Hollow members, such as a subsea test tree, which are inserted into a well assembly often require a flow port for allowing fluid communication between an internal bore and the exterior of the hollow member. A subsea test tree may be disposed, for example, in a blow-out preventer (BOP) of an offshore oil or gas well assembly for pressure testing a length of marine riser extending from a wellhead assembly including the BOP, to a surface oil rig or vessel and for providing well control functions. Where the well assembly includes a dual bore riser, the subsea test tree has internal main and annulus bores, and the flow port extends through a side wall of the subsea test tree between the annulus bore and an external annulus defined by an outer surface of the tree and an inner surface of the marine riser. A sliding valve sleeve of a sleeve valve surrounds the subsea test tree and is moveable to open and close the flow port by actuation of a combination of hydraulic fluid control conduits and/or return springs.

When it is desired to allow fluid communication through the port, the valve sleeve is moved to open the flow port, allowing fluid communication between the annulus and the annulus bore to provide well control functions.

A guide ring and/or seals are provided in an outer surface of the subsea test tree which extend around the tree. In particular, seals are provided above and below the flow port which are sealingly engaged by the valve

sleeve to close the flow port when pressure testing (or any other operation requiring the flow port to be open) has been completed.

When the valve sleeve is moved to open the flow port, the guide ring and/or the seals are exposed and may become damaged. Such damage may be due to relatively large differential pressures and high fluid velocity experienced when the guide ring/seals are exposed as the flow port is open, or to corrosive well fluids or a combination of the two.

It is amongst the objects of the present invention to obviate or mitigate at least one of the foregoing disadvantages.

According to a first aspect of the present invention, there is provided apparatus for engaging and protecting a seal disposed in an outer wall of a tubular member for location in a well assembly, the tubular member having at least one internal bore and an external moveable valve sleeve adapted to be moved between a first position where the valve sleeve engages the seal and prevents fluid communication between the internal bore and the exterior of the hollow member, and a second position where the valve sleeve exposes the seal and allows fluid communication between the internal bore and the exterior of the hollow member, the apparatus comprising: an auxiliary sleeve coupled to the valve sleeve and moveable therewith, so that when the valve sleeve is moved to the second position exposing the seal, the auxiliary sleeve is moved to engage and protect the seal.

According to a second aspect of the present invention, there is provided apparatus for engaging and protecting a seal disposed in an outer wall of a test tree having at least one internal bore and an external moveable valve sleeve adapted to be moved between at least a first position where the valve sleeve engages the seal and prevents fluid communication between the

internal bore and the exterior of the test tree, and a second position where the valve sleeve exposes the seal and allows fluid communication between the internal bore and the exterior of the test tree, the apparatus comprising: an auxiliary sleeve coupled to the valve sleeve and moveable therewith so that when the valve sleeve is moved to the second position exposing the seal, the auxiliary sleeve is moved to engage and protect the seal.

According to a third aspect of the present invention, there is provided a well tubular comprising: a generally tubular body defining at least one internal bore and having at least one flow port for selectively allowing fluid communication between the at least one internal bore and the exterior of the tubular body; at least one seal disposed in an outer wall of the generally tubular body; a moveable valve sleeve mounted on the outer wall of the generally tubular body, moveable between a first position where the valve sleeve engages the seal and blocks the flow port to prevent fluid communication between said at least one internal bore and the exterior of the tubular body, and a second position where the valve sleeve exposes the seal and opens the flow port to allow fluid communication between said at least one internal bore and the exterior of the tubular body; and an auxiliary sleeve coupled to the valve sleeve and moveable therewith, so that when the valve sleeve is moved to the second position exposing the seal, the auxiliary sleeve is moved to engage and protect the seal.

The well tubular may be a tree and is preferably a subsea test tree. Alternatively, the well tubular may be a length of well tubing or a drill string or the like.

Thus, apparatus is provided having an auxiliary sleeve which is moved to engage and protect a seal of a hollow member, such as a subsea test tree, when a valve

sleeve of the subsea test tree is moved to allow fluid communication between an internal bore of the subsea test tree and the exterior of the tree. In this fashion, the seal is protected from exposure to relatively large differential pressures/fluid velocities and/or exposure to potentially harmful well fluids when the valve sleeve is moved to allow fluid communication. The subsea test tree may include at least one flow port for allowing the fluid communication.

The apparatus may further comprise a guide ring disposed in an outer wall of the generally tubular body, said guide ring being engaged and protected by the auxiliary sleeve when the valve sleeve is in the second position, in a similar fashion to the at least one seal.

Preferably, the well tubular further includes actuating means for moving the valve sleeve between the first and second positions. The actuating means may comprise a combination of at least one hydraulic fluid control line and at least one return spring. Preferably, the actuating means comprises two hydraulic fluid control lines and a plurality of return springs. The valve sleeve defines an annulus between an inner surface thereof and an outer surface of the generally tubular body of the well tubular. The valve sleeve annulus may be divided into first and second isolated annular chambers by a shoulder extending substantially radially outwardly from the tubular body. Preferably, one of the control lines is coupled to one of the first and second annular chambers, whilst the other one of the control lines is coupled to the other one of the first and second annular chambers. Conveniently, the return springs are disposed in one of the first and second annular chambers.

Preferably, there are two or more seals disposed in the outer wall of the well tubular. Preferably also, where the well tubular is a subsea test tree, the two or more seals extend substantially circumferentially around the subsea tree and are spaced axially above and below

the flow port of the tree, for sealing the flow port and preventing fluid communication when the valve sleeve is in the first position.

Conveniently, the subsea test tree is a dual bore subsea test tree having an internal annulus bore and an internal main bore. Preferably, the fluid communication is selectively allowed between the annulus bore and the exterior of the tree. The subsea test tree may be disposed in a riser and may define an annulus between the outer surface of the subsea test tree and an inner surface of the riser.

Conveniently, the auxiliary sleeve is coupled to the valve sleeve by one or more couplings. The or each coupling includes a piston disposed in a cylinder defined by the auxiliary sleeve and an end of the or each piston is coupled to the valve sleeve.

Preferably, each piston extends through a respective outlet in a wall of the cylinder and includes a head disposed in the cylinder for retaining the piston in the auxiliary sleeve. A spring is disposed between the wall of the cylinder through which each piston extends and the piston head. In this fashion, when the valve sleeve is moved to the second position, the piston head compresses the spring to exert a force on the auxiliary sleeve to move it in conjunction with the valve sleeve to engage and protect the seal. Preferably, the auxiliary sleeve has a U-shaped wall in cross-section which defines an annulus having a plurality of pistons disposed therein.

Alternatively, the auxiliary sleeve defines a plurality of separate U-shaped compartments each receiving a respective piston.

Preferably, in use, the valve sleeve is moved substantially axially upwardly to the second position and exposes a seal disposed axially below the flow port.

Preferably also, when the valve sleeve is moved to the second position, the auxiliary sleeve is moved to engage and protect the exposed seal without blocking the flow

port.

Conveniently, an inner surface of the auxiliary sleeve engages the exposed seal. The auxiliary sleeve includes a substantially radially inwardly extending shoulder for engaging a corresponding substantially radially outwardly extending shoulder on the outer surface of the generally tubular body. The auxiliary sleeve shoulder is adapted to engage the tubular body shoulder when the valve sleeve is moved to the second position to limit movement of the auxiliary sleeve to cover the seal whilst exposing said fluid communication flow port. Preferably, the auxiliary sleeve shoulder and the tubular body shoulder are tapered. Preferably also, the shoulder of the tubular body tapers outwardly in a direction from the bottom of the test tree towards the flow port. In this fashion, the taper of the tubular body shoulder aids location of the or each seal and the guide ring in respective recesses of the tubular body above the shoulder.

According to a fourth aspect of the present invention, there is provided a method of protecting a seal of a well tubular disposed in a well assembly, the well tubular having: a generally tubular body defining at least one internal bore and having at least one flow port for selectively allowing fluid communication between the at least one internal bore and the exterior of the well tubular; at least one seal disposed in an outer wall of the well tubular; a moveable valve sleeve mounted on the outer wall of the generally tubular body; and an auxiliary sleeve coupled to the valve sleeve for movement therewith ; wherein the method comprises the steps of: moving the moveable valve sleeve between a first position where the valve sleeve engages the seal and

blocks the flow port, and a second position where the valve sleeve exposes the seal and opens the flow port; and moving the auxiliary sleeve in conjunction with the valve sleeve to cover the seal whilst the flow port is open.

Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which: Fig. 1 is a schematic cross-sectional illustration of a well assembly with a subsea test tree disposed in a blow-out preventer (BOP) of the well assembly, the subsea test tree having apparatus for engaging and protecting a seal of the subsea test tree in accordance with a preferred embodiment of the present invention; Fig. 2 is a longitudinal cross-sectional view of part of the subsea test tree of Fig. 1, drawn to a larger scale, showing a valve sleeve of the subsea test tree in a first position where the valve sleeve has engaged the seal, and showing the apparatus for engaging and protecting the seal of the test tree in more detail, and Fig. 3 is a view similar to the view of Fig. 2, with the valve sleeve of the subsea test tree in a second position, where the apparatus has engaged and protected the seal.

Referring firstly to Fig. 1, there is shown a schematic cross-sectional illustration of a well assembly, indicated generally by reference numeral 10.

The well assembly includes a marine riser 12, a BOP 14, a wellhead 16, a borehole casing 18, well tubing 20, a subsea test tree 22, a tubing hanger 24 and a further length of well tubing 26.

The marine riser 12 is coupled to the BOP 14 and extends to an oil rig or other vessel at the surface.

The BOP 14 is connected to the wellhead 16, which is, in turn, connected to the borehole casing 18. The well tubing 26 is suspended within the borehole casing 18 by a

tubing hanger 24, which has been run into the casing 18 by a tubing hanger running tool (not shown), as will be appreciated by persons skilled in the art. The subsea test tree 22 is run into the BOP 14 on the end of the well tubing 20 and connected to the upper end of the tubing hanger running tool.

The subsea test tree 22 is a dual bore test tree having a main bore 32 and an annulus bore 34, as will be described in more detail with references to Figs. 2 and 3 below. A typical such test tree 22 is disclosed in the applicant's granted European Patent No. EP 0770167B1 for a completion subsea test tree. For clarity, the dual bores are not shown in Fig. 1. On location of the subsea test tree 22 in the BOP 14, the test tree 22 is typically used to control well functions, which involve control of the annulus bore 34 (shown in Figs. 2 and 3).

For this purpose, the test tree 22 includes a flow port 54 (shown in Figs. 2 and 3) for selectively allowing fluid communication between an annulus 28 and the annulus bore 34 of the test tree 22. The annulus 28 is defined between an outer surface of the well tubing 20 and test tree 22 and an inner surface of the riser 12.

The test tree 22 includes a moveable tubular sliding sleeve valve 30 for allowing the selective fluid communication between annulus 28 and the annulus bore 34, as will be described with reference to Figs. 2 and 3 below.

Referring now to Fig. 2, there is shown a longitudinal cross-sectional view of the subsea test tree 22 of Fig. 1, drawn to a larger scale. The test tree 22 has threaded upper and lower ends 40 and 42 respectively for coupling the test tree 22 to threaded ends of the well tubing 20 and 26, as will be appreciated by persons skilled in the art. In a similar fashion, the main bore 32 and the annulus bore 34 of the test tree 22 have internally threaded upper openings 44 and 46 respectively and externally threaded lower male ends 48 and 50

respectively, for coupling the bores 32 and 34 to corresponding main and annulus bores of the well tubing 20 and 26, again as will be appreciated by persons skilled in the art. Also, a hydraulically actuated ball valve 52 of a type well known in the art is disposed in the annulus bore 34 for selectively allowing fluid flow through the annulus bore 34 to surface.

The sleeve valve 30 is mounted on an outer surface 36 of the test tree 22 and is coupled to apparatus for engaging and protecting a seal of the test tree 22, indicated generally by reference numeral 38. A flow port 54 extends radially through the wall 56 of the test tree 22 between the annulus bore 34 and the annulus 28, and has an inlet 58 and an outlet 60.

The sliding sleeve valve 30 comprises an annular valve sleeve 62 which defines inner annular chambers 64 and 66. Actuating means including hydraulic fluid control lines 68 and 70 extend from the annular chambers 64 and 66 respectively to the surface to allow the valve sleeve 62 to be moved between first and second positions, as will be described below. The actuating means also includes thirty-two springs, one of which is shown in Fig. 2 and given the reference numeral 72, disposed in annular chamber 66 around the circumference of the test tree 22, each spring acting between a washer 74 at the bottom of chamber 66 and an annular inner sleeve 76 at the top of chamber 66. The inner sleeve 76 abuts a shoulder 78 which extends radially outwardly from the outer surface 36 of test tree 22 and which includes an 0- ring seal 80. An upper inner collar 82 is disposed in annular chamber 64 and includes additional seals 84 for sealing the annular chamber 64. Also, the valve sleeve 62 has an upper 0-ring seal 86 and first and second O- ring seals 88 and 90 of a thermoplastics material are provided in the outer surface 36 of test tree 22, spaced axially above and below the flow port 54 respectively.

In Fig. 2, hydraulic control fluid has been supplied

to the annular chamber 66 and allowed to bleed from the annular chamber 64 via hydraulic control lines 70 and 68 respectively. This, combined with the force exerted by each spring 72 upon the valve sleeve 62, causes the valve sleeve 62 to move to the position shown in Fig. 2, where a lower inner surface 92 of the valve sleeve 62 abuts the seals 88 and 90 to sealingly block the flow port 54. To aid movement of the valve sleeve 62 to the position shown in Fig. 2, a guide ring 94 of aluminium/bronze is provided to lend a lubricating effect, to prevent the valve sleeve 62, which is of a type 86/30 steel, from binding thereto under high pressure.

The apparatus 38 is provided for protecting the seal 90 and guide ring 94 during the movement of the valve sleeve 62 to the position shown in Fig. 3 and comprises an auxiliary annular sleeve 96 defining an internal annulus cylinder 98, with sixteen pistons 100 spaced around the annulus cylinder 98 (only two of which are shown in Figs. 2 and 3), and corresponding springs 102 located around each piston 100. The annulus cylinder 98 is generally U-shaped in cross-section as shown in Figs.

2 and 3. Each piston 100 extends through a respective outlet 104 of the annulus cylinder 98 and has a threaded male end 106 screwed into a threaded bore 108 of the valve sleeve 62. Also, each piston 100 has a head 110 of an outside diameter greater than the outlet 104.

Referring now to Fig. 3, when it is desired to allow fluid communication between the annulus 28 and the annulus bore 34, the valve sleeve 62 is moved upwards to expose the flow port 54. This is achieved by supplying hydraulic control fluid to the inner annular chamber 64, via control line 68, and allowing fluid to bleed from the inner annular chamber 66. This creates a differential force acting against the restoring force of each spring 72, which moves the sleeve 62 to the position shown in Fig. 2.

As the valve sleeve 62 of sleeve valve 30 moves

upwards, each piston 100 of the apparatus 38 is pulled upwards therewith, compressing the springs 102 and imparting a force upon the sleeve 96 to move it upwards with the valve sleeve 62. A tapering shoulder 114 is formed at a bottom edge of inner surface 112 of auxiliary sleeve 96, which abuts a similar tapering shoulder 116 in the wall 56 of test tree 22, as shown more clearly in Fig. 2. These shoulders 114 and 116 come into abutment when the sleeve valve 62 is moved to the position shown in Fig. 3, preventing the auxiliary sleeve 96 from moving further upwards with the valve sleeve 62 of sleeve valve 30 and blocking the flow port 54. Any further movement by the valve sleeve 62 is borne by the springs 102 which compress further as the head 110 of each piston 100 is drawn further upwardly into annulus cylinder 98. The shoulder 116 tapers outwardly from the bottom of test tree 22 towards the flow port 54, to aid location of the seals 88 and 90 and the guide ring 94 by a snap-fit into recesses in the wall 56.

In this position the inner surface 112 of the auxiliary sleeve 96 engages both the seal 90 and the guide ring 94, protecting the seal 90 and guide ring 94 from exposure to relatively high differential pressures, such as those which may be experienced between the annulus 28 and the annulus bore 34 and, furthermore, protecting them from exposure to well fluids which may be corrosive and harmful.

When the requirement for fluid communication between the annulus bore 34 and annulus 28 is finished, the port 54 is closed by returning the valve sleeve 62 to the position shown in Fig. 2. This is achieved by supplying fluid to the inner annular chamber 66 by control line 70 and allowing fluid to bleed from the inner annular chamber 64 via control line 68. This, in combination with the restoring force of each spring 72, returns the valve sleeve 62 downwards into abutment with the auxiliary sleeve 96 of apparatus 38. The apparatus 38

is then pushed downwards with the valve sleeve 62 until the flow port 54 is covered and the seal 90 and guide ring 94 engaged and protected by the valve sleeve 62 of sleeve valve 30. It will be noted that the seal 88 above the flow port 54 is engaged and protected at all times by the valve sleeve 62, as shown in Figs. 2 and 3.

Various modifications may be made to the foregoing within the scope of the present invention. For example, the well tubular may be a length of well tubing such as a liner, drill string or the like, or indeed any other tubular member which may be inserted into, or form part of, a well assembly. Where the well tubular is a tree, the tree may be a completion tree, a horizontal tree or indeed any single or dual bore tree.

The valve sleeve 62 of sleeve valve 30 may be actuated between the first and second positions by actuating means including two or more hydraulic fluid control lines, a hydraulic fluid control line and one or more springs, or any other suitable arrangement. The springs 72 may be disposed under tension to provide the restoring force.

There may be a plurality of seals and/or guide rings disposed in the outer wall of the well tubular. There may be a plurality of flow ports 54.

The auxiliary sleeve may define a plurality of cylinders each having a respective piston.

The valve sleeve 62 and/or the auxiliary sleeve 96 may not be annular and, in particular, may comprise one or more arcuate plates. There may be an arcuate plate for the or each flow port 54.

The auxiliary sleeve 96 may be restrained from further upward movement with valve sleeve 62 by a pin or other protrusion for engaging a groove, ledge or the like. The pin may extend from one of the auxiliary sleeve 96 and the valve sleeve 62, whilst the groove, ledge or the like may be formed in or extend from the other one of the sleeves 96 and 62.

The well tubing 20 and 26 may be substantially single or dual bore, or partially single/dual bore with respective couplings for the main and annulus bores 32 and 34 of test tree 22.