Most conventional tree systems have parallel bore conduits extending through the tree and tubing hanger, one for production flow and one for annulus communication. When a subsea tree is to be retrieved for repair it is necessary to close the conduits in the tubing hanger.

Normal practice is to set two plugs run on wireline; one set in the production bore and another set in the annulus bore.

Another known form of completion provides a valve in the annulus bore of the tubing hanger.

This has the dual advantages of saving time by eliminating the requirement to set an annulus plug and by removing the requirement for vertical access to the annulus. This is particularly advantageous when using a monobore riser, or for tree designs which do not permit wireline access to the tubing hanger annulus bore.

A monobore riser is often used for subsea completion and intervention operations. In this case, if the annulus valve fails to operate by its normal (hydraulic) means, then the monobore riser is brought back to the surface and reconfigured to allow the vertical bore of the riser to align with the generally vertical annulus bore in the tree. A contingency tool is then run on wireline to operate the valve. This procedure is compatible with tubing sizes up to about 140mm (5 1/2") internal diameter. Recent trends in the oil industry have led to a desire to have larger production conduits, for example 178mm (7")-I. D : To accommodate these, the configuration of the tree and tubing hanger needs to be changed, one such large bore tree and tubing hanger configuration being described in GB 2342668. A problem with such large bore completions is that if the valve actuation mechanism fails, there is no contingency operation available to open and close the valve by wireline, since the generally vertical annulus bore in the tree is eliminated.

Summary of the Invention The present invention allows tubing hanger valve actuation by wireline or similar mechanical means via the production bore, thereby maintaining the advantages of existing systems, whilst also allowing a larger production conduit. Such valve actuation may be the primary mode of operation, or may be used as a backup or contingency mode in case of failure of the primary valve actuation mechanism.

Accordingly, the present invention provides a completion comprising a tubing hanger having a production bore provided with wireline access, a passageway in the tubing hanger communicating between a tubing annulus below the tubing hanger and an annulus flow conduit in a Christmas tree, the tubing hanger co-operating with a valve closure element which can be moved by a tool received within the production bore, so as to control fluid flow within the passageway, characterised in that the annulus flow conduit is separated from the production bore by a seal stab extending between the tubing hanger and the Christmas tree.

The valve closure element may be a sleeve in the tubing hanger surrounding the production bore, for example sliding on an inner surface of the tubing hanger. Conveniently, a movable production seal stab moves the valve closure element. In this case, the valve closure element may be of the pressure-balanced type. An abutment surface on the seal stab may move the valve closure element in one direction. Locking dogs which selectively secure the valve closure element to the seal stab may be used to cause the closure element to move in the other direction. The seal stab (where present), or the valve closure element, may be moved by hydraulic pressure applied through a separate line to an hydraulic piston and cylinder.

Alternatively the seal stab (where present) or the valve closure element may be moved by pressure in the annulus flow conduit and/or the production bore.

In a further aspect, the invention thus provides a completion comprising a tubing hanger having a production bore provided with wireline access, a passageway in the tubing hanger communicating between a tubing annulus below the tubing hanger and an annulus flow conduit in a Christmas tree, the tubing hanger co-operating with a valve closure element which can be moved by a tool received within the production bore so as to control fluid flow

within the passageway, characterised in that the valve closure element slides on an inner surface of the tubing hanger and comprises a port selectively alignable with a corresponding port in the tubing hanger inner surface to control the fluid flow within the passageway; the tubing hanger production bore communicating with a seal stab depending from the Christmas tree, the valve closure element remaining accessible from the tubing hanger production bore for such sliding movement when the seal stab is in position.

In a preferred embodiment, a valve in the tubing hanger is arranged concentrically around a production seal stab between the tree and the tubing hanger. It is operated by motion of the production seal stab. In the primary mode, the seal stab is moved by hydraulically operated pistons. This arrangement is efficient in terms of the use of radial space and also allows the contingency operation of the valve by wireline. Commonly available wireline tools can be run to engage in a dedicated profile in the seal stab to operate the valve should this be required in contingency.

Further preferred features and advantages of the invention are in the following description of illustrative embodiments made with reference to the drawings.

Brief description of the Drawings Fig. 1 is a diagrammatic vertical section through a first preferred embodiment of the invention; Fig. 2 is a vertical section through a completion showing the overall configuration of a second preferred embodiment; Fig. 3 is a vertical section showing parts of Fig. 2 in more detail, and Fig. 4 shows a modified form of seal stab that may be used in further preferred embodiments of the invention.

Description of the preferred Embodiments Referring to Fig. 1, a christmas tree 60 is connected to a wellhead 10 by a connector 50. The wellhead includes a cylindrical wellhead housing 11 in which a casing hanger 12 is locked.

The casing hanger supports a string of casing 12a extending downwards into the well. A tubing hanger 13 is also locked into the wellhead housing 11 and supports a string of tubing

14 extending down the well. Static seal stabs 40,140 formed with annular sealing elements and/or sealing surfaces 68,70 extend from the tree 60 and sealingly engage the tubing hanger 13. An annular annulus flow conduit 150d is thereby defined between the seal stabs 40,140.

A valve closure element in the form of a sleeve 20 is slidably received in the production bore 100 in the tubing hanger. A passageway 150a extends upwardly through the tubing hanger, from the tubing annulus below. It terminates at a lateral port 18a adjacent to the sleeve 20.

A further passageway 150b extends from an opposable port 18b upwardly through the sleeve 20. A still further passageway 150c provides fluid communication between the passageway 150b and the annulus flow conduit 150d. As shown, the sleeve 20 is in an upward position in which the port 18a is opposite a solid portion of the sleeve 20, between a pair of annular seal elements 23,24. The passageways 150a-c through the tubing hanger are thereby closed against fluid flow. The sleeve 20 is movable downwardly from the position shown, to bring the ports 18a, 18b into alignment, thereby establishing fluid communication from the tubing annulus through the passageways 150a-c to the annulus flow conduit 150d. A number of sets of passageways 150a-c may be circumferentially distributed around the tubing hanger 13 and sleeve 20, with the ports 18a, 18b forming annular galleries. The sleeve 20 is movable between the up and down positions by hydraulic fluid supplied to chambers 120,122 defined between the sleeve 20 and the tubing hanger 13 by annular seal elements 23,62, 64. Suitable hydraulic lines (not shown) extend through the tree 60 and tubing hanger 13 to the chambers 120,122. Alternatively, the chambers 120,122 and hydraulic lines may be omitted and the sleeve 20 shifted up by applying fluid pressure to the production bore 100 (after setting a plug in the tubing hanger 13or tubing). The sleeve may be shifted down by pressurising the annulus flow conduit 150d. In either case, the sleeve may also be shifted by a tool (not shown) lowered down the production bore 100 on wireline, coiled tubing or the like, to engage groove 20a in the sleeve 20. Such operation provides a backup to the primary mode of operation of the sleeve 20. Yet alternatively, the sleeve may not be actuated by fluid pressure at all, in which case the tool provides the only mode of operation. Suitable mechanical detents (e. g. spring loaded balls, snap rings or J-slots and locking pins) may be provided to hold the sleeve 20 in its valve open and valve closed positions.

Figures 2 and 3 show a further embodiment, again comprising a wellhead housing 11, tree 60, tubing hanger 13 and closure member sleeve 20. The tubing hanger includes a number of

conduits for conveying hydraulic fluids and/or electrical lines down the well outside the tubing string. These lines are normally arranged concentrically around the tubing 14. The hydraulic and electrical lines communicate with the respective lines in the Christmas tree 60 and from there to the outside of the well. In Fig. 2 only two conduits are shown, an annulus bore 8 for establishing fluid communication with the tubing annulus below the tubing hanger 13, and bore 7: an hydraulic line for control of a downhole safety valve.

The tubing hanger has a production bore 100 having a lower section 15 with diameter similar to the inner diameter of the tubing string 14 and an upper section 16 with a larger diameter.

Between them they define an annular shoulder 16a.

Referring to Fig. 3 the tubing hanger annulus bore 8 communicates with a lateral bore 9. A port 18 in tubing hanger section 16 communicates with bore 9. A groove 17 is made in section 16. A number of such bores 8,9 and portsl8 may be circumferentially spaced around the tubing hanger.

The closure member 20 is a cylindrical sleeve with an outer diameter which is a sliding fit within section 16 of the tubing hanger production bore. Thus the sleeve can slide along inner wall section 16 movable between fist and second positions, the movement being limited by the shoulder 16a and a stop ring 27. The sleeve includes seal elements 23,24, 26 that provide fluid tight seals between the outer wall of the sleeve and the wall of section 16. A series of circumferentially spaced recesses 22 (only one shown) in sleeve 20 house respective outwardly biased dogs 21.

A movable production seal stab 40 is located in the tubing hanger and extends upwardly into the Christmas tree. The stab includes seal elements 41,42 that pack off between the stab and the lower section 15 of the tubing hanger inner profile, as well as a metal-to-metal sealing lip 42a which seals against a co-operating surface 15a in the tubing hanger production bore.

These isolate the closure member sleeve 20 from well fluids. As can be seen from Fig. 3, the outer wall of the stab and the wall of section 16 of the tubing hanger production bore define between them an annular space in which the sleeve 20 is located. The movable production seal stab 40 further includes a driving formation 44 engaging the sleeve 20.

The annulus valve can be actuated by moving the production stab 40 whereby the driving formation 44 will act on the sleeve 20. In its lower position, a port 25 in annular sleeve 20 will align with port 18 in the tubing hanger, allowing access to the annulus. The port 25 communicates with circumferentially spaced, longitudinal channels 25a formed in the upper end of the closure member sleeve 20 and with corresponding channels in the driving formation 44. With the sleeve 20 in the upper position (as shown in Fig. 3), annulus access is closed off by a solid portion of the closure member sleeve 20 lying between the seal elements 23 and 24.

In use, the movable production seal stab 40 is actuated by hydraulic pressure via a dedicated circuit in the Christmas tree. This comprises a line 102, Fig. 2, in the tree 60 communicating with a closed hydraulic chamber 104 which is pressurised for downward movement of the production seal stab 40. Similarly, a line 106 communicates with a chamber 108 for upward stab movement. An annular piston 110 formed on the production seal stab 40 separates the chambers 104,108. (The left-hand side of Fig. 2 shows the production seal stab 40 in its upper, retracted position, and the right-hand side the extended position).

When the seal stab 40 and the valve sleeve 20 move down together, the dogs 21 will be forced radially inwards out of groove 17 in the tubing hanger and into groove 43 in the seal stab, thus locking the sleeve 20 and production bore seal stab 40 together. To move the sleeve 20 up to the closed position, the production seal stab is operated by hydraulic pressure via line 106. Due to the action of the dog mechanism, the sleeve 20 is also caused to move upwards until the point when the dogs again 21 line up with the groove 17 in the tubing hanger. At this point, the seal stab 40 is released from the sleeve 20 and tree 60 can be disconnected from the wellhead with the sleeve left in its closed position. The lock ring 27 acts as a stop ring to prevent further upward movement of sleeve 20.

If the hydraulic circuit fails, a tool can be run on wireline or the like into the production bore 100 and engaged into a dedicated profile 40a in the seal stab 40. The stab can then be manipulated up or down in order to operate the valve.

Various seal element arrangements and/or types can be used. The seals may for instance either be elastomer or metal seals.

The closure member configuration shown in Figs. 2 and 3 is pressure balanced, so that when closed it may be pressurised from above or below without causing the sleeve 20 or seal stab 40 to move. This gives the ability to test to confirm that the valve is closed by applying pressure from above. In an alternative embodiment shown in Fig. 4, a non pressure-balanced production bore seal stab 40 is shown. This may be moved downwardly by pressurising the annulus flow conduit 150d from above, or moved upwardly by plugging the tubing hanger or tubing production bore and pressurising the production bore from above. A metal-to-metal seal element 168 provides sealing between the stab 40 and tree 60 body. The tubing hanger and closure member sleeve are substantially similar to those of Figs. 2 and 3 and are therefore not further described or illustrated. Circumferentially spaced stems 160 (only one shown) extending through bonnets 166 in the tree 60 and engageable with detents 162,164, or similar mechanical devices, can be provided to lock the seal stab 40 in the extended or retracted position. Such stems also provide visual indication of the proper positioning of the seal stab 40. For this purpose, detent 162 is deeper (for example a through hole) than detent 164 (for example a blind-ended hole).

The valve may be wholly activated by mechanical means, thus eliminating the hydraulics. In such a case, the actuating sleeve may be separate from the production sleeve stab, as shown in Fig. 1. This has the advantage that the production seal stab may remain static. The closure member sleeve may be moved by a wireline run tool as described above. Another method of moving the closure member sleeve may be by rotation by a suitable tool lowered into the production bore and engaged with the sleeve. This may cause the sleeve to move up or down on a threaded connection e. g. with the tubing hanger or production seal stab. Alternatively, the sleeve may remain vertically fixed relative to the tubing hanger, with such rotation moving ports otherwise similar to ports 18a, 18b into and out of circumferential alignment.