Connector system

Abstract

A subsea connector system (10) for providing a connection with a subsea well component comprises a latch assembly (14) defining a through bore and a latch member (18) mounted on the latch assembly. A mandrel (20) extends through said bore of the latch assembly, wherein the mandrel and the latch assembly are axially and rotatably moveable relative to each other in a predefined relative movement sequence to operate the latch member and configure the connector system between connected and disconnected configurations. The connector system also comprises a conveyance connector (22) for providing a connection between a conveyance member (24) and the mandrel such that a conveyance member may permit an axial movement component of the predefined movement sequence. A rotation interface (26) is mounted on one of the mandrel and the latch assembly such that a subsea manipulator may permit a rotational movement component of the predefined relative movement sequence.

Claims

1. A subsea connector system for providing a connection with a subsea well component, the connector system comprising: a latch assembly defining a through bore; a latch member mounted on the latch assembly and being moveable between a latch configuration and an unlatch configuration to facilitate connection and disconnection with the subsea well component; a mandrel extending through the through bore of the latch assembly, wherein the mandrel and the latch assembly are axially and rotatably moveable relative to each other in a predefined relative movement sequence to operate the latch member and configure the connector system between connected and disconnected configurations; a conveyance connector for providing a connection between a conveyance member and the mandrel such that the conveyance member is configured to permit an axial movement component of the predefined movement sequence; and a rotation interface provided separately from the conveyance connector and mounted on one of the mandrel and the latch assembly such that a subsea manipulator is configured to permit a rotational movement component of the predefined relative movement sequence, wherein the rotation interface comprises an engagement arm extending generally radially relative to one of the latch assembly and the mandrel, the engagement arm configured to engage the subsea manipulator to permit torque to be transmitted to one of the latch assembly and the mandrel.

2. The subsea connector system according to claim 1, wherein the rotation interface is provided on the mandrel such that the mandrel is moveable by the subsea manipulator relative to the latch assembly.

3. The subsea connector system according to claim 1, wherein the mandrel comprises a drive profile for engaging and operating the latch member and permitting said latch member to be reconfigured between the latch and unlatch configurations during relative movement between the mandrel and the latch assembly.

4. The subsea connector system according to claim 1, wherein at least one rotational movement component of the predefined relative movement sequence increases a connection force applied against the subsea well component.

5. The subsea connector system according to claim 1, wherein the predefined movement sequence comprises a first axial component, a subsequent first rotational component, a subsequent second axial component and a subsequent second rotational component.

6. The subsea connector system according to claim 5, wherein the first axial component and subsequent first rotational component provide movement from an initial running configuration, the second axial component facilitates reconfiguring of the latch member to the latch configuration, and the second rotational component provides locking of the connector system in the connected configuration.

7. The subsea connector system according to claim 6, wherein the second rotational component further provides a connection preload.

8. The subsea connector system according to claim 1, comprising an interface assembly provided between the latch assembly and the mandrel for prescribing the predefined relative movement sequence between the mandrel and the latch assembly, wherein the interface assembly comprises a track arrangement comprising at least one track portion provided on one of the latch assembly and the mandrel, and a dog arrangement comprising at least one dog provided in the other of the latch assembly and the mandrel, wherein interaction of the dog arrangement with the track arrangement provides the predefined movement sequence between the mandrel and the latch assembly.

9. The subsea connector system according to claim 8, wherein the track arrangement defines a pocket, wherein the dog of the dog arrangement is received within said pocket when the connector system is in the disconnected configuration.

10. The subsea connector system according to claim 9, wherein the pocket provides an axial and rotational connection between the mandrel and the latch assembly such that the latch assembly is configured to be suspended from the mandrel with relative rotation therebetween restricted.

11. The subsea connector system according to claim 9, wherein the pocket is arranged such that relative axial movement between the mandrel and latch assembly is required to remove the dog from the pocket, followed by relative rotational movement to misalign the dog and the pocket.

12. The subsea connector system according to claim 1, comprising a secondary locking arrangement for providing locking of the latch member in the latch configuration.

13. The subsea connector system according to claim 1, wherein the latch member is pivotally mounted on the latch assembly and arranged to pivot to selectively engage and disengage the subsea well component.

14. The subsea connector system according to claim 1, comprising a tool assembly connector for providing a connection with a tool assembly, wherein the tool assembly comprises at least one of a rotary tool assembly, a cutting tool assembly, and a sealing tool assembly.

15. The subsea connector system according to claim 1, comprising a sealing tool assembly for providing a seal within the well component, wherein the sealing tool assembly is supported by the mandrel.

16. The subsea connector system according to claim 1, wherein the mandrel defines an entry orifice, an exit orifice and a cavity extending therebetween to facilitate passage of a conduit, wherein the entry orifice is positioned on one side of the latch assembly, and the exit orifice is positioned on an opposite side of the latch assembly.

17. A method for establishing a connection with a subsea well component, comprising: positioning a latch assembly relative to the well component; establishing relative movement in a predefined relative movement sequence between a mandrel and the latch assembly to operate a latch member mounted on the latch assembly to move to engage the well component, wherein the predefined relative movement sequence comprises: at least one axial component provided by a conveyance connector for providing a connection between a conveyance member and the mandrel, and at least one rotational component provided by a subsea manipulator engaged with a rotation interface mounted on one of the mandrel and the latch assembly, wherein the rotation interface is separate from the conveyance connector.

18. The method according to claim 17, comprising engaging the subsea manipulator with an engagement arm which extends generally radially relative to one of the latch assembly and the mandrel, and operating the subsea manipulator to rotate one of the latch assembly and the mandrel via the engagement arm.

19. The method according to claim 17, comprising engaging the subsea manipulator with the rotation interface provided on the mandrel and rotating the mandrel with the subsea manipulator.

20. The method according to claim 17, comprising increasing a connection force applied against the subsea well component during the at least one rotational component of the predefined relative movement sequence.

21. The method according to claim 17, wherein the predefined movement sequence comprises a first axial component, a subsequent first rotational component, a subsequent second axial component and a subsequent second rotational component.

22. The method according to claim 21, comprising: reconfiguring the latch assembly and the mandrel from an initial running configuration during the first axial component and subsequent first rotational component; reconfiguring the latch member to engage the well component during the second axial component; and locking the latch member in engagement with the well component during the second rotational component.

23. The method according to claim 17, comprising activating a secondary locking arrangement to retain the latch member in engagement with the well component.

24. The method according to claim 17, comprising providing a seal within the well component using a sealing tool supported by the mandrel.

25. A subsea tool system, comprising: a latch assembly defining a through bore; a latch member mounted on the latch assembly and being moveable between a latch configuration and an unlatch configuration to facilitate connection and disconnection with a subsea well component; a mandrel extending through the through bore of the latch assembly, wherein the mandrel and the latch assembly are axially and rotatably moveable relative to each other in a predefined relative movement sequence to operate the latch member and facilitate connection and disconnection with the subsea well component; a conveyance connector for providing a connection between a conveyance member and the mandrel such that the conveyance member is configured to permit an axial movement portion of the predefined movement sequence; a rotation interface provided separately from the conveyance connector and mounted on one of the mandrel and the latch assembly such that a subsea manipulator is configured to permit a rotational movement portion of the predefined relative movement sequence; wherein the rotation interface comprises an engagement arm extending generally radially relative to one of the latch assembly and the mandrel, the engagement arm configured to engage the subsea manipulator to permit torque to be transmitted to one of the latch assembly and the mandrel; and a tool assembly connected to the mandrel.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) These and other aspects and embodiments will now be described, by way of example only, with reference to the accompanying drawings, in which:

(2) FIG. 1 is a side elevation view of a subsea mechanically actuation connector system, illustrated in a connected state with a well component;

(3) FIG. 2 is a cross-section view of the connector system taken along line 2-2 of FIG. 1;

(4) FIG. 3 is a perspective view, from below, of a bonnet member of the connector system of FIG. 1;

(5) FIG. 4 is a side elevation view of a mandrel portion of the connector system of FIG. 1;

(6) FIG. 5 is a cross-section view of the mandrel portion taken along line 5-5 of FIG. 4;

(7) FIG. 6 is a side elevation view of a rotation lock ring of the connector system of FIG. 1;

(8) FIG. 7 is a cross-section view of the rotation lock ring taken along line 7-7 of FIG. 6;

(9) FIGS. 8 to 21 provide an illustration of a sequence for providing a connection between the connector system of FIG. 1 and a well component; and

(10) FIGS. 22 to 32 provide exemplary uses of the connection system of FIG. 1.

DETAILED DESCRIPTION OF THE DRAWINGS

(11) FIG. 1 provides a side elevation view of a subsea connector system, generally identified by reference numeral 10, shown connected with a subsea well component 12. The subsea well component 12 may be any subsea component, such as a well head, Xmas tree or the like. The connector system 10 comprises a latch assembly 14 which mounts over a rim 16 of the well component 12 and includes a plurality of latch members 18 (only one visible in FIG. 1) which pivot to engage the rim 16 of the well component 12 to provide a connection therewith.

(12) The connector system 10 further includes a mandrel 20 which is coupled to the latch assembly 14 and includes a conveyance connector 22 in the form of a shackle which provides connection to a conveyance member 24, specifically wire rope in the present embodiment. The conveyance member 24 extends from a surface vessel (not shown) and is used to trip the connector system 10 to/from the vessel. The conveyance member 24 may also be used to control a relative axial movement between the mandrel 20 and the latch assembly 14.

(13) A pair of rotation arms 26 (only one visible in FIG. 1) are secured to the mandrel 20, and in use permit an ROV (not shown) to engage one or both arms 26 and cause relative rotation between the mandrel 20 and the latch assembly 14.

(14) As will be described in more detail below, a connection with the well component 12 may be made and broken by establishing relative movement between the mandrel 20 and the latch assembly 14 in a predefined relative movement sequence comprising at least one axial component under the control of the conveyance member 24, and at least one rotational component under the control of an ROV engaging one or both arms 26.

(15) FIG. 2 provides a cross-sectional view of the connector system 10, taken along line 2-2 of FIG. 1. The mandrel 20 extends through a through bore 28 of the latch assembly 14, and includes an upper mandrel section 20a and a lower mandrel section 20b secured together by a threaded connection 30, such that the lower mandrel section 20b establishes an axial shoulder 32.

(16) The latch members 18 are provided in the form of L-shaped arms and are each pivotally mounted, via fulcrum members 34, on the latch assembly 14, such that the latch members 18 may be moveable in a rocking motion. Each latch member 18 includes a profiled engagement portion 36 which is arranged to engage, generally from below, a corresponding engagement profile 38 on the rim 16 of the well component 12.

(17) The latch members 18 also each comprise a drive portion 40 which is engaged by the axial shoulder 32 of the mandrel 20 such that upward movement of the mandrel 20 relative to the latch assembly 14 drives the latch members 18 to pivot and grip the rim 16. As the engagement portions 36 of the latch members 18 generally grip the rim 16 from below, this may have the effect of pressing the latch assembly 14 and the rim 16 together, for example in region 42, which may provide a preload within the connection. Such a preload may provide a reaction against relative axial and rotational movement between the latch assembly 14 and the well component 12. Downward movement of the mandrel 20 relative to the latch assembly 14 may permit the latch members 18 to be desupported, and thus remove their grip on the rim 16. In this respect a collar 44 is mounted on the mandrel 20 above the latch assembly 14 to limit downward movement of the mandrel 20 relative to the latch assembly 14.

(18) As noted above, relative axial movement of the mandrel 20 in reverse directions relative to the latch assembly 14 may permit operation of the latch members 18. However, as will be described in more detail below, such axial movement is only a component of a required predefined movement sequence, with rotational movement also required to facilitate a complete connection and disconnection operation. In this respect the connector system 10 further comprises an interface arrangement 46 between the mandrel 20 and latch assembly which prescribes the required movement sequence by only permitting relative movement in the predefined sequence. In the present embodiment the interface arrangement 46 includes a track arrangement 48 provided on the latch assembly 14, and a dog assembly 50 provided on the mandrel 20. The form and interaction of the track arrangement 48 and dog assembly 50 will be described in detail below. The interface arrangement 46 also includes a limit ring 52, which, as will be described in more detail below, permits relative axial and rotational movement between the mandrel 20 and latch assembly 14 to be limited.

(19) The mandrel 20 further includes an upper orifice 11 provided in a side wall thereof above the latch assembly 14, and a lower orifice 13 provided in a lower end thereof below the latch assembly 14, with an internal bore 15 extending partially through the mandrel to connect the upper and lower orifices 11, 13. As will be described in further detail below, the orifices 11, 13 and bore 15 provide a duct arrangement to permit one or more conduits to be directed through the mandrel 20, past the latch assembly 14.

(20) FIG. 3 provides a perspective view, from below, of a portion of the latch assembly 14, with the mandrel 20 and latch members 14 removed for clarity. The track arrangement 48 includes three identical tracks 60 arranged circumferentially within the through bore 28 of the latch assembly 14. Each track 60 includes a first track portion 62 which extends generally circumferentially, a second track portion 64 which extends generally axially, and a third track portion 66 which extends generally circumferentially. The first track portion 62 is defined by a single track edge 62. The second track portion 64 is defined between a pair of track edges 64a, 64b and is thus provided in the form of an axial slot. The third track portion 66 is defined between a pair of track edges 66a, 66b and is thus provided in the form of a circumferential slot.

(21) The first track portion 62 of each track 60 includes a recess or pocket 70.

(22) The track arrangement 48 also includes three rotation stop members 72.

(23) FIG. 4 provides a side elevation view of the lower mandrel section 20b, in isolation, and FIG. 5 is a sectional view, taken along line 5-5 in FIG. 4. The lower mandrel section 20b includes or defines the dog assembly 50 and comprises an upper cylindrical portion 80 and a lower enlarged portion 82 with an axial shoulder 84 defined therebetween. The upper cylindrical portion 80 includes three evenly distributed dogs 86 which are sized and arranged to engage the various tracks 60 of the track assembly 48 (FIG. 3). The upper cylindrical portion 80 also includes three evenly distributed locator lugs 88 which function to rotatably secure the limit ring 52 (FIG. 2) to the lower mandrel section 20b.

(24) A side elevation view of the limit ring 52, in isolation, is shown in FIG. 6, with a sectional view, taken along line 7-7 of FIG. 6 provided in FIG. 7. The limit ring 52 includes a base ring portion 90 and three evenly distributed limit rib members 92 axially extending upwardly from the base ring portion 90. Three locator slots 94 (only 2 visible in FIG. 7) are provided on the inner surface of the base ring portion 90. The limit ring 52 may be mounted over the upper cylindrical portion 80 of the lower mandrel section 20a (see, e.g., FIG. 4) with the locator slots 94 of the base ring 90 allowing the limit ring 52 to pass the dogs 86. The limit ring 52 may then rest on the axial shoulder 84, with the locator lugs 88 received within the locator slots 94, thus rotationally securing the limit ring 52 to the lower mandrel section 20b.

(25) An operational sequence will now be described in detail with reference to FIGS. 8 to 21.

(26) Reference is first made to FIGS. 8 and 9, wherein FIG. 8 is a part cut-away perspective view of the connector system 10 being initially deployed via conveyance member 24, for example from a surface vessel and through a depth of water towards the seabed. FIG. 9 is an enlarged view showing the corresponding configuration of the interface arrangement 46. In this configuration the dogs 86 of the lower mandrel section 20b are received within the respective pockets 70 of each track 60, such that the latch assembly 14 is effectively suspended from the mandrel 20, with the weight of the latch assembly 14 carried by the mandrel 20 via the dogs 86. When in this configuration the mandrel 20 and latch assembly 14 are positioned such that the latch members 18 are axially separated from the shoulder 32 on the mandrel 20, and thus are in an unlatch or free configuration.

(27) FIG. 10 illustrates the connector system 10 upon initial engagement with the rim 16 of the well component, with FIG. 11 providing an enlarged view of the corresponding configuration of the interface arrangement 46. In this configuration the weight of the latch assembly 14 is transferred to the well component 14, with the conveyance member 24 slightly lowering the mandrel 20 relative to the latch assembly 14, thus moving the dogs 86 out of the respective pockets 70 of the tracks 60.

(28) Subsequent to this, as illustrated in FIGS. 12 and 13, the mandrel 20 is rotated, in an anti-clockwise direction (for example by around 60 degrees of rotation), relative to the latch assembly 14, by use of an ROV (not shown) engaging one or both of the arms 26. Such rotation moves the dogs 86 along the respective first track portion 62 of each track 60 until the dogs 86 become aligned with the second track portion 64. In this respect over-rotation is prevented by engagement between the dogs 86 and the rotation stop members 72.

(29) Subsequent to this, as illustrated in FIGS. 14 and 15, the mandrel 20 is lifted axially by the conveyance member 24, moving the dogs 86 into the second track portions 64 of the respective tracks 60, thus engaging the shoulder 32 against the latch members 18 and causing said members 18 to pivot and initially engage the rim 16 of the well component 12.

(30) As illustrated in FIGS. 16 and 17, now that initial engagement is made between the latch members 18 and the well component 12, axial tension within the conveyance member 24 can be increased, causing further axial movement of the mandrel 20, increasing the pressing force of the latch members 18 against the rim 16 of the well component 12 and moving the dogs 86 further into the respective second track portions 64, establishing a preload between the latch assembly 14 and the well component 12.

(31) Following this, as illustrated in FIGS. 18 and 19, the mandrel 20 may be again rotated by the ROV (not shown) in an anti-clockwise direction (for example by around 60 degrees of rotation), such that the dogs 86 are now moved into and along the third track portions 66 of the respective adjacent tracks 60 (not visible in FIG. 18 or 20see FIG. 3). In this respect, upper track edge 66a of each third track portion 66 may provide a slight tapering surface, such that an additional axial force between the mandrel 20 and the latch assembly 14 may be created, to provide an additional preload within the connection. As illustrated in FIG. 19, the limit rib members 92 of the limit ring 52 engage the rotation stop members 72 of the track arrangement 48, thus preventing over-rotation.

(32) Once in the connected state, a secondary locking system may be operated, as illustrated in FIGS. 20 and 21. In this respect, the latch assembly 14 includes a locking pin 100 associated with each latch member 18. Each locking pin may be driven downwardly, by an ROV (not shown), to engage a top surface of a respective latch members 18.

(33) Thus, a connection with a subsea well component 12 may be made and/or broken by establishing a combination of relative rotational and axial movement between the latch assembly 14 and the mandrel 20 in the predefined relative movement sequence, by the combined use of a conveyance member 24, providing or permitting axial movement, and an ROV (not shown), providing or permitting rotational movement. Such an arrangement may provide a purely mechanically actuated connector system. This may minimise or eliminate potential problems associated with, for example, hydraulic systems, allowing the connector system 10 to have utility in both shallow and ultra-deep applications

(34) The requirement for a conveyance member 24 to only provide relative axial movement within the connector system 10 may permit simplified control of the conveyance member 24 via a surface vessel. In some embodiments this may avoid the necessity to utilise specialised, high cost and infrequently available vessels, and allow more ready use of vessels of opportunity, such as monohull vessels, mobile offshore drilling units and the like.

(35) Also, the requirement for an ROV (not shown) to only provide relative rotational movement within the connector system 10 may minimise the work requirement of the ROV, for example by avoiding or minimising the requirement for the ROV to take on any weight of the connector assembly 10 and/or associated equipment.

(36) By providing different components or portions of the predefined relative movement sequence by separate sources of control (the conveyance member 24 and the ROV), an additional degree of safety may be established in that a single control source is not entirely responsible, and a more involved or deliberate connection and/or disconnection procedure is required. This may minimise the risk of accidental disconnection, for example.

(37) The connector system 10 may be used in multiple applications, for example for use in deploying a well component from a vessel, for retrieving a well component to a vessel, for supporting an operation on a well component, or the like. Some example applications will now be described, with reference to FIGS. 22 to 31.

(38) Referring first to FIG. 22, the connector 10 is illustrated as forming part of a casing cutter system, generally identified by reference numeral 110, with the connector system 10 providing a connection to a wellhead 12. In this embodiment an abrasive cutter tool assembly 112 is suspended from the mandrel 20 via a flexible interface link 114. An umbilical 116 extends from surface and through the mandrel 20 to deliver power, for example hydraulic power to the abrasive cutter tool assembly 112. The cutter tool assembly 112 may generate a radially directed abrasive jet, with rotation of the cutter tool assembly 112 (for example via a mud motor 113) permitting casing strings 120, 122 suspended form the well head 12 to be cut at some location below the mudline 124.

(39) In an alternative embodiment, as shown in FIG. 23, the same abrasive cutter tool assembly 112 may be mounted to the mandrel via a rigid interface link 130.

(40) In further alternative embodiments other forms of cutting tool assembly may be provided. For example, FIG. 24 illustrates a perforation gun assembly 132 mounted to the mandrel 20 via a rigid interface 134. FIG. 25 illustrates a mechanical cutting tool assembly 136 mounted on the mandrel 20 via a flexible interface 138 and rotatable by mud motor 113 to permit cutting of the casing strings 120, 122. FIG. 26 illustrates the same cutting tool 136 mounted on drill pipe 140 which extends to surface and also provides the function of conveyance member 24 and a portion of the mandrel 20.

(41) In each of the embodiments in FIGS. 22 to 26, the cutting tool assembly facilitates cutting of casing strings 120, 122 below the mudline 124. This can permit the wellhead 12 and severed sections of casing strings 120, 122 to be retrieved, via the conveyance member 24, as illustrated in FIG. 27. This may form part of a well abandonment operation.

(42) The connector system 10 may also be utilised in well testing operations. For example, as illustrated in FIG. 28, the connector system 10 is connected to a wellhead 12 in the manner described above. In this case a sealing tool assembly 150 in the form of a pack off seal is mounted on and below the mandrel 20, such that a seal may be generated within the wellhead (or lower within the associated wellbore). An umbilical 152 extends from surface and through the mandrel 20, and is coupled to the sealing tool assembly 150. The umbilical 152 may deliver high pressure fluid through the sealing tool assembly 150 and into a wellbore space 154 below the sealing tool assembly 150. This pressurised fluid may be used to pressure test a lower established seal or plug 156, for example which may be used as a well abandon barrier.

(43) In some examples, following the test operation illustrated in FIG. 28, a cutting operation may be performed, such as illustrated in any one of FIGS. 22 to 26, to retrieve the wellhead 12.

(44) An example of a sealing tool assembly 150 is illustrated in FIGS. 29A and 29B. The sealing tool assembly 150, which is shown in partial cross section, is illustrated in a non-sealing configuration in FIG. 29A, and in a sealing configuration in FIG. 29B.

(45) In this example, the sealing tool assembly 150 includes a body 200 upon which is mounted a seal support 202 which defines a first support surface 204, a second support surface 206 of a larger diameter than the first support surface 204, and a ramp interface 208 therebetween. Although the seal support 202 is illustrated as being separately formed from the body 200, in an alternative arrangement part or all of the seal support 202 may be integrally formed with the body 200. A seal member 210, such as an elastomeric seal member, is mounted on the seal support 202. A hydraulic piston sleeve 212 is mounted on the body 200, and is operable to stroke in opposing axial directions by hydraulic pressure delivered via conduits 214, 216.

(46) When in the non-sealing configuration, as illustrated in FIG. 29A, the seal member 210 is positioned on the first support surface 204 of the seal support 202. When sealing is required, pressure is applied via conduit 214 to cause the piston sleeve 212 to stroke and drive the seal member 210 onto the second support surface 206, as illustrated in FIG. 29B.

(47) In one example the seal member 210 may be secured to the piston sleeve 212, to facilitate reconfiguration of the sealing tool assembly back to its non-sealing configuration.

(48) The sealing tool assembly 150 in the examples shown is provided separately from the mandrel 20 of the connector system. However, in other examples the sealing tool assembly may be provided as part of the connector system 10. For example, the sealing tool assembly 150 may form part of the lower mandrel section 20b (see, for example, FIG. 2).

(49) Other applications or uses of the connector system 10 may include deploying tools or equipment. One example is illustrated in FIG. 30, in which the connector system 10 is shown in the deployment of a subsea Xmas tree 160. In this case the Xmas tree 160 includes a re-entry mandrel 162 to which the connector assembly 10 is connected. A pack off seal assembly 164 is mounted below the mandrel 20 of the connector system 10, and in use establishes a seal within the re-entry mandrel 162. An umbilical 166 may extend through the mandrel 20 to provide a high pressure fluid connection to the pack off seal assembly 164. Such high pressure fluid may be communicated through the pack off seal assembly 164 and used in pressure testing within the Xmas tree 160 (for example pressure testing of various pressure barriers within the Xmas tree 160), and/or pressure testing within an associated wellbore.

(50) In an alternative embodiment shown in FIG. 31, the connection system 10 may include a tubular riser 170 which provides the function as a conveyance member 24 and also forms part of the mandrel 20. In such an embodiment the tubular riser 170 may deliver pressurised fluid into the Xmas tree 160 for pressure/wellbore testing.

(51) In a further alternative embodiment of FIG. 32, an alternative form of pack off sealing assembly 180 is provided which permits tripping through the tubular riser 170 and the pack of seal assembly 180 to permit crown plugs (not shown) within the Xmas tree 160 to be set and pulled. Such an embodiment may also permit pressure/wellbore testing.

(52) It should be understood that the embodiments described herein are merely exemplary and that various modifications may be made thereto without departing from the scope of the invention.