Patent ID: 12196051

DETAILED DESCRIPTION

An example of a prior art wellhead system is shown inFIG.1. The wellhead system includes a wellhead10(only the upper portion of which is shown) which is positioned at the top of a well bore (not shown). The wellhead10comprises a central bore12within which a number of casing hangers are landed, including an uppermost casing hanger14(only the upper portion of which is shown). The top of the casing hanger14is configured as a seat16on which a tubing hanger18is landed. The tubing hanger18includes a cylindrical body20and a load nut22which is threadedly connected to the body. The load nut22comprises a load shoulder24which engages the seat16when the tubing hanger18is landed in the wellhead10.

The tubing hanger18is secured to the wellhead10using a suitable lockdown mechanism. In the example shown inFIG.1, the lockdown mechanism includes a lock ring or a number of expandable locking dogs26which are supported on a lockdown ring28that is connected to the tubing hanger body20. After the tubing hanger18is landed in the wellhead10, a locking mandrel30is actuated to drive the locking dogs26into a locking profile32which is formed in the central bore12. This action forces a number of axially spaced, circumferential locking ridges26aformed on the locking dogs26into a corresponding number of axially spaced, circumferential locking ridges32aformed in the locking profile32to thereby secure the tubing hanger to the wellhead.

As discussed above, in order to ensure that the tubing hanger18is properly locked to the wellhead10, the vertical distance between the load shoulder24and the locking dogs26must be the same as the vertical distance between the seat16and the locking profile32(i.e., the wellhead space-out). The wellhead space-out may be determined using, e.g., a lead impression tool (LIT). In the wellhead system shown inFIG.1, for example, the LIT would be lowered on a drill string and landed on the seat16. The LIT would then be actuated to press a number of circumferentially spaced lead impression pads into the locking profile32. After the impressions are taken, the LIT would be retrieved to the surface and mounted on a storage/test stand, which would then be manually adjusted to match the LIT. After this step, the tubing hanger18would be mounted on the storage/test stand and the load nut22would be manually rotated until the vertical distance between the load shoulder24and the locking dogs26is the same as the vertical distance between the seat and the locking profile. As may be apparent, this method for determining the wellhead space-out and adjusting the load nut until the vertical distance between the load shoulder and the locking dogs is the same as the wellhead space-out is a relatively time consuming process.

In accordance with the present disclosure, a tubing hanger and adjustable load nut assembly is provided which enables the vertical spacing between the load shoulder and the locking dogs to be adjusted automatically. As a result, the need to measure the wellhead space-out and adjust the position of the load nut before the tubing hanger is run into the wellhead is eliminated, which greatly reduces the time required to install the tubing hanger.

An illustrative embodiment of a tubing hanger and adjustable load nut assembly of the present disclosure is shown inFIG.2. InFIG.2, the tubing hanger, which is indicated generally by reference number100, is shown landed and locked, but not yet pre-tensioned, in a representative wellhead10. Similar to the example described above in connection withFIG.1, the wellhead10comprises a central bore12within which a number of casing hangers are landed, including an uppermost casing hanger14(only the upper portion of which is shown). In this example, the top of the casing hanger14is configured as an upward facing seat16on which the tubing hanger100is landed.

Referring also toFIG.5, the tubing hanger100includes an axially extending body102comprising an annular outer surface. A load nut104is threadedly connected to the body102and includes a downward facing load shoulder106which engages the seat16when the tubing hanger100is landed in the wellhead10. Due to the threaded connection between the load nut104and the body102, rotation of the load nut relative to the body will result in axial displacement of the load nut relative to the body.

The tubing hanger100is secured to the wellhead10by engagement of interacting lockdown features on the tubing hanger and the wellhead. The lockdown features may comprise any suitable means for securing the tubing hanger to the wellhead. For example, the wellhead may comprise a locking profile in the central bore which is engaged by a lock ring carried on the tubing hanger or on a separate lockdown mandrel or similar device. As another example, the tubing hanger may comprise a locking profile on the outer surface which is engaged by a number of locking pins or similar devices mounted on the wellhead.

In the example shown inFIG.2, the tubing hanger lockdown feature comprises a number of expandable locking dogs108which are supported on a lockdown ring110that is connected to the tubing hanger body. Alternatively, the locking dogs may be supported directly on the tubing hanger body102. Also, the wellhead lockdown feature comprises a locking profile32which is formed in the central bore12. As with the locking dogs26described above, the locking dogs108in this example embodiment comprise a number of axially spaced, circumferential locking ridges108awhich are configured to be received in the axially spaced, circumferential locking grooves32aof the locking profile32. In this example, after the tubing hanger100is landed in the wellhead10, a locking mandrel112is actuated to drive the locking ridges108ainto the locking grooves32ato thereby secure the tubing hanger to the wellhead.

As discussed above, in order to ensure that the tubing hanger100is properly locked to the wellhead10, the vertical distance between the load shoulder106and the locking dogs108must be the same as the vertical distance between the seat16and the locking profile32. In the prior art, the vertical distance between the load shoulder106and the locking dogs108was adjusted manually. In accordance with the present disclosure, after the tubing hanger100is landed and locked in the wellhead10, and preferably also pre-tensioned from above, the vertical distance between the load shoulder106and the locking dogs108is adjusted automatically using a novel torsion spring arrangement.

Referring also toFIG.4, the torsion spring arrangement includes a torsion spring114which is operatively engaged between the tubing hanger body102and the load nut104. The torsion spring114is a helically wound member which comprises a radially inwardly extending first end116that is secured to the tubing hanger body102and a radially outwardly extending second end118that is secured to the load nut104. In the illustrative embodiment of the invention shown in the drawings, the first end116may be received in a corresponding first hole120which is formed in the tubing hanger body102and the second end118may be received in a corresponding second hole122which is formed in the load nut104. In addition, the torsion spring114may be positioned in a circumferential recess124which is formed in the inner diameter surface of the load nut104(but may alternatively be formed in the outer diameter surface of the tubing hanger body102).

During assembly of the tubing hanger100, the load nut104is threaded onto the tubing hanger body102until it reaches an initial or upper position, which is shown inFIGS.4and5. As the load nut104is threaded onto the tubing hanger body102, the torsion spring114is wound from a relaxed state to a torqued state. In this position, mechanical energy is stored in the torsion spring114which will generate a torque on the load nut104that will cause the load nut to rotate relative to the tubing hanger body102. Due to the threaded connection between the load nut104and the body102, this rotation will displace the load nut axially downward relative to the body and thereby increase the vertical distance between the load shoulder106and the locking dogs108.

In order to maintain the torsion spring114in its torqued state, the tubing hanger100also includes means for preventing the load nut104from rotating relative to the tubing hanger body102until after the tubing hanger is landed in the wellhead10. Referring toFIG.4, for example, the tubing hanger and adjustable load nut assembly may include a latching mechanism126which is positioned in the tubing hanger body102and a de-latching mechanism128which is positioned in the load nut104. In this example, the latching mechanism126comprises a latch member130which is slidably positioned in a bore132that is formed in a portion of the tubing hanger body102located proximate the upper surface of the load nut104. The latch member130may be maintained in the bore132by a suitable gland nut134and may be biased toward the load nut104by a compression spring136. The latch member130may also include an alignment pin138which extends vertically into a guide bore140that is formed in the tubing hanger body102.

In this example, when the load nut104is in its initial position, a distal end142of the latch member130will be positioned in a corresponding groove144formed in the upper surface of the load nut. In this position, the spring136will bias the latch member130toward the load nut104with sufficient force to maintain the distal end142of the latch member fully engaged in the groove144and thus prevent the torsion spring114from rotating the load nut relative to the tubing hanger body102.

In the illustrative embodiment shown inFIG.4, the de-latching mechanism128functions to force the distal end142of the latch member130out of the groove144when the tubing hanger100lands in the wellhead10. As shown inFIG.4, the de-latching mechanism128may comprise an axially stiff but radially flexible rod146which is positioned in an axially extending through bore148formed in the load nut104. The rod146includes a first end146awhich is located proximate the bottom of the groove144and a second end146bwhich extends a distance below the load shoulder106. In this manner, when the tubing hanger100lands in the wellhead10, the seat16(not shown inFIG.4) will contact the second end146band force the rod146axially upwardly, and the first end146awill in turn force the distal end142of the latch member130out of the groove144, thus permitting the load nut104to rotate relative to the tubing hanger body102as the torsion spring114unwinds.

During installation, the tubing hanger100is connected to a drill string and lowered from a surface vessel toward the wellhead10. The tubing hanger100is lowered into the wellhead10until the load shoulder106on the adjustable load nut104lands on the seat16at the top of the casing hanger14. As shown inFIG.2, this action will force the rod146upward and displace the distal end142of the latch member130from the groove144. In this position, the weight of the tubing hanger100and its depending tubing string (not shown) acting on the casing hanger14will prevent the torsion spring114from unwinding and rotating the load nut104relative to the tubing hanger body102. The tubing hanger100is then locked to the wellhead by forcing the locking dogs108into the locking profile32.

Once the tubing hanger100is locked to the wellhead10, tension is applied to the drill string to lift the tubing hanger upward until the upper facing portions of the locking ridges108aare fully loaded against the corresponding downward facing portions of the locking grooves32a. During this process, the load nut104is lifted off of the landing seat106. Since the latch member130is no longer engaged with the groove144in the top of the load nut104, the torsion spring114will force the load nut to rotate downward relative to the tubing hanger body102until the landing shoulder106is once again fully engaged with the landing seat106. This is the position of the load nut104shown inFIGS.3and6. In this position, the locking dogs108will be fully preloaded with the locking grooves32, thus minimizing possible fretting of the metal tubing hanger annulus seals (not shown) due to the development of thermal gradients during production startups and shutdowns.

In other embodiments, the latching and de-latching mechanisms may take different forms from those described above. For example, the latch member130may be mounted on the load nut104and be biased by a spring136or other suitable means into engagement with a corresponding groove formed in the tubing hanger body102. In this example, the de-latching mechanism may comprise a rod or pin which is linked to the latch member130and which functions to retract the latch member from the groove when the rod or pin engages the seat16or a corresponding feature in the central bore12of the wellhead10.

In another example, the latch member130shown inFIG.4may be sealed to the bore132in the manner of a piston. In this example, the de-latching mechanism may comprise a source of pressurized fluid which is located on, e.g., a surface vessel or a tubing hanger running tool which is used to install the tubing hanger100. The source of pressurized fluid may be operationally connected to the latch member130via a conduit in the tubing hanger running tool which is connected to a corresponding conduit in the tubing hanger body102that in turn is connected to the bore132(or the alignment bore140). In operation of this embodiment, once the tubing hanger100is landed on the seat16, a negative pressure from the source of pressurized fluid is applied to the bore132to retract the latch member130from the groove144.

In a variation of this embodiment, the spring136may be removed and the source of pressurized fluid may be used to both extend the latch member130into the groove144(by applying a positive pressure to the bore132) and retract the latch member from the groove144(by applying a negative pressure to the bore132).

In a further variation, the spring136may comprise an extension spring which functions to retract the latch member130from the groove144. In this example, the source of pressurized fluid may be used to maintain the latch member in the groove until the tubing hanger100is landed on the seat16, at which point the pressure can be released to allow the latch member130to retract from the groove.

In a further embodiment, the latching and de-latching mechanisms may comprise a number of shear pins or the like which are connected between the load nut104and the tubing hanger body102.

Although the torsion spring arrangement has been described herein in the context of a tubing hanger which is landed on a casing hanger supported in a wellhead, it should be understood that it could be used in other applications, either within or outside of the field of subsea hydrocarbon production systems. In the field of subsea hydrocarbon production systems, for example, the torsion spring arrangement could be used to obtain proper spacing between any tubular hanger and any component within which the tubular hanger is landed, such as, e.g., a tubing spool or tubing head.

More generally, the present disclosure provides a torsion spring arrangement for use in securing an inner member to an outer member which surrounds at least a portion of the inner member. In one embodiment, the outer member comprises first and second axially spaced outer features and the inner member comprises first and second axially spaced inner features which are configured to engage the outer features to secure the inner member to the outer member. The first inner feature is formed on a component which is threadedly connected to the inner member, and the torsion spring arrangement is operable to rotate the component to thereby move the first inner feature axially relative to the inner member until the first and second inner features engage the first and second outer features, respectively, to secure the inner member to the outer member. Alternatively, the first outer feature may be formed on a component which is threadedly connected to the outer member, and the torsion spring arrangement may be operable to rotate the component to thereby move the first outer feature axially relative to the outer member until the first and second inner features engage the first and second outer features, respectively, to secure the inner member to the outer member.

It should be recognized that, while the present disclosure has been presented with reference to certain embodiments, those skilled in the art may develop a wide variation of structural and operational details without departing from the principles of the disclosure. For example, the various elements shown in the different embodiments may be combined in a manner not illustrated above. Therefore, the following claims are to be construed to cover all equivalents falling within the true scope and spirit of the disclosure.