230 begin to mesh.

[0079] Highly pressurised hydraulic fluid can then be injected into the coupling (i.e. the connection between the head 232 and body 231 portions) through said one or more inlets (not shown). The fluid is injected between the respective peripheral surfaces which expands the head portion 232 and / or contracts the body portion 231 to allow the body portion 231 to be fully pushed into the head portion 232. Upon release of the said pressure the head portion 232 contracts around the body portion 231 such that the annular teeth of the body portion 231 are fully engaged in the annular grooves of the head portion 232 and vice versa. The wedging action of the teeth converts radial preload of the coupling into an extremely high axial preload that maintains coupling stiffness and enhances axial and bending fatigue characteristics.Tensioning Tool Connection Means 234:

[0080] With reference to the detailed view of the head portion 232 shown in Fig. 5, an upper end of the first inner casing 230 comprises an attachment means 234 for permitting attachment of a tension pulling means 290, wherein in this embodiment the attachment means 234 is in the form of a tensioning tool connection means 234 to permit connection to a tensioning pull tool 290 to enable application of a tensile force to the casing during the tension applying process. For example, and as shown in the present example, an uppermost portion of the outer surface of the first inner casing 230 comprises a first outer threaded profile 234 defining a tensioning attachment profile 234 configured to permit connection to a tensioning pull tool 290 which may have a corresponding inner threaded profile for engaging said first outer threaded profile 234 during application of a tensile force to the first inner casing 230 (as will be described subsequently in detail below).Locking Mechanism:

[0081] To axially secure the wellhead 9 to the first inner casing 230, a locking mechanism 240 is provided (see Figs. 5 and 6D in particular). The locking mechanism 240 may typically include a set of circumferentially extending annular projections 241 (or teeth) which are arranged to be selectively engageable (as will be described subsequently) with a locking means provided at an upper end of the casing, where in this embodiment the locking means are provided by corresponding circumferentially extending grooves 242. The circumferentially extending annular projections 241 are provided on one of the first inner casing 230 and the wellhead 9 (or provided on any intermediate components securable thereon and / or therebetween), and the corresponding circumferentially extending grooves 242 being provided on the other. The circumferentially extending annular projections 241 (or teeth) are configured to move into engagement with the corresponding circumferentially extending grooves 242 during the locking process (which in this preferred embodiment optionally includes rotating an actuating sleeve member 255 which has a screw threaded configuration 260 provided thereon to force the locking mechanism 240 downwards as will be described subsequently) to axially lock the first inner casing 230 relative to the surface (i.e. via the wellhead therebetween) after the first inner casing 230 has been tensioned (and is being held in tensioned, waiting to be locked).

[0082] In the example shown, a lower portion of the outer surface of the head portion 232 (of the first inner casing 230) comprises axially spaced circumferentially extending grooves 242 and the axially spaced circumferentially extending annular projections 241 or teeth are provided on radially moveable locking dogs 250 (as best shown in Fig. 6D). The radially moveable locking dogs 250 (and the circumferentially extending annular projections 241 or teeth provided thereon) are configured to move into engagement with said lower portion of the outer surface of the head portion 232 of the first inner casing 230 (via the circumferentially extending grooves 242 thereon) during the locking process to thereby axially lock the first inner casing 230 in place.

[0083] Advantageously, embodiments of the present invention having such arrangements of corresponding sets of circumferentially extending annular projections 241 and grooves 242, provides the ability for the casing to be re-tensioned due to the ability to separate said corresponding sets of circumferentially extending annular projections 241 and grooves 242 from one another (e.g. by retracting the locking dogs 250); at such point tension can be reapplied to the casing (e.g. via a tension pulling means - as will be described subsequently in detail below) before once again axially locking the upper end of the casing. Additionally, theprovision of the upper ends / portions of the inner casings 230 not being directly secured to the surrounding formation (e .g . via cement) also provides the ability for the conductor / casing 230 to be re-tensioned.

[0084] The corresponding sets of circumferentially extending annular projections 241 and grooves 242 may be configured such that they allow a certain amount of controlled slipping.Axially Moveable Sleeve Member

[0085] The locking mechanism 240 may include an actuating sleeve member 255 for contacting, axially moving and thereby radially moving (i.e. via contact between the tapered surface 243, 251 of each of the radially moveable locking dogs 250 and the inner housing 245 of the wellhead 9, as described subsequently) the radially movable locking dogs 250 into engagement with the outer surface of the first inner casing 230. The actuating sleeve 255 can be aligned with the radially moveable locking dogs 250 such that they share a central axis, the central axis projecting through the centre of the circumferential arrangement of radially moveable locking dogs 250 and the actuating sleeve, thus allowing the actuating sleeve 255 to axially move and impinge upon each of the radially moveable locking dogs 250 equally.

[0086] An inner surface of the wellhead 9 (i.e. of the first intermediate section of the wellhead 220) may include a tapered surface 243. Additionally, the radially moveable locking dogs 250 may comprise tapered face(s) 251, which correspond with said tapered face 243 of the inner surface of the wellhead 9 (i.e. of the first intermediate section of the wellhead 220). Each of the tapered faces 251 of the radially moveable locking dogs 250 taper from a first (generally larger) dimension (which is preferably a diameter) to a second (generally narrower) dimension (which is preferably a diameter) thereof such that in use the tapered face 251 of the radially moveable locking dogs 250 engages and pushes against the corresponding tapered face 243 of the inner surface of the wellhead 9 (i.e. of the first intermediate section of the wellhead 220).The use of the tapered face ( / interface) allows the axial movement of the actuating sleeve 255 to be translated into radial movement of the radially moveable locking dogs 250. This allows one motion (in a first axial direction which in the Figures of this embodiment is downwards) of the actuating sleeve 255 to move the radially moveable locking dogs 250 from the retracted and disengaged configuration (as shown in Fig. 6D) to the engaged and locked configuration (as shown in Fig. 7B). It further provides the advantage of allowing a smooth transitionbetween these two configurations, which is desirable so as not to overly stress any of the materials which form the component parts of the locking mechanism 240 (or the wellhead and casing system 1000 for that matter).

[0087] The locking mechanism 240 may further comprise a screw thread configuration 260 configured to translate the rotational movement of the actuating sleeve 255 into axial movement of the actuating sleeve 255 (and radial movement and locking of the radially moveable locking dogs 250 thereafter). In such embodiments, the sleeve member 255 may comprise a threaded profile on an outer surface thereof, and a portion (e.g. an uppermost portion) of the inner surface of the first intermediate section of the wellhead 220) may include a threaded profile (261) corresponding to said threaded profile 260 on the outer surface of the sleeve member 255. The sleeve member 255 may, for instance, be an annular ring-shaped “pack-off retainer” 255 comprising a threaded profile on an outer surface thereof; said threaded profile corresponding to the second threaded profile of the outer surface of the first inner casing 230.

[0088] Advantageously, embodiments of the present invention having the combination of the screw thread configuration 260 (which allows the rotational movement of the actuating sleeve 255 to be translated into axial movement of the actuating sleeve 255), along with the tapered faces 243, 251 (which allow the axial movement of the actuating sleeve 255 to be translated into radial movement of the radially moveable locking dogs 250), enables a single rotational motion of the actuating sleeve 255 to move the locking dog 250 from the retracted and disengaged configuration to the engaged and locked configuration. It provides the advantage of providing an even smoother transition between these two configurations (i.e. compared to embodiments having only the tapered face, and not the screw thread configuration 260). Additionally, the screw thread configuration 260 provides the operator with the ability to back off the actuating sleeve 255 (by rotating it in the opposite, second rotational direction) to move the radially moveable locking dogs 250 from the engaged and locked configuration (as shown in Fig. 7B) back to the retracted and disengaged configuration (as shown in Fig. 6D) should for example the operator require to remove the tension they applied to the casing (in order for example to replace the casing / first inner casing 230). Accordingly, the actuating sleeve member 255 and screw threaded configuration 260 provides the ability to the operator to be able to control the said transition by rotating the upper most end of the actuating sleeve member 255 and which therefore is much easier to access and control.

[0089] In an alternative embodiment of the present invention, the locking mechanism 240 may include, for example, a latch mechanism 500, which may be, for instance, hydraulically operated or manually operated. Said latch mechanism 500 may include radially movable activating members 510 which are configured for contacting and radially moving the radially moveable locking members 250 into engagement with the outer surface the tensioned casing 230. For example, Figs. 11 to 14 show an exemplary embodiment of the present invention having a latch mechanism 500 that is configured such that radial movement of the radially movable activating members 510 causes corresponding radial movement of the radially moveable locking members 250. Although the radially movable activating members 510 may directly engage with the radially moveable locking members 250, in the embodiment shown in Figs. 11 to 14 the radially movable activating members 510 are configured to engage with the radially moveable locking members 250 via an intermediate retaining mechanism 520 provided between the radially movable activating members 510 and the respective radially moveable locking members 250. In this example the intermediate retaining mechanism 520 is provided in the form of a “pack off member” 520 that is configured to serve the purpose of retaining the radially moveable locking members 250 in a first position in which the radially moveable locking members 250 are in a radially retracted position such that the engaging profiles 241, 242 (i.e., the engagement profile 242 of the radially moveable locking members 250 and the corresponding engaging profiles 241 provided on the outer surface at the upper end of the casing 230) are spaced apart from one another and are therefore not in engaging contact with one another; and therefore such that, when the radially moveable locking members 250 are in the first (spaced apart) position as shown in Fig. 11, axial movement of the upper end of the casing 230 is not inhibited by the radially moveable locking members 250.

[0090] As best shown in the more detailed Figs. 13 and 14, outer surfaces 522 of the intermediate retaining mechanism 520 are configured to engage with complementary inner surfaces 252 of the radially moveable locking members 250. With the radially moveable locking members 250 in their first (spaced apart) position (as shown in Figs. 11 and 13) and the intermediate retaining mechanism 520 is radially retracted (i.e., and in its configuration for retaining the radially moveable locking members 250 in the first position), a retaining engagement is provided between the radially moveable locking members 250 and the intermediate retaining mechanism 520. During this retaining engagement, the outer surfaces 522 of the intermediate retaining mechanism 520 and the complementary inner surfaces 252 of the radially moveable locking members 250 are configured to substantially or fully engage with one another (as best shown in Fig. 13), such that said respective surfaces 252, 522 are engagedsubstantially or fully in continuous secure contact over substantially the entire extent of their complementary engagement surfaces 252, 522. As shown in Figs.11 and 13, when the radially moveable locking members 250 are in their first (spaced apart) position (i.e., their radially retracted position) and the intermediate retaining mechanism 520 is also in a first position (i.e., in which it is also in a radially retracted position from the casing 230), radial movement and also axial movement of the radially moveable locking members 250 is restricted by the intermediate retaining mechanism 520 via the substantial or full engagement of said complimentary inner and outer surfaces 252, 522. This substantial or full engagement acts to retain the radially moveable locking members 520 in their radially retracted position, until such stage that they are required to move radially inwards to lock the tensioned casing 230 in place. The tapered surfaces 243, 251 additionally act to restrict relative axial movement of the radially moveable locking members 250.

[0091] At the stage when the radially moveable locking members 250 are required or desired by the operator to move radially inwards to lock the tensioned casing 230 in place, the radially movable activating members 250 can be moved radially inwards (the operation thereof will be described in further detail subsequently), causing the intermediate retaining mechanism 520 to correspondingly move radially inwards. As the intermediate retaining mechanism 520 gradually moves radially inwards, the radially moveable locking members 520 gradually in turn move radially inwards, whilst also gradually moving in an axially downwards direction; due to:- i) the reduced retention of the radially moveable locking members 250 inhibited by the radially inwards movement of the intermediate retaining mechanism 520, which in turn permits at least partial axial movement of the radially moveable locking members 250, andii) gravity which causes the radially moveable locking members 250 to move downwards as the tapered surfaces 251 thereof slides along the tapered surface 243 of the inner surface of the inner housing 245 of the wellhead 9. This downward movement causes the respective surfaces 252, 522 to be gradually moved from their substantial or full engagement (with one another) to a partial engagement, in which at least a lower portion of the outer surfaces 522 of the intermediate retaining mechanism 520 is in contact with at least an upper portion of the complementary inner surfaces 252 of the radially moveable locking members 250. Advantageously, maintaining at least such partial engagement throughout enables the radially moveable locking members 250 to be selectively retractable at any stage; for example, following tensioning of the casing 230 and locking of said tension via the radially moveable locking members 250, should the operator wish to remove, increase or otherwise adjust thetension, the operator can move the radially movable activating members 510 in a radially outwards direction causing the intermediate retaining mechanism 520 to correspondingly move radially outwards, and in doing so the intermediate retaining mechanism 520 will engage the radially moveable locking members 250 (via said at least partial engagement of the surfaces 252, 522 therebetween) and move the radially moveable locking members 250 radially outwardly towards the first position thereof, with the radially moveable locking members 250 sufficiently retracted from the outer surface of the casing 230.

[0092] In response to continued radially inwards movement of the radially movable activating members 510, the intermediate retaining mechanism 520 and the radially moveable locking members 250 will each continue to gradually move radially inwards, and the radially moveable locking members 250 will also continue to move gradually axially downwards, until such point as the radially moveable locking members 250 have arrived at their second position, in which the one or more engaging profiles 241 on the at least one radially moveable locking member 250 have moved into locking engagement with the one or more corresponding engaging profiles 242 provided on the outer surface at the upper end of the casing 230, as shown in Figs.12 and 14 (i.e., said locking engagement being the same as has been described in detail hereinabove). Following completion of the locking engagement between said engaging profiles 241, 242, the tensioned casing 230 will be locked in place. Advantageously, for embodiments of the present invention having the tapered surfaces 243, 251, the load (e.g., the weight of the tensioned casing 230) is transferred directly from the casing 230 to the wellhead 9 via these tapered surfaces 243, 251, rather than being transferred directly from the casing 230 to the wellhead 9 via the radially movable activating members 510 which enables easier control of the radially movable activating members 510.

[0093] Radial movement of the radially movable activating members 510 can be controlled by any suitable means. For example, the radial movement may be hydraulically operated (such as with a suitable piston arrangement (not shown) being moveable by application of pressurised hydraulic fluid) or can be moved by a suitable powered motor (not shown) or could be manually operated, and may additionally or otherwise include a threaded arrangement 511, 512. As best illustrated in Fig. 14, a threaded arrangement 511, 512 can be employed to control the radial movement of the radially movable activating members 510. In this example, the radially movable activating members 510 are circumferentially spaced around the wellhead 9, with each being housed within a respective throughbore 515 formed through a side wall of the wellhead 9. In this arrangement, the threaded arrangement 511, 512 is configured to translate therotational movement of the radially movable activating members 510 into radial movement of the intermediate retaining mechanism 520 (and radial movement and locking of the radially moveable locking members 250 thereafter). The radially movable activating members 510 each comprise a threaded profile 511 on an outer surface thereof. The throughbores 515 (i.e., housing their respective radially movable activating members 520 therein) each comprise a corresponding threaded profile 512 on an inner surface thereof (i.e., corresponding to the threaded profile 511 on the outer surface of the radially movable activating members 510). In the example shown in Figs 11 to 14, the radially movable activating members 510 are connected to the intermediate retaining mechanism 520 via a swivel type connection 529 that permits the intermediate retaining mechanism 520 to move radially with the radially movable activating members 510 whilst preventing the intermediate retaining mechanism 520 from rotating around the longitudinal axis of the radially movable activating members 510 as the radially movable activating members 510 rotate around their longitudinal axis. Accordingly, rotational movement can be selectively applied to the radially movable activating members 510 (e.g., by applying rotation to the radially movable activating members 510 via radially outer openings 513 of the throughbores 515 housing the respective radially movable activating members 510 therein) which is translated to radial movement by the threaded arrangement 511, 512. The radial movement of the radially movable activating members 510 is then converted into radial movement of the locking members 250, as described above. The radially movable activating members 510 can be rotated by any suitable means such as manually or more preferably by an automated and powered rotation mechanism comprising suitably powered and controlled motors (not shown).

[0094] With the borehole 201 drilled for the first inner casing 230, the lower end of the first inner casing 230 is located at the lower end of the casing hole 201. The lowermost end (and / or a lower portion) of the first inner casing 230 can be secured in place (and this step occurs before the locking dog 250 are moved from the retracted and disengaged configuration to the engaged and locked configuration). In this example, cement is pumped into the annulus (between the outer surface of the first inner casing 230 and the inner surface of the borehole 201) to secure the lower end of the first inner casing 230 in place at a lower point (or along a lower portion of the length) of the first inner casing 230 (as shown in Figure 4). In the example shown, cement 270 is pumped into the annulus along a length between the shoe (not shown) located at the bottom of the first inner casing 230 and the shoe (not shown) located at the bottom of the outermost conductor 130. This particular cementing arrangement can be referred to as “shoe-to-shoe” cementing. The skilled person will however understand that any suitable means of securing a lowermost end (and / or a lower portion) of the first inner casing 230 in place can be used (e.g. alternative cementing methods and / or any suitable of mechanical means), and the skilled person will further understand that embodiments of the present invention are not limited to such methods / systems including “shoe-to-shoe” cementing. For example, instead of pumping cement into the annulus along a length between the shoe (not shown) of the first inner casing 230 and the shoe of the outermost conductor 130, cement may instead, for instance, be pumped into the annulus along a length between the shoe of the first inner casing 230 and a location below the shoe of the outermost conductor 130 (and / or a location above the shoe of the outermost conductor 130, but preferably still at a distance below the surface / top of the first inner casing 230). However, in the preferred embodiment described herein, the “shoe-to-shoe” cementing is particularly preferred because it provides significant reductions in the amount of cement required to complete the wellbore and therefore provides significant advantages in CO2 reduction from the cement production / curing process and additionally provides significant cost reductions due to the reduction in the amount of cement required.

[0095] With the first inner casing 230 installed and cemented in place, a first intermediate section of the wellhead 220 can be installed in the next completion step. The first intermediate section of the wellhead 220 is secured to the lower wellhead housing 120 with clamps 280 which engage with the profiled outer surface 121 of the lower wellhead housing 120. A detailed description of an exemplary clamping arrangement that can be used to secure axially adjacent sections of wellheads (e.g. an “upper” section of the wellhead, and a “lower” section of the wellhead - where upper and lower are used relative in this context as meaning upper / lower to the respective other adjacent section) is described at paragraph

[0065] . With specific reference to the example shown in Fig. 3, the lower wellhead housing 120 comprises a profiled outer surface 121. The profiled outer surface 121 shown is preferably a LynxLok™ mounting flange profile. A set of equally spaced circumferential radially movable clamping dogs 280 are housed with first intermediate section of the wellhead 220. These clamping dogs 280 are a LynxLok™ clamps. The clamping dogs 280 are each radially connected to a screw member having an outer threaded profile on an outer surface thereof (each corresponding to an inner threaded profile of the housings within first intermediate section of the wellhead 220 - i.e., said housings being the housings for each respective clamping dogs 280) such that rotation of the screw member translates into radial movement of the clamping dogs 280. Accordingly, in this embodiment, the clamping is controlled by rotational movement (of the screw member). In use, the first intermediate section of the wellhead 220 is placed atop the lower wellhead housing120 and aligned such that the clamping dogs 280 (e.g. and / or the housing thereof) line up with the profiled outer surface 121, or more specifically such that the circumferentially extending of the clamping dog 280 is aligned with the circumferentially extending groove of the profiled outer surface of the lower wellhead housing 120. With proper alignment, the screw member of the clamping dog 280 is rotated to radially extend the clamping dog 280 inwards and towards the lower wellhead housing 120. Typically, each of the respective screw members of each of the clamping dogs 280 are rotated simultaneously such that each of the radially movable clamping dogs radially move and impinge upon the circumferentially extending groove(s) (of the profiled surface) equally. As the clamping dogs 280 move into engagement, the circumferentially extending projections thereon move into engagement with the corresponding circumferentially extending grooves of the lower wellhead housing 120 to lock the lower wellhead housing 120 relative to the first intermediate section of the wellhead 220.

[0096] After the first intermediate section of the wellhead 220 is installed, pressure tests of the lower section 120 can be performed (e.g. in line with API Regulations). The first intermediate section of wellhead housing 220 may also comprise a profiled outer surface 221 at an upper end thereof. The profiled outer surface 221 shown is also preferably a LynxLok™ mounting flange profile. The profiled outer surface 221 can be used during a later stage for securing an additional section of the wellhead thereto.Tensioning Process:

[0097] The tensioning of the first inner casing 230 will now be described.

[0098] In this presently described example, which includes cement 270 being pumped into the annulus along a length between the shoe of the first inner casing 230 and the shoe of the outermost conductor 130, the tensioning process typically commences only after the cement 270 has been set. This may be advantageous due to the fact that it ensures that the lower end of the first inner casing 230 is sufficiently secure enough within the well such that the lower end of the first inner casing 230 does not axially lift up along with the upper end of the first inner casing 230, which may prevent or substantially minimize the amount of tensile force that is applied to the first inner casing 230. That being said, there may for instance be examples in which the weight of a casing 230 alone (i.e. which may be several kilometres in length, and which may weigh several tens or even hundreds of tons) is sufficient to axially lock the lowerend of the first inner casing 230 in place during the tensioning process, and in such an instance (or indeed otherwise) the requirement / advantages of waiting to commence the tensioning process until after the cement has been set may not be as pertinent (e.g. due to either a complete lack of cement being used, or due to the fact that the cement is not strictly required to axially lock the lower end of the first inner casing 230 in place during the tensioning process).

[0099] The first inner casing 230 is tensioned by applying a tensile load to the first inner casing 230 via an upper end of the first inner casing 230. In the example shown, a tension pulling tool 290 is used to connect to the upper end of the first inner casing 230 (via tensioning tool connection means 234, as described in paragraph

[0080] ) and apply atensile force thereto. The tension pulling tool 290 can be any suitable tool for connecting to an upper end of the casing 230 and subsequently applying a tensile force thereto. An example of a suitable tension pulling tool 290 is shown in Fig.3. This tension pulling tool 290 connects to an upper end of the first inner casing 230 via a threaded connection there between. To enable application of tensile force to the casing 230 during the tension applying process, the upper end of the tension pulling tool 290 connects with the lower end of a standard drill string 291 (e.g. via a NC50 threaded connection), which is operable to apply said tensile force by lifting the drill string 291 in an upwards direction.

[0100] Fig. 6A shows a front sectional view of the wellhead and casing system 1000 at the start of the tensioning process, at the point whereby the tensioning tool 290 has been connected / secured to the first inner casing 230. With the tension pulling tool 290 connected to the first inner casing 230, the first inner casing 230 is pulled into tension. In this example, the first inner casing 230 is pulled into tension by lifting the tensioning tool 290 (and the first inner casing 230 connected thereto) in an upwards direction (e.g. via lifting the drill string 291 in an upwards direction). In the example shown, the first intermediate section of the wellhead 220 includes an upper portion 220U and a lower portion 220L, with the upper portion 220U connected atop the lower portion 220L. Each of the upper portion 220U and a lower portion 220L of the first intermediate section of the wellhead 220 includes annular grooves 223 for housing high temperature seals 224 therein, said annular grooves 223 being proximate to the interface 220A of the upper portion 220U and the lower portion 220L of the intermediate section of the wellhead 220 (as best shown in Fig.5).

[0101] Fig. 6B shows the next stage of the tensioning process (subsequent to the initial engagement of the tensioning 290 tool shown in Fig. 6A) and specifically shows the midwaypoint of the tensioning process with the casing 230 in a mid-tensioned stage. It can be seen in this example, that the uppermost end of the casing / first inner casing 230 (and the lower end of the tension pulling tool 290 connected thereto) moves from an initial position below the interface 220A of the upper portion 220U and the lower portion 220L of the first intermediate section of the wellhead 220 (i.e. as shown in Fig.6A - approximately in line with a valve body 226 of the lower portion of the first intermediate section of the wellhead 220) to a position which is approximately in line with said interface 230A of the upper portion 220U and the lower portion 220L of the first intermediate section of the wellhead 220 (i.e. as shown in Fig.6B).

[0102] From this point, the tensioning tool 290 continues to pull the upper end of the casing / first inner casing 230 in an upwards direction (e.g. via lifting the drill string 291 in an upwards direction), until the desired (e.g. pre-determined) amount of tension is achieved in the first inner casing 230. Fig. 6C shows the stage of the tensioning process (subsequent to the midway point of the process shown in Fig.6B) and specifically shows the final point / location of the tensioning process with the casing 230 in a fully tensioned stage (i.e. with the desired amount of tension achieved). It can be seen in this example that the uppermost end of the first inner casing 230 (and the lower end of the tension pulling tool 290 connected thereto) moves from the midway position which is approximately in line with the interface 220A of the upper portion 220U and the lower portion 220L of the first intermediate section of the wellhead 220 (i.e. as shown in Fig. 6B) to a position which is approximately in line with the uppermost end of the first intermediate section of the wellhead 220 (i.e. as shown in Fig. 6C). The operator will typically lift the standard drill string 291 by a sufficient distance such that the casing / first inner casing 230 is tensioned and thereby elastically stretched by a sufficient degree but not so much as to plastically stretch the casing / first inner casing 230. In other words, the operator will stop applying tension to the casing / first inner casing 230 before it experiences any plastic deformation.

[0103] With the desired amount of tension being achieved in the first inner casing 230 (e.g. as shown in Fig. 6C), the tension locking mechanism 240 can then be used to axially secure the first inner casing 230 in place.

[0104] As the skilled person will understand, due to a lowermost end (or a lower a portion) of the first inner casing 230 being secured / locked in place (i.e. such that it cannot move axially), pulling on the upper end of the first inner casing 230 in an upwards direction applies a tensileforce along a portion or length of the first inner casing 230, specifically along the length of the first inner casing 230 which is not axially secured / locked in place. For example, when a shoe-to shoe cementing method is used (as described at paragraph

[0094] ), the tensile force will be applied along a length of the first inner casing 230 between a first point proximate the shoe of the outer conductor 130 and a second point proximate the surface of the wellbore. On the other hand, when such a shoe-to shoe cementing method is used, the length of the first inner casing 230 between the shoe of the outer conductor 130 and the shoe of the first inner casing 230 (i.e. the length having been cemented in place) will not experience the same tensile force by virtue of the cement which prevents said portion of the first inner casing 230 from moving axially (i.e. in response to the tensile force applied via the upwards pulling / lifting of the drill string 291 and tensioning tool 290 - and the upper end of the first inner casing 230 connected thereto - in an upwards direction).Locking Process:

[0105] An exemplary process of locking the tensioned first inner casing 230 in place will now be described with reference to the example shown in the drawings, in which the locking mechanism 240 includes each of the optional features of : an annular ring-shaped axially moveable actuating sleeve member 255 (as described at paragraph

[0085] ) having a screw thread configuration 260 (as described at paragraph

[0087] ); radially moveable locking dogs 250 (having circumferentially extending annular projections or teeth 241 provided thereon, as described at paragraph

[0082] ); circumferentially extending grooves 242 (provided on the outer surface of the head portion 232 of the first inner casing 230, as described at paragraphs

[0081] and

[0082] ); and the tapered face arrangement (as described at paragraph

[0086] ).

[0106] Throughout this process of locking the tensioned first inner casing 230 in place, the tensioned first inner casing 230 is held (i.e. tensioned, as shown in Fig. 6B) in place, until such point that the locking mechanism 240 has successfully engaged with and locked against the first inner casing 230. After such point, and typically only ever after such point, can the tension pulling tool 290 be removed.

[0107] The radially moveable locking dogs 250 may be temporarily connected to a surface of the inner housing of the wellhead 9 (e.g. a surface of the inner housing of the first intermediate section of the wellhead 220). Fig. 6D shows the locking mechanism 240 in the retractedconfiguration. To commence the locking of the locking mechanism 240 of the presently described example, the radially moveable locking dogs 250 (which are normally retained against the inner housing of the wellhead 9, during transportation, by any suitable means such as a plastic sleeve) are released from said inner housing of the wellhead 9 and the circumferentially extending annular projections 241 of the radially moveable locking dogs 250 move into contact and engagement with the circumferentially extending grooves 242 provided on the lower portion of the outer surface of the head portion 232 (of the first inner casing 230). Generally, at this stage, the circumferentially extending annular projections 241 of the radially moveable locking dogs 255 have merely made initial contact with the circumferentially extending grooves 242, such that relative axial movement of the upper end of the first inner casing 230 is still possible. In this example, to lock the radially moveable locking dogs 250, the actuating sleeve member 255 is used for contacting, axially moving and thereby radially moving (i.e. via contact between the tapered surface 251 of each of the radially moveable locking dogs 250 and the inner wellhead, as described subsequently) the radially movable locking dogs 250 into engagement with the outer surface of the first inner casing 230. Torque is applied to the actuating sleeve member 255 thereby rotating the actuating sleeve member 255. This rotation is translated into downwards axial movement of the actuating sleeve member 255, due to the screw thread configuration 260. Continued application of torque, and therefore axial movement of the actuating sleeve member 255, results in the actuating sleeve member 255 impinging upon each of the radially moveable locking dogs 250, which due to the tapered face arrangement forces the radially moveable locking dogs 250 both radially inwards and axially downwards thereby moving the radially moveable locking dogs 250 into the locked configuration (as shown in Figs. 7Aand 7B).

[0108] Now that the process of locking the tensioned first inner casing 230 in place has been completed, the tensioned first inner casing 230 can be disconnected from the tension pulling tool 290. To prevent the actuating sleeve member 255 from loosening from the locked configuration (e.g. via reverse rotation resulting in axial movement) and also to ensure an adequate (i.e. not too loose nor too tight) locking force has been applied, the actuating sleeve member 255 can be checked for torque to ensure that the correct amount of rotational force has been applied.

[0109] Afterwards, the area can once again be cleaned up. Importantly, the subsequent stage of the method typically involves installation of an additional section of the wellhead and therefore at this stage (i.e. before installing any additional sections of the wellhead) any sealingcomponents (e.g. ring gaskets) can be installed. In this example, a SBMS (Straight Bore Metallic Seal) 295 and a retainer 296 thereof are installed, along with a BX Gasket 225.

[0110] This completes the second stage (of tensioning and installing the first inner casing 230) of the present exemplary method in accordance with embodiments of the present invention.STAGE 3 OF EXEMPLARY METHOD IN ACCORDANCE WITH EMBODIMENTS OF THE PRESENT INVENTION - INSTALLATION AND TENSIONING OF A SECOND INNER CASING 330

[0111] The next stage (hereinafter referred to as “Stage 3”, “third stage” or the like) of the method in accordance with embodiments of the present invention includes the installation and tensioning of a second inner casing 330; it is important to note however, that this third stage is optional in that some wellbores may not require a third stage because they don’t require the installation and tensioning of a second inner casing 330 (because for example the wellbore is shallow enough that the installation and tensioning of a first inner casing 330 is sufficient). On the other hand, some wellbores may well require such a third stage and indeed may require a further stage (not shown) immediately thereafter that involves a similarly installed but even narrower fourth inner casing (not shown) be installed after the third stage (because for example the wellbore is deeper such that the installation and tensioning of only a first 230 and second 330 inner casings is not sufficient). Fig.8A is a front sectional view of the wellhead and casing system 1000 during this subsequent third stage (next on from the second stage shown in Fig.3) of installing and tensioning the second inner casing 330. The steps and components of this third stage of the exemplary method are broadly speaking in many respects relatively similar to, and most instances essentially all of the same or equivalent steps and components, as described in respect of prior Stage 2 (with reference to Figs. 3 to 7C, above), and thus similar components and features to those of the second stage are indicated with the same reference numeral, but with the addition of 100 (e.g. first inner casing 230 of Stage 2 corresponds with second inner casing 330 of stage 3).

[0112] The first step of this third stage (of installation and tensioning of a second inner casing 330) also requires a further borehole 301 to be drilled; this time for the second inner casing 330. Again, this borehole 301 is typically larger in diameter than the second inner casing 330, but is typically smaller in diameter than the first inner casing 230 (so that the drill bit involvedcan pass through the first inner casing 230). In the example shown, the second inner casing 330 is a 9 % casing pipe (i.e. 9 % inch [~ 250 mm] outer diameter). In an example in accordance with the present invention, the second inner casing 330 may, for instance, have a length (i.e. typically the length between the shoe of the second inner casing 330 and the surface 6) of approximately 1700 metres.

[0113] The second inner casing 330 may also include a second inner casing head portion 332 and a second inner casing body portion 331, and in this example has substantially all the same features as described in the previous stage, including a pipe connector means 333 (as described at paragraphs

[0074] -

[0079] ), a tensioning tool connection means 334 (as described at paragraph

[0080] ), a locking mechanism 330 (as described at paragraph

[0081] ).

[0114] With the borehole 301 drilled for the second inner casing 330, the lower end of the second inner casing 330 is lowered into the borehole 301. The lowermost end (and / or a lower portion) of the second inner casing 330 can be secured in place (e.g. as described at paragraph

[0094] ).

[0115] With the second inner casing 330 installed, a second intermediate section 320 of the wellhead of the wellhead 9 can be installed. The lower end of the second intermediate section 320 of the wellhead 9 is secured to the upper end of the first intermediate section 220 of the wellhead 9 with clamps 380 which engage with the profiled outer surface 221 of the first intermediate section of the wellhead 220.

[0116] This completes the third stage (of installing and tensioning the second inner casing 330) of the present exemplary method in accordance with embodiments of the present invention.STAGE 4 OF EXEMPLARY METHOD IN ACCORDANCE WITH EMBODIMENTS OF THE PRESENT INVENTION - INSTALLATION OF WELLHEAD CAP I TOP SECTION

[0117] The next stage (hereinafter referred to as “Stage 4”, “fourth stage” or the like) of the method in accordance with embodiments of the present invention includes the installation of awellhead cap / top section. Fig. 9 is a front sectional view of the wellhead and casing system during this final stage.

[0118] The fourth stage involves the installation of a cap wellhead 420 (i.e. an upper section of wellhead 420). The upper section of wellhead 420 can be secured to the second intermediate section of the wellhead 320 with clamps 480 which engage with the profiled outer surface 321 of the second intermediate section of the wellhead 320. In the example shown, LynxLok™ clamps 480 are again used, which again engage with the LynxLok™ mounting flange profile (in a similar manner as hereinbefore already described) of the second intermediate section of the wellhead 320. With the upper section of wellhead 420 now secured to the second intermediate section of the wellhead 320, the wellhead 9 in this present exemplary method is now fully formed; this wellhead 9 thus mainly being made up of the wellhead base 110, the lower wellhead housing 120, the first intermediate section of the wellhead 220, the second intermediate section of the wellhead 320, and the upper section of wellhead 420. After the upper section of wellhead 420 is installed, pressure tests of the second intermediate section of the wellhead 320 can be performed (e.g. in line with API Regulations).

[0119] At this final stage any sealing components (e.g. ring gaskets) can be installed, along with any other equipment, such as valves fittings, that is required. In this example, a BX Gasket is installed, in addition to bolts (e.g. for connecting to a 7 1 / 16 standard API Flange) and some equipment (e.g. Christmas tree assembly / valve block arrangement).

[0120] This completes the fourth and final stage of the present exemplary method in accordance with embodiments of the present invention. Once all of the topsides equipment has been installed and checked, operation of the geothermal system 1 can be commenced by the operator in order to recover / produce useful energy and in-doing-so the tensioned but noncemented casing of the first 230 (and if present second 330) inner casings in the first vertical section 3 will likely expand due to the heated transfer fluid being returned to surface therethrough. However, because the non-cemented casing of the first 230 (and if present second 330) inner casings in the first vertical section 3 was pretensioned, it is much less likely to buckle but rather will much more likely relax into itself thus significantly extending the likely lifespan of such casing and therefore significantly extending the likely lifespan of such a geothermal system 1.

[0121] Embodiments in accordance with the present invention provide for reduced cement requirements in comparison to current conventional “full annulus” cementing, which requires much larger volumes of cement (and much more problematic placement thereof). Embodiments in accordance with the present invention in which cement is circulated in a lower portion of the annulus only (i.e. in a portion of the annulus between the casing and the borehole wall only), provide the advantage of enabling access to at least an upper portion of the annulus such that the annulus can be continuously (e.g. via 24 hour a day, 365 days a year) monitored. Continual annulus monitoring (e.g. electronic surveillance) results in lower downtimes of the well (e.g. due to the reduced requirement for casing health monitoring that requires well shut down and intervention) and enables rapid indication of corrosion causing material via annulus sampling chemistry. Additionally, maintenance of this annulus path to a specific depth provides for better protection of shallow aquifers. The reduction in the cement requirement of the present invention can be (at least partially) attributed to the ability provided by the present invention to apply and lock in tension within the casing, which, for instance, prevents or drastically mitigates against buckling in the casing.

[0122] An additional advantage provided by embodiments of the present invention, includes the removal of the requirement for high -cost tubing (e.g. vacuum insulated tubing used in high temperature wells) that may otherwise be used to prevent failure in the casing (e.g. due to compressive failure / buckling) which can be caused, for instance, by thermally induced forces. Embodiments of the present invention enable the simple replacement of cement (e.g. “full annulus” cementing as used in conventional methods) with lower thermally conductivity fluid.EXAMPLES OF ADDITIONAL I ALTERNATIVE STEPS AND FEATURES IN ACCORDANCE WITH THE PRESENT INVENTION

[0123] Re-tensioning and / or readjustment of the applied tension of the casing is also possible. To re-tension / readjust the tension in the casing, it is possible to rotate the axially moveable sleeve member (i.e. in a reverse rotational direction, which due to the threaded connection translates said rotational movement of the actuating sleeve to into axial movement of the actuating sleeve) to move the locking dog from the engaged and locked configuration to the retracted and disengaged configuration. Tension can then be adjusted or re-applied (e.g. via the same tensioning means as described at paragraphs

[0097] to

[0104] ), before once again securing the tensioned (i.e. re-tensioned) casing (e.g. via the same locking means as described at paragraphs

[0105] to

[0107] ).

[0124] Although the embodiments of the present invention are particularly well suited to use in geothermal wells, the skilled person will appreciate that aspects and embodiments in accordance with present invention are not limited as such to the application of geothermal energy extraction. Rather, as the skilled person will understand, all of the described aspects and embodiments in accordance with present invention can also be used in related fields or applications such as, but not limited to, hydrocarbon production wells such as oil and gas wells particularly as the advantages (e.g. of a reduction in the amount of cement that is required for installations of embodiments of the present invention) will be of significant benefit in reducing the costs of such hydrocarbon production wells.

[0125] As the skilled person will understand, the number of inner casings may vary depending on a variety of factors (e.g. well depth, specific application, temperatures etc), and the number of casings / conductors that may be installed can vary. Accordingly, the skilled person will additionally understand that the present invention includes embodiments including further adding additional stages (i.e. repeating the stages 2 or 3) to this exemplary method. For use of example, a further (“third” in the context of the exemplary described embodiment) inner conductor or casing may be installed and tensioned by introducing an additional step (e.g. after stage 3) which mirrors the stages described in respect of stages 2 or 3, as described herein. On the other hand, the skilled person will additionally understand that the present invention includes embodiments including a reduced number of stages (i.e. removing either of stages 2 or 3) to this exemplary method. For use of an example, a single inner conductor or casing may be installed and tensioned (e.g. by removing step 3).

[0126] Embodiments of the present invention can be modified or improved without departing from the scope of the invention.

Claims

1. A method of tensioning a casing, the method comprising the steps of: a. securing a lower end of a first casing within a well;b. tensioning the first casing by applying a tensile load to the first casing via an upper end of the first casing; andc. axially securing the upper end of the first casing, whilst the first casing is tensioned, by moving one or more engaging profiles provided on at least one radially moveable locking member into engagement with one or more corresponding engaging profiles provided on the outer surface at the upper end of the casing, to thereby lock the tensioned first casing within the well.

2. A method as claimed in claim 1, wherein the method further includes the step of installing the first casing in the well, wherein said step of installing the first casing in the well includes:drilling a hole for the first casing; andinserting the first casing into a wellbore.

3. A method as claimed in either of claim 1 or 2, wherein the method further comprises the step of securing the outer surface of the length of the first casing in place within the wellbore.

4. A method as claimed in any preceding claim, wherein the method further comprises the step of cementing a lower portion of the length of the first casing in place.

5. A method as claimed in any preceding claim, wherein the method further comprises the step of attaching a tension pulling tool to the upper end of the first casing.

6. A method as claimed in claim 5, wherein the method further comprises the step of lifting the tension pulling tool to thereby apply tension to the first casing.

7. A method as claimed in claim 6, wherein the method further comprises the step of activating a locking mechanism to axially secure the tensioned first casing at or towards the upper end thereof.

8. A method as claimed in claim 7, wherein the method further comprises the step of removing the tension pulling tool from the first casing after the locking mechanism has axially secured the tensioned first casing at or towards the upper end thereof.

9. A method as claimed in any preceding claim, wherein the method further comprises the step of attaching a first casing head to a first casing body.

10. A method as claimed in any preceding claim, wherein the method further comprises the steps of:drilling a hole for a second casing;inserting the second casing into the wellbore;securing the outer surface of the length of the second casing in place within the wellbore;attaching a tension pulling tool to the upper end of the second casing; lifting the tension pulling tool to thereby apply tension to the second casing; andactivating the locking mechanism to axially secure the tensioned second casing at or towards the upper end thereof.

11. A method as claimed in claim 10, wherein the method further comprises the steps of:drilling a hole for a third casing;inserting the third casing into the wellbore;securing the outer surface of the length of the third casing in place within the wellbore;attaching a tension pulling tool to the upper end of the third casing;lifting the tension pulling tool to thereby apply tension to the third casing; and activating the locking mechanism to axially secure the tensioned third casing at or towards the upper end thereof.

12. A method as claimed in any preceding claim, wherein the well is at least one of:a geothermal well;a hydrocarbon production well; orheated water production well.

13. A method as claimed in any preceding claim, wherein the method further comprises the step of re-tensioning the casing, wherein said step of re-tensioning the casing comprises:re-tensioning the casing by applying a tensile load to the casing via an upper end of the casing; andre-securing the upper end of the casing whilst the casing is tensioned to lock the tensioned casing.

14. A tensioning system, the system comprising:a casing, said casing comprising:an upper end,a lower end securable within a well,an attachment means at an upper end thereof for permitting attachment of a tension pulling means, anda locking means at an upper end thereof for attachment to a locking mechanism, wherein the locking means comprises one or more engaging profiles provided on the outer surface at the upper end of the casing;a tension pulling means attachable to said attachment means of the casing and configured to apply a tensile load to the casing via said upper end thereof; anda locking mechanism configured to selectively lock against said locking means of the casing such that the axial position of the upper end of the casing is locked in place,wherein said locking mechanism includes at least one radially moveable locking member having one or more engaging profiles, which correspond to the one or more engaging profiles of the locking means, andwherein the one or more engaging profiles of the at least one radially moveable locking member is / are configured to be selectively movable into engagement with said one or more corresponding engaging profiles of the locking means.

15. A tensioning system as claimed in claim 14, wherein an uppermost portion of the outer surface of the casing comprises an outer threaded profile defining a tensioning attachment profile, wherein said tensioning attachment profile is configured to permit connection to a tensioning pulling tool having a corresponding inner threaded profile for engaging said threaded profile during application of a tensile force to the casing.

16. A tensioning system as claimed in any of claims 14 to 15, wherein the system includes a tension pulling tool for connecting to the upper end of the casing via the tensioning attachment profile and for applying a tensile force thereto, wherein the tension pulling tool is configured to connect with a standard drill string such that tensile force can be applied by lifting the drill string in an upwards direction to enable application of tensile force to the casing during the tension applying process.

17. A tensioning system as claimed in any of claims 14 to 16, wherein the system comprises a wellhead, wherein said wellhead includes axially adjacent sections, wherein said axially adjacent sections comprise at least one set of:an upper section of wellhead, anda lower section of wellhead.

18. A tensioning system as claimed in claim 17, wherein the system further comprises a clamping arrangement configured to secure axially adjacent sections of wellheads together,wherein the clamping arrangement comprises a profiled outer surface provided on at least one of the upper section of the wellhead or the lower section of the wellhead,wherein the clamping arrangement further comprises a set of radially movable clamping dogs that are housed within the other of the at least one of the upper section of the wellhead or the lower section of the wellhead,wherein the radially movable clamping dogs are configured to engage with and clamp against said profiled outer surface.

19. A tensioning system as claimed in claim 18, wherein the profiled outer surface is defined by at least one circumferentially extending groove, wherein the radially movable clamping dogs are provided with at least one corresponding circumferentially extending projection on a surface thereof, wherein the circumferentially extending projection of each clamping dog is configured to contract around the or each corresponding circumferentially extending groove of the profiled surface such that the annular projection of the radially movable clamping dogs fully engages with the annular groove thereby clamping the axially adjacent sections of the wellhead together.

20. A tensioning system as claimed in claim 18 or claim 19,wherein the radially movable clamping dogs are provided in a circumferential arrangement, andwherein the radially movable clamping dogs are aligned such that they share a central axis, said central axis projecting through the centre of the circumferentially extending groove(s) of the profiled surface, thus allowing each of the radially movable clamping dogs to radially move and impinge upon the circumferentially extending groove(s) of the profiled surface equally.

21. A tensioning system as claimed in any of claims 18 to 20, wherein the clamping arrangement further comprises a threaded configuration configured to translate the rotational movement of the radially movable clamping dogs into radial movement of the of the radially movable clamping dogs.

22. A tensioning system as claimed in any of claims 14 to 21 ,wherein the one or more engaging profiles provided on the at least one radially moveable locking member includes a set of circumferentially extending annular projections,wherein the one or more engaging profiles of the locking means also includes a corresponding set of circumferentially extending grooves,wherein said circumferentially extending annular projections are configured to move into engagement with said corresponding circumferentially extending grooves during the locking process to axially lock the casing relative to the surface after the casing has been tensioned.

23. A tensioning system as claimed in claim 22, wherein the circumferentially extending grooves are axially spaced, and wherein the circumferentially extending annular projections are axially spaced.

24. A tensioning system as claimed in claim 22 or 23, wherein the radially moveable locking members and the circumferentially extending annular projections provided thereon are configured to move into engagement with the circumferentially extending grooves of the casing during the locking process to thereby axially lock the casing in place.

25. A tensioning system as claimed in any of claims 14 to 24, wherein the locking mechanism further comprises an actuating sleeve member for contacting, axially moving and thereby radially moving the radially movable locking members into engagement with the outer surface of the casing.

26. A tensioning system as claimed in claim 25, wherein the actuating sleeve is aligned with the radially moveable locking members such that they share a central axis projecting through the centre of the circumferential arrangement of radially moveable locking members and the actuating sleeve thus allowing the actuating sleeve to axially move and impinge upon each of the radially moveable locking members equally.

27. A tensioning system as claimed in any of claims 25 to 26, wherein, when the system comprises a wellhead housing, an inner surface of the wellhead housing includes a tapered surface, and wherein the radially moveable locking members also comprises a tapered face(s) which corresponds with said tapered face of the inner surface of the wellhead housing.

28. A tensioning system as claimed in claim 27, wherein the or each of the tapered faces of the radially moveable locking members taper from a first dimension to a second dimension thereof such that in use the tapered face of the radially moveable locking member engages and pushes against the corresponding tapered face of the inner surface of the wellhead.

29. A tensioning system as claimed in any of claims 25 to 28, wherein the locking mechanism further comprises a screw thread configuration configured to translate the rotational movement of the actuating sleeve into:axial movement of the actuating sleeve, andradial movement and locking of the radially moveable locking members thereafter.

30. A tensioning system as claimed in claim 29, wherein the sleeve member comprises a threaded profile on an outer surface thereof, and a portion of the inner surface of the wellhead includes a threaded profile corresponding to said threaded profile on the outer surface of the sleeve member.

31. A tensioning system as claimed in any of claims 14 to 30, wherein the casing comprises a casing head portion and a casing body portion, and wherein a lower endof the head portion is connected to an upper end of the body portion to form the casing, wherein the lower end of the head portion is connected to the upper end of the body portion.

32. A tensioning system as claimed in claim 31 , wherein an upper end of the body portion includes a frustoconical outer peripheral surface, wherein a lower end of the head portion includes frustoconical inner peripheral surface, and wherein said frustoconical outer peripheral surface corresponds to said frustoconical inner peripheral surface, wherein said frustoconical inner and outer peripheral surface are configured to engage telescopically with one another such that they overlie one another when the upper end of the body portion is inserted into the lower end of the head portion.

33. A tensioning system as claimed in claim 32, wherein one of the frustoconical outer peripheral surface and the frustoconical inner peripheral surface comprises axially spaced circumferentially extending grooves in its frustoconical surface, and wherein the other comprises corresponding axially spaced circumferentially extending annular projections or teeth in its frustoconical surface, wherein said circumferential grooves and corresponding teeth are configured to resist axial forces and ensure metal-to-metal contact.

34. A tensioning system as claimed in claim 33, wherein a radial passage is provided communicating with an axially extending recess intersecting at least some of the grooves centrally of the groove region, wherein said radial passage is adapted for connection to a source of liquid.

35. A casing for a borehole, the casing comprising an upper end and a lower end, the upper end of the casing having an attachment means for attachment to a tension pulling means,wherein the lower end of the casing is securable within the well, wherein the upper end of the casing further comprises a locking means for attachment to a locking mechanism to permit the upper end of the casing to be locked within a borehole in a tensioned state, andwherein the locking means comprises one or more engaging profiles provided on the outer surface at the upper end of the casing, andwherein the said one or more engaging profiles provided on the outer surface at the upper end of the casing corresponds to one or more engagement profiles formed on a contact surface of a radially moveable locking member of the locking mechanism.

36. An apparatus for locking tension into a tensioned casing, the apparatus comprising:a radially moveable locking member comprising a contact surface having one or more engaging profiles formed thereon;wherein the said one or more engaging profiles formed on the contact surface of the radially moveable locking member corresponds to one or more engagement profiles of a locking means provided on the outer surface at the upper end of the casing.

37. A method of extracting energy resource, comprising the steps of:tensioning a casing in accordance with the method of any of claims 1 to 13; andextracting energy resource through the casing.

38. A method of generating electricity, comprising the steps of:tensioning a casing in accordance with the method of any of claims 1 to 13; extracting energy resource; andgenerating electricity from said extracted energy resource.

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