NO160942B - DEVICE INCLUDING A HOLDING AND SEALING UNIT FOR FITTING IN A BROWN HEAD. - Google Patents

Description

This invention relates to subsea wellhead systems, and

more specifically, a device for sealing and holding down casing hangers in a subsea wellhead. Increased activity in offshore drilling and production has brought an increase in working pressure so that it is expected that new wells will have a working pressure of up to 15,000 psi (1050 kp/cm<2>). In order to cope with the special problems associated with underwater drilling and production at such increased working pressures, new underwater wellhead systems are required. Wells with working pressures up to 15,000 psi (1050 kp/cm<2>) are currently being drilled offshore Canada and in the North Sea at depths greater than 300 feet (91.5 m)• These drilling operations typically involve a floating vessel with a wave compensator for a riser and drill pipe that extends to the safety valve and the wellhead located at seabed level. The relief valve stack is typically mounted on 20 inch (508 mm) pipe with the riser extending to the surface. A quick disconnect is often located on top of the safety valve stack. A joint connection is used to take account of the vessel's movement. A major problem encountered with subsea wellhead systems operating at 15,000 psi under such conditions is pressure loading.

The sealing device must be able to withstand and absorb 15,000 psi (1050 kp/cm<2>) working pressure. Available energy sources for activation of the sealing device include gravity, hydraulic pressure, and torque. Each sealing device requires different amounts of energy for positioning and activation. Weight is the least desirable, because handling the weight tube that provides the weight is difficult and time-consuming on the rig floor. If hydraulic pressure is applied through the drill pipe, there is a need for wireline equipment to lower and retrieve "darts" from the "hydraulic-to-actuated" seal activation system. If "darts" are not used, the handling of "wet strings" of drill pipe becomes very messy and unpopular with the drilling crew. If the seal activation device uses the single-trip pipe hanger technique, the cementing fluid can cause problems in the hydraulic system used to activate the seal. Maintenance is also a problem. Although torque is the most desirable method of actuating a seal, there are limitations on the amount of torque that can be transmitted from the surface due to frictional losses to the riser, relief valve stack, site saw, various threads, and the drill pipe itself.

The above-mentioned problem is essentially solved by a device as stated in the subsequent, independent claim 1. Advantageous embodiments of the device are stated in the subsequent non-independent claims.

The device according to the present invention thus overcomes the disadvantages of the known technique and includes many other advantageous features. The system has a single-trip option, but can still use multi-trip methods. The sealing elements can be interchanged and are fully activatable to a pressure in excess of the assumed wellbore pressure. Support seals are available. The seals cannot be deactivated by pressure, and the sealing elements will seal even if the pipe hangers land high.

The device according to the present invention will reliably seal an annular area of approx. 18 1/2 inch (470 mm) outside diameter and 17 inch (432 mm) inside diameter and provides a rubber pressure greater than 15,000 psi (1050 kp/cm<2>) (20,000

v

psi [1400 kp/cm*2] nominal) when the device is activated and the device experiences a pressure from above or below 15,000 psi. Pressure greater than 15,000 psi is maintained in the device after the lowering tool is removed. The device is also seiv-activated to maintain full pressure if full load force was not applied or if full load force was not maintained. The device will not be pressure-deactivated. The device provides a relatively long sealing area that covers defects in the house and/or contamination. The device further comprises metallic primary seals and uses metallic seals as a counterweight to prevent high-pressure extrusion of elastomeric secondary seals. The device according to the present invention positively retracts the metallic seals from the walls before the device is pulled up.

The elastomeric seals in the device are allowed to be relieved during pulling up of the packing unit and are completely recyclable. The present device forms an essentially metallic one

joint between the top and bottom of the packing area to ensure that the lower ring can be recovered. The construction makes it possible

single trip operations. There are no intervening metal parts in the sealing area that could cause irregular rubber pressure. The device provides a minimum number of parallel sealing areas

for the least possible leakage paths. The device is firmly attached to the packing element so that it cannot be washed away by flow during the lowering operations. The construction also enables multi-trip operations and enables the interchangeability of all casing hangers within a nominal size.

The preferred embodiment of the invention shall be described in more detail below with reference to the drawings, where: Fig. 1 is a schematic view of the surroundings of the present invention; Figs. 2A, 2B and 2C show sections of the wellhead, the pipe hanger support ring, the pipe hanger lowering tool, the gasket and the hold-down assembly, and a schematic view of a part of the safety valve for the underwater well of fig. 1; Fig. 3 is a view with parts separated from each other, showing the seat and part of the wellhead in fig. 2; Fig. 3A is an elevation view on a larger scale of the wedge shown in Fig. 3; Fig. 4 is a section of the sealing element in lowered position and fig. 4A is a section of the sealing element in the sealing position; and

Fig. 5A, 5B and 5C are sections of the wellhead with the pipe hangers

in 16 in. (406 mm), 13 3/8 in. (340 mm), 9 5/8 in. (241.5 mm), and 7 in. (178 mm) pipe hanger strings placed in the hold position and in the seal position.

The preferred embodiment of the invention is described below.

The present invention is intended for use in an underwater wellhead system for lowering, supporting, sealing, retaining and testing a casing hanger in a wellhead in an oil or gas well. Although the present invention can be used in various environments, fig. 1 a schematic illustration of a typical installation of a casing hanger and a casing string according to the present invention in a wellhead located on the seabed at an offshore well.

Fig. 1 shows a wellbore 10 which has been drilled in the seabed 12 under a body of water 14 from a drilling vessel 16 which floats on the water surface 18. A foundation structure or a control foundation 20, a guide pipe 22, a wellhead 24, a drilling safety valve stack 26 with pressure control equipment, and a riser pipe 28 is lowered from the floating drilling vessel 16 and mounted on the seabed 12. The guide pipe 22 can be driven or flushed into the seabed 12 until the wellhead 24 rests near the seabed 12 or, as shown in fig. 1, a borehole 30 can be drilled for the introduction of the guide pipe 22. The guide foundation 20 is fixed around the upper end of the guide pipe 22 on the seabed 12, and the guide pipe 22 is anchored in the borehole 30 by means of one column 32 of cement around a

considerable part of its length. The safety valve stack 26 is connected by means of a suitable coupling to the wellhead 24 which is arranged on the control foundation 20 which is mounted on the seabed 12 and includes one or more drilling safety valves such as the safety valve 40. Such drilling safety valves comprise a number of sealing pipe stoppers, such as the pipe stoppers 34 on the safety valve 40, adapted to be moved out and in from the safety valve housing to and from sealing engagement with a tubular member, such as drill pipe, extending through the safety valve 40,

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as is well known. The riser 28 extends from the top of the siphon stack 26 to the floating vessel 16.

in the Safety valve stack 26 comprises "throttle and kill" lines 36, 38 respectively, which extend to the surface 18. Throttle and kill lines are used i.a. to test

the safety valve 40 pipe shut-off valves 34. When testing the shut-off valves 34, a test plug is lowered into the well through the riser 28 to seal the well at the wellhead 24. The shut-off valves 34 are activated and closed, and the kill line 38 is then pressurized with a valve on the choke line 36 closed to test the pipe shut-off valves 34.

Drilling equipment, including drill pipe with a standard 17 1/2"

(444 in.5 mm) drill bit, is lowered through riser 28 and guide pipe 22 to drill a deeper borehole 42 in the seabed for surface casing 44. A surface casing hanger 50, shown in FIG. 2C where it carries the surface casing 44, is lowered through the guide pipe 22 until the surface casing hanger 50 lands on and connects to the wellhead 24 as described below. Subsequently, other internal casing and production pipe strings are placed and suspended in the wellhead 24 as described below in connection with fig. 5A, 5B and 5C.

As shown in fig. 2C, the wellhead 24 comprises a housing 46 which

has a lower end 48 with a stepped or narrowed diameter which forms a downward-facing, inwardly tapering conical shoulder or shoulder 52. The stepped lower end 48 has at its termination a stepped or narrowed pipe section 54 which forms another, less downward-facing, inwardly tapering shoulder or shoulder 56. The outer diameter of the guide tube 22 is 20 inches (508 mm)

and the pipe is welded to the constricted pipe portion 54 at the bottom of the wellhead 24. The guide pipe 22 has a thickness of 1/2 inch (12.7 mm) and an internal bore 62 of 19 inches (482.6 mm) diameter to initially accommodate the drill string and drill bit to drill the wellbore 42 and then to receive the surface casing string 44 as shown in fig. 1. The wellhead housing 46 comprises a bore 60 with a diameter of approx. 18 11/16 inches (475 mm), slightly smaller than the inside bore 62 of the guide tube 22.

On the inside of the wellhead bore 60 are arranged a number of wedge grooves 64, tooth segments 66, and four annular grooves (shown in Fig. 5B) such as grooves 68, arranged with a mutual distance along the bore 60 above the tooth segments 66. The tooth segments 66 have an internal diameter of approx. 17 9/16 in. (446 mm) to allow passage of the standard 17 1/2 in. (444.5 mm) drill bit for drilling the 42 hole.

The wellhead 24 comprises a detachable pipe hanger support element or housing seat 70 which is arranged for immersion in the bore 60 and connection to the tooth segments 66. The housing seat 70 comprises a massive, tubular ring 72 with a smooth inner bore 74, external tooth segments 76 arranged for engagement with the wellhead 46 internal tooth segments 66, an upwardly facing, downwardly tapering conical seat or bearing shoulder 80 for bearing against the surface casing hanger 50, and a wedge device 78 for locking the housing seat 70 in the wellhead housing 46.

The bore 74 in the solid ring 72 has an internal diameter of 408 mm which gives the conical bearing shoulder 80 an effective horizontal thickness of approx. 33 mm for storage of the casing hanger 50. The housing seat 70 has a wall thickness sufficient to prevent the housing seat 70 from buckling under a vertical compressive stress of 90,000 psi (63,00 kp/cm<2>). This is important as the wellhead 24, due to its size, weight and thickness, is a rigid element compared to the housing seat 70 which is a relatively flexible element.

As shown in fig. 3, the housing seat 70 comprises a number of groups 82 of tooth segments 76 with slots or spaces 86 for receiving corresponding groups 88 of tooth segments 66 in the wellhead

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46 shown in fig. 2C. The tooth segments 66, 76 may optionally have teeth with a pitch, but preferably have pitch-free teeth. The teeth 66, 76 are designed for engagement when the seat 70 is turned for connection to the wellhead 24. The wellhead teeth 66 taper inwards and downwards to facilitate passage of the drill bit. If the cross-section of the teeth 66 were of the square-shaped or saw-tooth-shaped type, they could have gripped the drill bit when it was lowered through the wellhead 24 for drilling the borehole 24 for the surface casing 44. The seat teeth 76 are correspondingly tapered for engagement with the wellhead teeth 66 .

Each of the groups 82, 88 comprises six rows of tooth segments which are approximately one-half inch (12.7 mm) high from bottom to top. The thread surface of the six rows of tooth segments 66, 76 is larger than the contact surface of the bearing shoulder 80. A continuous upper, annular flange 85, which is provided on the seat 70 above the teeth 76, delimits the insertion of groups of teeth 82 into the space menu 87. The flange 85 prevents the seat 70 from passing through the wellhead 24. The lower tooth segment 84 is oversized to prevent too early rotation of the seat 70 in the wellhead 24 until the seat 70 has landed on the ring flange 85.

The six rows or groups 82, 88 of tooth segments 66, 76 form an equal number of rows for uniform storage and distribution of the load. Such a construction equalizes the stresses acting on the tooth segments 66, 76. By having six groups of teeth, the tooth segments 66, 76 can be connected by turning the housing seat 70 30°, i.e. 180° divided by the number of groups. If the tooth segments 66, 76 had been longer, a greater degree of rotation of the housing seat 70 would have been necessary for connection. It is preferred that the tooth segments 66, 76 have the same length, so that maximum contact is achieved to carry the loads.

The tooth segments 66, 76 can only be circular grooves with slots or spaces 86 for connection. The tooth segments 66, 76 have zero pitch angle and taper to increase the thread area so that the threads 66, 76 can withstand a greater shear stress. The taper of the tooth segments 66, 76 is greater than 30" and preferably approx. 55°, whereby the thread area is significantly increased for cutting. This tooth profile seeks to equalize the stresses across all the tooth segments 66, 76 so that the teeth 66, 76 do not give way once the hallway.

The teeth 66, 76 can be of the saw tooth type. If the teeth 66, 76 had had a rectangular profile, they would have caught drilling residues and other debris flowing through the well. A further advantage of the connection between the wellhead 24 and the housing seat 70 is that the tooth segment 76 cleans the tooth segment 66 when the housing seat 70 is rotated in the wellhead 24. The teeth 76 knock the contaminants away from the teeth 66 so that the contaminants fall into the slots or spaces 86, 87 .

Continuous threads have several disadvantages. Threads require several turns to engage and must be supported until they drop a fraction of an inch before the initial engagement of the thread leads. Threads also slide at a point when turning for mating. The connection between the housing seat 70 and the wellhead 24 avoids these disadvantages. When the housing seat 70 is immersed in the wellhead

24 on a suitable lowering tool, the lower tooth segment 84 on the seat 70 will engage the upper tooth segment in the tooth segments 66 on the wellhead housing 24. The seat 70 is then turned less than 30" so that the group 82 on the seat 70 can be received in the slot 87 between the groups 88 on the wellhead 24. This drop movement is significant, up to 12 inches (305 mm), and can be easily detected at the surface as an assurance that the housing seat 70 has engaged the wellhead 24 and can be rotated to engage the breech. Use of the connection according to the present invention provides a clear indication of when the housing seat 70 is in full engagement with the wellhead 24. The connection according to the present invention has the further advantage that it allows the housing seat 70 to be inserted into the wellhead 24 and secured by a 30" rotation of the housing seat 70 to achieve full engagement between the housing seat 70 and the wellhead 24.

As shown in fig. 2C, 3 and 3A, the wedge device 78 comprises a number of outwardly biased cams 92 each of which is displaceably received in an outward facing cavity 94 in every other lowermost tooth segment 84 of the solid ring 72. The cams 92 have planar faces 90, upper and lower tapered sides 91 . end rests against the bottom of the cavity 94 to press the cam 92 outwards. Keyway 64 is located under all six groups 88 so that the cams 92 are positioned on the solid ring 72 whereby the cam 92 will be located next to a keyway 64 in the wellhead housing 46 in full engagement between the inner and outer teeth 66, 76 of the wellhead 24 and housing the seat 70. The cam 92 will be pressed into the groove 64 by rotation of the ring 72 in the threads 66, thereby stopping the rotation of the ring 72. An opening 102 is formed through the ring 72 and into the cavity 94, whereby the cam 92 can be released.

According to the prior art, the support shoulder for the surface casing hanger was integral with the wellhead housing and was large enough to support the casing and the pressure load. In this known technique, however, the bearing shoulder narrowed the bore or the flow path in the wellhead housing, so that there was no full opening or access to the casing under the wellhead housing for drilling. Using a sufficiently large carrier shoulder of a known type for 15,000 psi (1050 kp/cm<2>) working pressure, the bore through the shoulder would not permit the passage of a standard 17 1/2 inch (444.5 mm) bit. Such underwater wellhead systems necessitated "under-escape".

According to the present invention, the housing seat 70 is a mountable support shoulder or shoulder which does not need to be mounted in the wellhead housing 46 before greater working pressure is encountered. The housing seat 70 is not assembled until the drilling operation for the surface casing 44 is complete, which allows access through fully open drilling. As only nominal working pressures occur

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during drilling for the surface casing 44, larger bearing shoulders are not required. After the drilling for the surface casing 44 is completed, the casing seat 70 is installed to handle casing and pressure loads up to 15,000 psi (1050 kp/cm<2>). There is thus sufficient clearance before mounting the housing seat 70 for a 171/2 inch (444.5 mm) drill bit to pass.

For mounting the housing seat 70, the housing seat 70 is connected with

a lowering tool (not shown) by means of breaker pins, one of which is partially shown at 104. The lowering tool on a drill string then guides the casing seat 70 down into the bore 60 in the wellhead 24 until the bottom tooth segment 84 lands on the top tooth segment of the tooth segments 66. The seat 70 is then turned until the groups of teeth 88 on the wellhead 24 fall into the slots 86 and the groups of teeth 82 on the ring 72 are received in corresponding slots 87 on the wellhead teeth 66. The continuous ring flange 85 lands on the uppermost tooth segment of the tooth segments 66 in the wellhead 24. The housing seat 70 is then rotated using the drill string and the lowering tool until the wedges 78 engage in the wedge grooves 64 and thereby stop the turning movement. A pressure test can be performed to ensure that the housing seat 70 is down. Then the break pins which retain the housing seat 70 on the lowering tool will break at 104 so that the lowering tool can be released and removed.

Fig. 2C shows how the surface casing hanger 50 is placed (landed) on the casing seat 70 in the wellhead 24. The casing hanger 50 has a generally tubular main part 110 which includes a lower internal threaded portion 112 in threaded engagement with the uppermost length of the casing string 44 for suspension of the string 44 in the borehole 42, an extended top section 114 with a radially projecting annular shoulder 116 and a number of annular grooves 120 (shown in Fig. 2B) in the inner circumference of the main part 110, which are arranged for connection with a lowering tool 200 to be described below .

As shown in fig. 2A and 2B, the outside of the tube part 110 is provided with threads 118 from the top down a significant part of its length, for engagement with the holding and sealing unit 180, which will be described below.

. The cementing operation for cementing the surface casing string 44 in the borehole 42 necessitates a channel from the lower annulus 130, between the surface casing string 44 and the guide pipe 22, to the upper annulus 134, between the wellhead 24 and the drill string 236, for the return of waste material to the surface. A number of upper and lower grooves or circulation ports 122, 124 are formed through the upper section 114 to allow fluid flow, e.g. for the cementing operation around the pipe hanger 50. The lower grooves 122 form fluid channels through the radially annular shoulder 116 and the upper channels 124 form fluid channels through the upper threaded end of the pipe part 110 for the passage of fluids around the holding and sealing unit 180.

Threads 126 are formed on the outer circumference of the upper section 114 below the ring shoulder 116 for engagement with the threaded shoulder ring 128 around the pipe hanger 50. The shoulder ring 128 has a downwardly facing, downwardly tapering, conical surface 132 which rests in abutment against an upwardly facing, downwardly tapering, conical bearing shoulder 80 on the housing seat 70. The pipe hanger 50 thus lands on the housing seat 70 by engagement between the cone surface 132 of the pipe hanger shoulder ring 128 and the housing seat's bearing shoulder 80, whereby the housing seat 70 must take over the resulting casing and pressure load.

Wells that have a working pressure in the range of 15,000 psi

creates unique stresses on the wellhead carrier rafts. Not only must the wellhead carry the weight of the casing trailers with their stored casing and one or more production tubing trailers; their stockpiled production pipe, but the wellhead must too

withstand the working pressure of 15,000 psi. The wellhead must thus bear both the weight of the casing and the production pipe as well as the pressure load. A wellhead designed for 15,000 psi working pressure must have sufficient support and bearing surface or bearing area over the entire wellhead construction, so that the load does not significantly exceed the yield strength under vertical pressure loading of the material in the wellhead support rafts. Although materials with a minimum yield strength of 70,000 psi (4,900 kp/cm<2>) are used at lower working pressures, normally a material with a higher yield strength of minimum

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85,000 psi (5950 kp/cm<2>) for 15,000 psi wellheads. If one carefully assumes a vertical compressive stress of 90,000 psi (6300 kp/cm<2>) on the wellhead, the wellhead according to the present invention will carry a load of over 6,000,000 Ibs (2,721,600 kg), as the bearing area is in the region of 65 to 70 square inches (419 to 452 cm<2>). Such a bearing area must be implemented over the entire construction so that the load does not exceed 25% of the material's yield strength under vertical pressure loading. The bearing area between the lowermost pipe hanger 50 and the housing seat 70, as well as between the housing seat 70 and the bearing tooth segments 66 on the wellhead 24 must be sufficient to carry such loads without significantly exceeding their material yield strength under vertical pressure loading, i.e. above 25% of the yield strength. Such a construction has been achieved with the wellhead system according to the present invention.

In order to ensure sufficient bearing area between the pipe hanger 50 and the seat 70, the pipe hanger shoulder ring 128 is screwed to the radial annular shoulder 116 which projects from the upper section 114 of the pipe hanger part 110. The shoulder ring 128 forms a 360° conical surface 132 for contact with the housing the bearing shoulder 80 of the seat 70, so that a complete contact is achieved between the shoulder 80 and the cone surface 132. Without the shoulder ring 128, the grooves or circulation ports 122 through the shoulder 116 prevent a 360° bearing area between the hanger 50 and the housing seat 70. The connection between the bearing shoulder 80 and the cone surface 132 provides an ample bearing area determined by the wellhead inside diameter of 17 9/16 inches (446 mm) and the housing seat 70 inside diameter of 16.06 inches (408 mm). The bearing area between the shoulder 80 and the surface 132 is therefore approx. 70 square inches (452 cm<2>) so that the bearing area can support more than 6,000,000 Ibs of load.

The inner and outer tooth segments 66, 76 of the wellhead 24 and the housing seat 70 are also designed to provide sufficient bearing area to carry the expected load described above. As previously mentioned, the tooth segments 66 comprise

76 six tooth groups 82, 88 which are designed on the wellhead 24 and the housing seat 70. Each group 82, 88 comprises six teeth 66, 76 which take up the load. The bearing area of the tooth segments 66, 76 is greater than the bearing area between the shoulder 80 and the cone surface 132. The number of teeth is determined by the loss of bearing area as a result of the six spaces 86, 87 which occupy the corresponding groups 82, 88 during assembly.

As shown in fig. 2C, the radial annular shoulder or shoulder 116 projecting from the upper section 114 of the pipe hanger portion 110 has an upwardly facing, downwardly and outwardly sloping conical cam surface 136 with an annular groove 138 extending upwardly at the bottom. An annular chamber 142 extends from the upper side of the groove 138 to an annular vertical sealing surface 140|, which extends from the groove 138 to the lower end of the threads 118. The shoulder 116 is located below the annular locking groove 68 in the wellhead housing 46 after the hanger 50 has been placed in the wellhead 24. The lower annular edge of the cam surface 136 ends just above the lower end of the groove 68.

The casing hanger 50 comprises a locking ring 144 which is arranged on the radial annular shoulder 116. The locking ring 144 may be a split ring which is arranged to expand in the wellhead groove 68 for engagement with the wellhead housing 46 to hold down and lock the casing hanger 50 in the wellhead 24. The wellhead slot 68 has a vertical bottom wall 146 with an upwardly tapered wall and a downwardly tapered wall. The locking ring 144 has a vertical outer surface 148 with an upwardly tapering surface of the same extent as the upwardly tapering wall of the slot 68 and a downwardly tapering surface which is parallel to the downwardly tapering wall of the slot 68, whereby the vertical surface 148 of the ring 144, upon expansion of the locking ring 144, forms an engagement with the vertical wall 146 of the groove 68. Furthermore, the locking ring 144 comprises a downward-facing, inwardly and upwardly tapering lower cam surface 152 in contact with the upward-facing cam surface 136 of the radial ring shoulder 116, an indenting annular flange 154 which is engaged in the ring groove 138 in the retracted position, and an upward and inward-facing cam head 156j which is arranged for contact with the holding and sealing unit 180 which will be described in the following. Between the comb head 156 and the elevation 154, a tapering surface 158 extends parallel to the wall of the chamber 142.

The indenting annular flange 154 is engaged in the groove 138 in the casing hanger 50 to prevent the locking ring 144 from being pulled out of the groove 138 when the casing hanger 50 is lowered into the well. During the immersion of the pipe hanger 50, the locking ring 144 must pass several narrow diameters such as in the safety valve 40. The safety valve 40 often includes a doughnut-shaped rubber seal which cannot be retracted completely so that the pipe hanger 50 must be pressed through this rubber seal. If the annular elevation 154 was not engaged in the groove 138, the locking ring 144 could hang up in such a narrow diameter and drag along the outer surface. This would pull the locking ring 144 out of the groove 138 and allow it to slide upwards around the pipe hanger 50 until the locking ring 144 contacts the sealing ring 110. This would not only prevent activation of the hold-down actuator device 212, but would also prevent activation of the sealing device 210. The annular chamber 142 provides a clearance so that the groove 138 can occupy the ring elevation 154. This profile also forms a ledge which keeps the locking ring 144 free from such upward movement when the load is placed on the locking ring 144.

The holding and sealing unit 180 is shown in fig. 2B and 2C, engaged with lowering tool 200 and activated in the hold position. The holding and sealing unit 180 comprises a stationary element 184 which is rotatably mounted on a turning element or a packing nut 182 by means of a holding device 186. The packing nut 182 has an annular part with a lower pin 188 and a knurled upper end 198 with upwardly projecting projections 202. The inner diameter surface of the nut 182 includes threads 204 in engagement with the outer threads 118 of the pipe hanger part 110.

The stationary element 184 has an annular part 216 and includes a sealing device 210 for sealing between the wellhead 24 internal bore wall 61 and the pipe hanger 50 external sealing surface 140, and a hold-down actuator device 212 for maneuvering the locking ring 144 into hold-down engagement with the slot 68 in the wellhead 24. The ring part 216 is a complete and continuous metal element and includes an upper drive portion 218, an intermediate Z portion 220 and a lower cam portion 222.

The upper drive part 218 comprises an upper recess 190 which rotatably accommodates the lower pin 188 of the packing nut 182. The holder device 186 comprises inner and outer tracks in the recess 190 which accommodate conical holder rollers or balls 196. The holder device 186 carries no load and is not used for the transmission of torque or compressive force from the packing nut 182 to the stationary element 184. A bearing device 205 is arranged above the sealing device 210 and includes bearing rings 206, 208 which are arranged between the bottom of the recess 190 and the lower end of the pin 188. The bearing rings 206, 208 have a low coefficient of friction which allows displaceable engagement between these upon activation of the hold-down actuator device 212 and the sealing device 210. The bearing device 205' is thus used to transfer pressure load from the packing nut 182 to the stationary element 184. The holder balls 196 only act to rotatably retain the stationary element 184 on the packing nut 182.

The hold-down actuator device 212 comprises the lower cam part 222 which has a downward and outward facing cam surface 224 (shown in Fig. 2C) which is arranged to rest against the cam head 156 of the locking ring 144, and the upper drive part 218 and intermediate Z-part 220 for transfer of pressure load from the packing nut 182 to the lower cam part 222.

The sealing device 210 comprises a Z-part 220 and elastomeric support seals 330, 332 which will be described in more detail below in connection with fig. 4, and upper drive part 218 and lower cam part 222 for compression of intermediate Z part 220. The sealing device 210 is a combined metallic primary seal and elastomeric secondary seal. The advantage of having a metallic seal (ie a seal based on metal to metal) as the primary seal is that it will have no tendency to degrade like an elastomer seal.

The holding and sealing unit 180 is lowered into the well on the pipe hanger 50 using a lowering tool 200. The lowering tool 200 includes a mandrel 230 which forms the main part of the tool 200, a cup part or sleeve 240, a skirt or an outer sleeve 250, and a mounting nut 260. The mandrel 230 includes, an upper pin end 232 with internal threads 234 for connection to the lower pipe section of a drill pipe 236 extending to the surface 18 and a lower socket end 238 which also has internal threads. Above the socket end 238 is an annular groove portion 242 with a narrowed diameter. Another portion 248 of narrowed diameter is located above the groove portion 242 and forms an annular elevation 252. Below the upper pin end 232 and above the narrowed diameter portion 248 is a third portion 254 of narrowed diameter (shown in Fig. 2A) having a smaller diameter than the diameter of parts 242 and 248.

The coupling part or sleeve 240 comprises a bore 246 which is dimensioned to be received telescopically over the annular elevation 252 and socket end 238. The coupling part 240 is telescopically received in the annular space formed by the mandrel 230 and the skirt 250. The elevation 252 comprises annular sealing grooves 258, 262 which occupy O-rings 264, 266, respectively, for sealing engagement with the bore 246 inner diameter surface. The top end of the coupling part 240 comprises an inward-facing, radial ring-shaped flange 268 which forms a sliding fit with the reduced diameter part 248. The lower end of the coupling part 240 has a narrowed diameter part 270 which is displaceably received in the bore 272 of the pipe hanger cleaner 50. The narrowed diameter part 270 forms a downward-facing annular shoulder or shoulder 274 which rests against the upper end 276 of the pipe hanger 50 when placing the lowering tool 200, the holding and sealing unit 180 on the pipe hanger 50

in the wellhead 24. The narrowed diameter portion 270 has a number of circumferentially distributed slots or windows 278 which displaceably receive segments or lugs 280 which have a number of teeth 282 arranged to be received in the grooves 120 in the pipe hanger 50 for connection of the lowering tool 200 in the pipe hanger 50. The lugs 280 has an upper protrusion 284 which is engaged in an annular groove 286 around the windows 278 upper inner circumference. Above the windows 278 are a number of sealing grooves 288, 290 which accommodate O-rings 292, 294 for sealing against the sealing bore 272 in the pipe hanger 50. Near the upper end of the coupling part 240 is a locking ring groove 296 which accommodates a locking ring 298 which is used during assembly of lowering tool 200 as explained below. The cams 280 fall back into the slot portion 242 after the lower sleeve end 238 is moved to the lower position, as shown, by applying torque to the tool 200 for applying the holding and sealing unit 180.

The skirt or outer sleeve 250 comprises a generally tubular portion with an upper inward facing radial portion 300, a center portion 302, a transition portion 304 and a lower actuator portion 306. The portions 300, 302, 304 and 306 are continuous and dimensioned to telescopically occupy the upper end 276 of the pipe hanger 50, the coupling part 240 and the mandrel 230. The lower actuator part 306 has a knurled lower end 308 in engagement with the upper knurled end 198 of the packing nut 182, whereby torque can be transferred from the lowering tool 200 to the holding and sealing unit 180. The actuator part 306's internal diameter is sufficiently large to provide clearance to the outside diameter of the pipe hanger's 50 threads 118.

The central part 302 displaceably accommodates the coupling part 240. The part 302 includes an internal annular groove 310 which is adapted to receive the locking ring 298 which is mounted on the coupling part 240 when disconnecting the lowering tool 200 from the holding and sealing unit 180 and the pipe hanger 50 as described below. The part 302 has a number of threaded bores 312 extending from its outer circumference to the groove 310 whereby bolts (not shown) can be screwed into the groove 310 to prevent the locking ring 298 from engaging with the groove 310 during repositioning of the lowering tool 200 on another pipe hanger. The locking ring 298 has an upper cam surface 316 for engagement with the ends of the bolts. As soon as the coupling part 240 is occupied in the upper part of the annular area formed by the outer sleeve 250 and the mandrel 230, whereby the locking ring 298 is above the ring groove 310, the coupling part 240 cannot be removed without the locking ring 298 creeping into the groove 310. To remove the coupling part 240 when adjusting the lowering tool 200, the bolts are thus screwed into the bores 310 to close the slot 310 and prevent the slots 310 from taking up and gripping the locking ring 298. Thereby the coupling part 240 can be moved downwards on the mandrel 230 until the shoulder 269 rests against the projection 252 for connection of another pipe hanger.

The transition part 304 transitions into the actuator part 306 and the middle part 302 to compensate for the diameter change. Flow openings 318 are designed in the transition portion 304 so that cement can flow back through the outer sleeve 250 and into the annulus 134.

The annular inside of the upper radial portion 300 is knurled to form a knurled coupling 320 with the mandrel 230 for transmitting torque.

As shown in fig. 2A and 2B, the mounting nut 260 has internal threads 234 for screw connection at 322 with the threads 235 of the mandrel 230 narrowed diameter portion 354. The lower end surface of the mounting nut 260 rests against the upper end of the outer sleeve 250 to hold the outer sleeve 250 on the mandrel 230.

During operation, the packing nut 182 is only partially screwed onto the threads 118 at the top of the pipe hanger 50 so that the mandrel 230 is mounted in the lowering position on the pipe hanger 50. In the lowering position, the annular elevation 252 rests against the shoulder 269 which is formed by the radial angle flange 268 of the coupling part 240. The outer tubular surface of the socket end 238 lies close to and engages the inside of the cams 280, whereby the teeth 282 are pressed into the grooves 120 in the pipe hanger 50 to thereby prevent the lowering tool 200 from detaching from the pipe hanger 50 when they are lowered into the well on the drill pipe 236. The lowering tool 200 lowering position is not shown in the figures.

When the surface 132 of the pipe hanger 50's shoulder ring 128 has landed on the housing seat 70's bearing shoulders 80 in the wellhead 24, the surface casing 44 is cemented in place in the borehole 42. After the cementing operation is completed, the lowering tool 200 is rotated and torque is transferred to the holding and the sealing unit 180 to bring the holding and sealing unit 180 into the holding position shown in fig. 2B and 2C. Rotation of the drill pipe 236 at the surface 18 causes the mandrel 230 to rotate, which rotates the outer sleeve 250 by means of the rifle coupling 320. The torque from the outer sleeve 250 is then transferred to the packing nut 182 at the rifle connection of the lugs 202 on the nut 182 and the lower end 308 of the sleeve 250. The packing nut 182 places an axial load on the retainer and seal assembly 180, which brings the cam portion 222 of the retainer-actuator device 212 into contact with the cam head 156 of the lock ring 144. The cam action expands the lock ring 144 into the wellhead groove 68 for engagement with the wellhead housing 46 to hold and lock the pipe hanger. 50 in the wellhead 24 as shown in fig. 2. The sealing device 210 has not yet been activated for sealing between the upper annular space 134 and the lower annular space 130. The locking ring 144 only requires a predetermined edge load for activation and therefore has

a predetermined contraction tension. The cross-section of the sealing device 210 is designed to ensure that the sealing device 210 is not to be compressed prematurely when the locking ring 144 is activated by pressure of the hold-down actuator device 212.

required load for compression of the sealing device 210 is significantly greater than that required to expand and activate the locking ring 144. The mandrel 230 is moved downwards together with the<1>skirt 250 upon activation of the holding and sealing unit 180. This downward movement of the mandrel 230 releases the cams 280.

, For a description of the sealing device 210, reference is made to fig. 4 and 4A which show the sealing device 210 in the lowering and holding position and the sealing position, respectively. The sealing device 210 comprises a Z-part 220 made of metal,

upper and lower elastomer elements 330 and 332, respectively, and upper drive portion 218 and lower cam portion 222 for compressing the Z portion 220 and the elastomer elements 330, 332. The annular metal Z-portion 220 includes a number of annular links 334 in 336, 338 which are interconnected by means of metal coupling rings 340, 342 and connected to an upper drive part 218 by means of an upper metal coupling ring 344 and to the lower cam part 222 by means of a lower metal coupling ring 346.

The links 334, 336, 338 form, together with the coupling rings 340, 342, 344 and 246, a positive connecting link from bottom to top between the lower cam part 222 and the upper drive part 218.

This positive connecting link moves the links 334, 336 and 338 to a more inclined disconnected position in relation to the wellhead 24 and the pipe hanger 50 by withdrawing and disconnecting the sealing device 210 and the actuator device 212 from the wellhead 24. Furthermore, this positive connecting link forms a metal connection that extends from the drive part 218 to the lower cam portion 222 to permit the application of a positive upward load to the lower cam portion 222 upon disengagement. Were it not for the advantage of this retraction, the coupling rings 340, 342, 344 and 346 might not have been necessary.

The coupling rings 344, 346 near the drive part 218 and the cam part 322, respectively, must have a minimum length to ensure sealing engagement for the ring joints 334 and 338. If the coupling rings 344, 346 are too short, there will be insufficient bending for the joints 334 and 338 to contact the surfaces respectively 61,

140. Because the drive part 318 and the edge part 222 are stronger and larger than the coupling rings 344, 346, the relatively strong parts 218, 222 will not bend so much that the joints 334, 338 come into sealing engagement. It is therefore essential that the coupling rings 340, 346 allow such bending. The coupling rings 340, 342, 344 and 346 form a local contact point with high voltage through the Z-metal part 220.

The Z-metal part 220 is made of very soft ductile steel, such as e.g. acid resistant. Such a metal will have a yield strength of approx. 40,000 psi (2800 kp/cm<2>). This yield strength is less than half of the yield strength of approx. 85,000 (5900 kp/cm<2>) to the material in the wellhead 24 and the pipe hanger 50. When the Z-metal part 220 seals, the Z-part 220 deforms plastically, while the surface 61 of the wellhead 24 and the surface 140 of the pipe hanger 50 deform elastically. In case of any irregularities in the surfaces 61, 140, the ductility of the material of the annular Z portion 222 will allow the material to deform or flow into the elevations and recesses in the irregularities of the surfaces 61, 140 to achieve a strongly compressed metal seal. The Z-metal part 220 is thus designed to be impressed into the sealing system with the walls 61, 140 in the wellhead 24 and the pipe hanger 50, respectively, upon activation.

The upper, intermediate and lower ring joints 334, 336, 338 all have diamond-shaped cross-sections. As the joints 334, 336, 338 have largely the same cross-section, a description of the joint 336 will serve as a description for the joints 334, 338. The ring joint 336 comprises largely parallel, ring-shaped upper and lower sides 348, 350 respectively, with the upper side 348 generally facing upwards and underside 350 generally downwardly facing, generally parallel, annular inner and outer faces 352, 254, respectively, with outer face 352 facing radially outward and inner face 354 facing radially inward, and parallel, inner and outer annular seal contact edge surfaces 356, 358, respectively. Ring links 334, 338 have corresponding top and bottom sides, inside and outside sides and inner and outer sealing contact edge surfaces.

In the hold position, the sealing contact edge rafts on the links 334, 336, 338 are deformed largely parallel to the bore wall 61 in the wellhead housing 46 and the outer wall 140 of the pipe hanger 50. The upper coupling ring 344 extends from the lower end 364 of the upper drive part 218 to the upper side of the upper link 334 335 to form an annular channel 366. The metal coupling ring 340 extends from the lower side 337 of the upper link 334 to the upper side 348 of the intermediate link 336 to form the annular channel 368 and the metal coupling ring 342 extends from the lower side 350 of the intermediate link 336 to the upper side 339 of the lower link 338 to

forming the annular channel 370. The lower connecting ring 346 extends from the lower side 341 of the lower link 338 to the upper end 372 of the lower cam portion 222 to form the annular channel 374. The annular channels 336, 338, 370 and 372 between adjacent elevations help to bend the Z-portion 220 at predetermined locations, namely at the coupling rings 340, 342, 344 and 346. The lower end 364 of the drive part 218 is generally parallel to the upper side 335 of the upper joint 334 and the upper end 372 of the cam part 222 is generally parallel to the lower side 341 of the lower joint 338. the lowering and holding positions, the outer and inner sealing contact edge surfaces have the same diameter as the outer and inner diameter of the upper drive part 218 and lower cam part 222, respectively.

The upper and lower elastomeric members 330, 332 have a shape corresponding to the shape of the annular grooves 376, 378 formed by the joints 334, 336, 338 and connected to the joints 334, 336, 338. The upper and lower elastomeric members 330, 332 have outer and inner annular vertical sealing surfaces 380, 382 respectively, which are arranged for sealing engagement with bore wall 61 and outer wall 140 in sealing position. The upper and lower elevations formed by the sealing rafts 380, 382 are chamfered to allow deformation of the members 330, 332 into the sealing position during compression. The elastomeric members 330, 332 are also chamfered to allow a predetermined deformation of the members 330, 332 between the joints 334, 336, 338. Although the cross-sections of the elastomeric members 330, 332 are substantially the same, the inner elastomeric member 332 may be chamfered or trimmed more than the outer elastomer element 330 in order to avoid possible premature extrusion or extrusion of the elements 330, 332 before the joints 334, 336, 338 creates an extrusion-preventing seal against the bore wall 61 in the wellhead 24 and the sealing surface 140 of the pipe hanger 50.

The sealing device 210 preferably comprises at least three joints. This number is preferred because it provides an extrusion-preventing link for each side of the elastomer elements 330, 332. Moreover, with the three links 334, 336, 338, a symmetrical construction is achieved. The sealing device 210 may, however, comprise one or more links, and may preferably comprise a number of links ending in a plurality of elastomer elements. The faces 364 and 372 of the drive portion 218 and the lower cam portion 222, respectively, are preferably tapered in the same direction as the adjacent joints, such as the joints 334 and 338 shown in the preferred construction.

The diamond-shaped cross-section of the joints 334, 336, 338 means that the middle parts 334, 336, 338 can be very rigid. With a thick middle part, the thinner areas at the end parts of the joints 334, 336, 338 will become the area that will yield or bend, such as the area near the coupling rings 340, 342, 344, 346. It is not desirable that the joints 334, 336, 338 bend or gives way at its midsection. However, the special diamond-shaped cross-section shown appears only because it is easier to produce such a shape. The joints 334, 336 and 338 could be continuously convex or ellipsoid-shaped. This shape could be termed obtuse spherical. This gives a protruding middle part. If the cross sections of the joints 334, 336, 338 were of the same thickness, the joints 334, 336, 338 could have a tendency to bend or bow at their middle part. Although the joints 334, 336, 338 preferably have an extended central portion to control the bending point at the edge surfaces for a predetermined plastic deformation and to ensure that distortion does not occur at the center of the joints 334, 336, 338, the joints 334, 336, 338 can be truncated cone-shaped metal rings with a cross-section of constant thickness instead of truncated spherical rings.

Looking at fig. 4 and 4A show fig. 4A the sealing device 210 in the sealing position. The sealing device 210 is compressed when the hold-down actuator device 212 reaches the limit of its movement against the locking ring 144 and the packing nut 182 continues its downward movement on the pipe hanger 50 threads 118 as shown in fig. 2B and 2C.

The metallic sealing device 210 is serially activated from bottom to top. In other words, the lowest ring link 338 is bent and deformed first by compression of the sealing device 210 and this link is the first to initiate sealing contact with the surface 61 and the surface 140. This series activation is preferred to limit the drag of the upper ring links 334, 336 down the surfaces 61 , 140 upon activation if the upper links 334, 336 were to enter the sealing system before the lower link 338. Preferably, a balanced force acts on the upper ring link 334.

The elastomer elements 330, 332 form the initial seal. The elastomer seals 330, 332 abut against the surfaces 61, 140 before the edge fins on the joints 334, 336, 338 come into contact with the surfaces 61, 140. The elastomer seals 330, 332 will not be pushed out past the edge surfaces at an initial pressure application of a few thousand psi, ie 3000 psi (210 kp/cm<2>) of the sealing device 210. The links 334, 336, 338 form a support for the elements 330 and 332, an anti-extrusion device for such elements and act as a holder for such elements. Therefore, it is desirable that the edge surfaces of the joints 334, 336, 338 come into contact with the surfaces 61, 140 before the elastomer elements 330 and 332 are pushed out past the adjacent edge surfaces. It is not desirable that such extrusion past the edge surfaces takes place before the edge surfaces enter the sealing system, as any elastomer material between the edge surfaces and the surfaces 60, 140 may adversely affect the sealing engagement of the joints 334, 336, 338. As shown and described, the volume of the elastomer material in the elements 330 and 332 is therefore calculated and predetermined, so that the edge surfaces contact the surfaces 60, 141 before any extrusion of the elements 330, 332.

The joints 334, 336, 338 are constructed sufficiently thin that they deform into sealing engagement with a pressure application of a few hundred kp/cm<2>. The coupling rings 340, 342, 346 form stress points or weakened areas around the annular Z-part 220 so that the bending of the Z-part 220 is localized to predetermined points to bring the inner and outer edge surfaces of the Z-part 220 into correct sealing engagement against the bore wall 61 and the outer wall 140 Upon activation, the edge surfaces are pressed against the bore wall 61 and the outer wall 140 to form a metallic seal between the wellhead 24 and the pipe hanger 50, whereby the upper annulus 134 is sealed from the lower annulus 130 in the well. The sealing device 210 is designed to ensure that there is no fluid channel or leakage path between the surfaces 61 and 140.

In the sealing position, the lower link 338 bends at the coupling ring 346 whereby the outer side 343 of the lower link 338 is moved downwards into engagement with the upper end 372 of the lower cam portion 222. The taper of the lower cam portion 222's surface 372 forms an initial deformation angle for the lower ring link 338. The surface 372 also ensures that the joint 338 will not become horizontal so that the joint 338 is prevented from loosening when the sealing device 210 is removed. When the lower end 364 of the drive part 218 is moved downwards, the upper joint 334 is bent at the coupling ring 344 so that the inside 333 of the upper joint 334 comes into engagement with lower end 364 when lower end 364 compresses Z portion 220. Intermediate link 336 is moved from its inclined position to a more horizontal position. The elastomer elements 330, 332 are compressed between the joints 334, 336, 338 and form a sealing engagement with the bore wall 61 and the outer wall 140. The edge surfaces of the joints 334, 336, 338 form circumferential sealing contact with the outer wall 140 of the pipe hanger 50 at 380, 382 and 384 and the joints 334, 336, 338 outer edges form a circumferential sealing contact with the bore wall 61 of the wellhead 24 at 386, 388 and 390. The sealing device 210 thus forms a six-point circumferential metallic sealing contact. The sealing contact of the inner and outer edge rafts means that the joints 334, 336, 338 act as extrusion-preventing rings for the elastomer elements 330, 332. The elastomer elements 330, 332 act as support or auxiliary seals for the metal seals.

When the links 334, 336, 338 are moved from their inclined position to a more horizontal position upon activation, each end or each inner and outer edge surface of the links 334, 336, 338 is moved into engagement with the bore walls 61 and 140. It is not intended that the links 334 , 336, 338 should become horizontal. It is essential that the inner and outer edge surfaces of the joints 334, 336 and 338 are tensioned between the bore wall 61 of the wellhead 24 and the outer wall 140 of the pipe hanger 50. The inner and outer edge surfaces of each joint react to each other's bearing load. When e.g. the inner edge surface 356 of the joint 336 rests against the pipe hanger wall 140, this installation will cause a reaction force on the outer edge surface 358, which causes the outer edge surface 358 to move against the bore wall 61. If each joint did not have an opposing edge surface, the joint would continue to move downward until its side surface supports against an adjacent joint instead of moving into sealing engagement against either wall 61 or 140. This contact against either the outer or inner edge surface makes it necessary to prevent bulging or bending in the middle part of the joint. The diamond-shaped cross-section therefore requires that the middle part of the joint must be rigid, so that it cannot bend or yield. If the joints 334, 336, 338 were allowed to come into a horizontal position, the tolerance between the inside diameter of the wellhead 24 and the outside diameter of the pipe hanger 50 would also become critical. When the joints 334, 336, 338 are not horizontal, but inclined, it also becomes easier to release the Z part 220 by pulling out the sealing device 210. The surface 364 of the drive part 218 and the surface 372 on the lower edge part 222 are tapered to prevent the joint 334, respectively and 338 from assuming a horizontal position.

It should be understood that the elastomer seals 330, 332 will not be necessary if the edge surfaces of the joints 334, 336, 338 lie sufficiently against the surface 61 of the wellhead 24 and the surface 140 of the pipe hanger 50 so that hydraulic pressure can occur in the annulus 134. The elements 330 and 332 can thus is looped in certain applications where there will be a void between the links 334, 336 and 338. Furthermore, it should be understood that the elements 330 and 332 can be replaced by a spacer element which allows a predetermined degree of compression or deformation of the links 334, 336, 338. As shown in the present embodiment, the elastomer elements 330 and 332 become such a spacer element. Moreover, the present invention is not limited to an elastomeric material. Elements 330 and 332 may be made of other resilient materials such as Grafoil, a pure graphite packing material manufactured by DuPont. Grafoil can especially be used where fire resistance is desired. "Grafoil" is described in the publications: "Grafoil - Ribbon-Pack, Universal Flexible Graphite Packing for Pumps and Valves" by F.W. Russel (Precision Products) Ltd., Great Runmow, Essex, England and "Grafoil Brand Packing" by

Crane Packing Company, Morton Grove, Illinois. Reference is hereby made to these publications.

It should also be understood that if a metallic seal is not desired, the channels 366, 368, 370 and 374 can be used to convey elastomeric material to the surfaces 61 and 140 to form a primary elastomeric seal instead of a primary metal seal as described in connection with the preferred embodiment.

If the elastomer seals 330, 332 are the primary seals, the ring joints 334, 336, 338 become the primary support for the elastomer seals 330, 332. These joints become activated support rings for the elements 330, 332. In such a case, the support seals will not be pulled down into position.

The device according to the present invention is designed for 15,000 psi (1050 kp/cm<2>) working pressure and it is therefore an object of the invention to achieve a compression of 20,000 psi (1400 kp/cm<2>) compression on the sealing device 210, whereby the sealing device 210 is pre-activated higher than the expected working pressure.

To achieve a compression of 20,000 psi on the sealing device 210, it is actuated by a combination of torque and hydraulic pressure. Initially, a torque of approx. 10,000 ft.-lbs (1383 kgm) at surface 18. Tongs are used to rotate the drill pipe 236 to transfer the torque to the lowering tool 200 and then pressure to the sealing device 210. The drill pipe 236 rotates the mandrel 230 which in turn rotates the outer sleeve 250 at with the help of the rifle coupling 320. The outer sleeve 250 drives the packing nut 182 with the help of the rifle coupling to the cams 198, 308. The packing nut 182 rests against the drive part 218 during the transfer of pressure force through the bearing device 205. As the hold-down actuator device 212 has previously reached the limit of its downward movement against the locking ring 144 during movement to the holding position, the sealing device 210 and in particular the Z part 220 is compressed between the drive part 218 and the lower cam part 222.

This torque causes an axial force of approx. 150,000 Ibs (68,100 kp).

When the Z portion 220 is compressed between the drive portion 218 and the lower cam portion 222, the elastomer elements 330, 332 are compressed between the joints 334, 336, 338 as the joints 334, 336, 338 are moved to a more horizontal position. When this compression occurs, the elastomer elements 330, 332 begin to completely fill the grooves formed between the joints 334, 336, 338 which accommodate the elastomer elements 330, 332. The amount of elastomer material in the elastomer elements 330, 332 is predetermined, so that when the joints 334, 336 , 338 is moved to a more horizontal position, the joints 334, 336, 338 achieve sufficient contact with the bore wall 61 in the wellhead 24 and the outer bore wall 140 in the pipe hanger 50 to act as an extrusion-preventing metal device that prevents extrusion of the elastomer seals 330, 332. the internal annular contact surfaces 382, 384 prevent extrusion of internal elastomer element 332 and the annular contact surfaces 386, 388 prevent extrusion of external elastomer element 330. Accordingly, an initial extrusion-preventing seal is achieved by means of joints 334, 336, 338 before elastomer elements 330, 332 can be pressed out past its adjacent annular sealing contact surfaces. It is essential that the elastomer elements 330, 332 have the correct volume of elastomer material and the correct shape, so that by compressing the sealing device 210, extrusion-preventing metal contact is achieved before extrusion of the elastomer elements 330i, 332 past the contact surfaces 382, 384, 386 and 388.

The particular purpose of the initial torque is to engage the elastomer support seals 330, 332, and it is not to create a metallic seal between the surfaces 61, 140 of the wellhead 24 and the tubing hanger 50, respectively. The initial torque cannot fully activate the metallic sealing device 210 due to friction losses in the riser, the safety valve stack, the drill pipe itself, and more specifically, due to various thread loads such as at the threads 118. Such friction losses limit the compression load that can be applied to the sealing device 210 by means of the drill pipe 23 6.

In order to achieve the desired compression fit of the sealing device 210, hydraulic pressure is combined with the torque to engage the metallic seals in the sealing device 210. In fig. 2A and 2B, the exhaust safety valve 40 is shown schematically and comprises shut-off valves 34 with shut-off line 38 in communication with the annulus 134 below the safety valve shut-off valves 34. Conventionally, the shut-off line 38 is located below the bottom shut-off valve. Should the throttle line 36 for one reason or another be the lowest line in the safety valve 40, hydraulic pressure is supplied through the throttle line 36.

When applying pressure through the kill line 38 and into the annulus 134, it is necessary to seal the annulus 134. Note in fig. 2A that the kill wire 38 is shown in phase with the shut-off switches 34, but in reality is produced 90° out of phase. Thereby, the pipe stoppers 34 close for sealing around the drill pipe 236, the O-ring seals 264, 266 seal between the mandrel 230 and the sleeve 240, the O-ring seals 292, 294 between the sleeve 240 and the inner surface 272 of the pipe hanger 50, and as discussed above, the sealing device 210 forms the initial seal across the annulus 134. Hydraulic pressure can thus be supplied through the kill line 38 and into the annulus 134.

Due to the corkscrew effect resulting from the application of torque to a drill string, such as drill string 236, a torque of 10,000 ft-lbs (1383 kgm) is generally considered to be the highest torque that can be transmitted through a drill string in a subsea situation. In the present invention, a torque of 10,000 ft-lbs on the drill pipe 236 will create a seal over the annulus 134 that can withstand a hydraulic pressure of a few thousand psi. This seal for a relatively low pressure will then allow the annulus 134 to be pressurized for further compression by the sealing device 210 which in turn increases the sealing engagement in the annulus 134 to resist further hydraulic pressure. The annular Z-metal portion 220 with the ring joints 334, 336, 338 is constructed so that the rings 334, 336, 338 are sufficiently thin to create a metallic seal in cooperation with the elastomer seals 330, 332 to withstand a hydraulic pressure of a few thousand psi when applying a torque of 10,000 ft-lb.

When applying pressure to the sealing device 210, the effective pressure areas are the diameter of the downhole tool seal 264 minus the diameter of the drill pipe 236 and, in addition, the annular sealing area of the sealing device 210. As the annular seal area is determined for a wellhead and a pipe hanger of a certain size, the main variable in determining the pressure application force is the difference in pressure area between the lowering tool seal 2 64 and the drill pipe 236. This difference can thus be varied to allow a predetermined pressure application force of the sealing device 210. The difference in diameter can vary, e.g. from between 5 inches (127 mm) and 10 inches (254 mm).

The special task of the hydraulic pressure is to provide an axial force capable of inducing 20,000 psi (1400 kp/cm<2>) in the sealing device 210 without exceeding the pressure limits for which the apparatus in the wellhead system is designed. The task of the torque on the nut 18 2 after hydraulic pressure is applied is to cause the nut 182 to follow the movement of the sealing device 210 when it is moved downwards under the influence of force and to prevent it from yielding when the hydraulic force is relieved. It is essential that a high torque, e.g. 10,000 ft. Ibs (1383 kgm) is maintained in the drill pipe 236 so that the packing nut 182 follows the sealing device 210 as the nut 182 could otherwise prevent the sealing device 210's downward movement. This procedure is repeated by gradually and continuously increasing the hydraulic pressure until the packing nut 182 has been turned a sufficient number of revolutions to ensure that a pressure application of 20,000 psi (1400 kp/cm<2>) is achieved at the sealing device 210.

The lowering tool 200 is a combination tool for applying torque to the holding and sealing unit 180 as well as helping to apply hydraulic pressure to the holding and sealing unit 180. The rotation of the drill pipe 236 to transfer torque via the lowering tool 200 to the holding and sealing unit 180 allows a initial sealing engagement of the sealing device 210 in the annular space 134 between

the wellhead 24 and the pipe hanger 50 whereby the hydraulic pressure so

can be applied to the annulus 134 for further engagement of the sealing device 210. When hydraulic pressure gradually and continuously increases in the annulus 134 through the kill line 38, the sealing device 210 is compressed into stronger sealing engagement against the surface 61 in the wellhead 24 and the surface 140 in the pipe hanger 50. When this sealing engagement increases, the sealing device 210 seal against an even greater annulus pressure. The pressure through the kill line 38 can thus be gradually increased until the sealing device 210 has a pressure setting of approx. 20,000 psi (1400 kp/cm<2>). The hydraulic pressure acting through the kill line 38 and the annulus 134 does not exceed the system's design limits. All systems have a standard working pressure that an operator must not exceed. The system according to the present invention is designed for a working pressure of 15,000 psi (1050 kp/cm<2>) and therefore the hydraulic pressure in the annulus 134 for full activation of the sealing device 210 cannot exceed 15,000 psi even if a pressure setting of 20,000 psi is desirable. A pressurization of the sealing device 210 of 20,000 psi is achieved without applying a hydraulic pressure in excess of 15,000 psi.

As the hydraulic pressure is gradually increased in the annulus 134 to achieve a compression or pressure application on the sealing device 210 of 20,000 psi, the packing nut 182, as a result of the continuous action of the torque of 10,000 ft-lb (1383 kgm) on the drill pipe 236, which is transferred to the skirt 250, following the sealing device 210 downwards in the annulus 134 on the threads 204. When relieving the hydraulic pressure through the kill line 38 and the annulus 134, the packing nut 182 prevents relaxation of the 20,000 psi pressure set on the sealing device 210 as a result of the engagement of the threads 204 with the pipe hanger 50.

It is essential that the elastomer seals 330, 332 are activated to seal engagement after application of the initial torque by means of the drill pipe 236. If the elastomer elements 330, 332 are not engaged, the hydraulic pressure supplied through the kill line 38 will be lost through the sealing device 210 to the lower annulus 130. However, the seal by means of the elastomer elements 330, 332 need only be sufficient to seal against a small increase in hydraulic pressure through the kill line 38 such as 500 psi (35 kp/cm<2>). After the initial seal is achieved, increasing hydraulic pressure will further compress the Z-portion 220 and the elastomer elements 330, 332 to increase the metallic and elastomeric sealing contact against the wall 61, 140. Such increased sealing contact will allow a continuous increase in hydraulic pressure through the kill line 38 for further activation of the sealing device 210.

The sealing actuator device described above is a simplification of previously known actuator devices. Prior art actuators direct pressure through the drill pipe to activate an internally opening piston system. A dart seals the end of the drill pipe bore to apply pressure through the piston system which in turn pressurizes the seal.

Although such an earlier actuator system could be adapted to the present invention, the arrangement according to the present invention has significant advantages compared to the known technique.

It may be necessary to increase the initial torque

to which the drill string 236 is exposed after the safety valve shut-off valves 34 are closed. Even if the rubber contact of the stoppers 34 against the drill pipe 236 does not create the friction loss that a metallic contact would create, a certain additional friction loss will occur. Consequently, if possible, additional torque may be applied to the drill string 236 above the initial torque to overcome such frictional loss. However, the drill pipe 236 will rotate with the shut-off valves 34 in the closed position. The annulus between the riser and the drill pipe 236 contains well fluids which will cause well fluids to be located between the pipe stoppers 34 and the drill pipe 236 when the safety valve 40 is closed. It is thus assumed that the torque of 10,000 ft-lb will not be significantly reduced. If, as a result of the particular application, the friction between the pipe stoppers 34 and the drill pipe 236 must be reduced, a special pipe section, not shown, can be connected in series in the drill pipe 236 whereby the pipe stoppers 34 form an engagement with a stationary pipe element through which a rotary element passes to transmit torque past the stoppers 34. Such a special pipe section will include rotary seals between

the stationary element and the rotating inner element to prevent the flow of fluid.

In fig. 5A. 5B and 5C are shown the complete assembly of wellhead 24 with 16 inch (406 mm) pipe hanger 24, 13 3/8 inch (340 mm) pipe hanger 50, 9 5/8 inch (245 mm) pipe hanger 400, and 7 inch (178 mm) pipe hanger 410. The pipe hanger 50 is shown in fig. 5B in the holding and sealing position described in fig. 1-4 with the hold down and seal unit 180 activated in the hold down and seal position. The 9 5/8 inch pipe hanger is shown supported at 402 at the top of the pipe hanger 50. The pipe hanger 400 also includes a hold down and seal assembly 404 which can be compared to the assembly 180 of the pipe hanger 50. The 7 inch pipe hanger 410 is shown supported at 412 on top of 9 5/8 inch pipe hanger 400. Pipe hanger 410 includes a hold-down and sealing unit 414 that can be compared to unit 180. Figs. 5A and 5B show hold-down grooves in the wellhead 24, namely hold-down grooves 68 for pipe hangers 50, hold-down grooves 406 for pipe hangers 400, and hold-down grooves 416 for pipe hanger 410.

The pipe hangers 400 and 410 do not require a shoulder ring such as the shoulder ring 128 of the pipe hanger 50. Since the pipe hangers 400, 410 carry a small load, the size of the contact bearing area required for the pipe hanger 50 is not necessary for the pipe hangers 400, 410. The pipe hanger 50 requires one hundred percent contact area which is not necessary for the pipe hangers 400, 410. Furthermore, the shoulders of the pipe hangers 400, 410 are square and are leveled at the top of the carrier hanger.

Fig. 5C shows an alternative embodiment of the detachable pipe hanger carrier seat device or bottom piece housing seat 70, shown in fig. 2C. In fig. 5C shows a modified bottom-piece-housing-seat 420 for immersion in the bore 60 and connection to the tooth segments 66 in the wellhead 24.

In certain areas, there are formations below 20 inches (508 mm) of casing that cannot take the pressure of the weight of the mud used to maintain bottom hole pressure. To prevent fracturing of this formation due to the weight of the mud, it will be necessary to run a 16 inch (406 mm) casing string through this formation prior to drilling the hole for the 13 3/8 inch casing. The modified housing seat 420 carries 16 inches of casing. The housing seat 420 thus acts both as a carrying shoulder for the pipe hanger 50 and as a pipe hanger for 16

inch casing 422.

The housing seat 420 comprises a solid tubular ring 424 and a packing ring 426. The solid tubular ring 424 comprises outer teeth segments 428 which are generally similar to the tooth segments 76 that were described in connection with the housing seat 70. The ring 424 also has an upwardly facing and tapering conical seat or bearing shoulder 430 which is adapted to engage the packing ring 426.

The ring 424 also comprises a number of wedges 432, largely similar to the wedges 92 shown in fig. 2C, for locking the housing seat 24 in the wellhead housing 46. The ring 424 is provided with a socket end 434 for key engagement with the upper section of tubing in the 16 inch casing string 422.

The upper part of the ring 424 comprises a recess 438 for

to accommodate the sealing ring 426's tapping 440. The sealing ring 426 comprises external threads for threaded engagement with the internal threads in the recess 438 in the ring 424 for threaded connection at 442. The sealing ring 426 comprises an upwardly facing bearing shoulder 450 for engagement with the downwardly facing shoulder 132 of the pipe hanger 50. O-ring seals 444 and 446 are engaged in 0-ring grooves around the upper end of the packing ring 426 for sealing engagement with the bore wall 61 in the wellhead 24. The packing ring 426 also includes 0-rings 452, 454 engaged in O-ring grooves above the thread 442 on the pin 440 for sealing engagement with the wall in the recess 438 in the ring 424. A test opening 456 is formed between the O-rings 452, 454 for testing the sealing ring 426.

Since the 16 inch casing string 422 must be cemented, the housing seat 424 has grooves or channels 435 shown in broken lines in FIG. 5C. The channels 435 comprise the usual slots, such as slots 86, 87 in the housing seat 70 and the wellhead 24 shown in fig. 3, and a series of circumferentially distributed slots through the continuous ring flange 85 which is aligned over the slots 86, 87. The slots in the flange 85 are narrower than the slots 86, 87 to prevent the seat 420 from passing through the wellhead 24. The packing ring 426 is arranged for after the cementation to

seal the annulus 134. To test the sealing ring 426, close the shut-off valves of the safety valve and seal the lowering tool

below the test opening 456 and the annulus 134 are pressurized. If there is a leak between the wellhead housing 46 and the sealing ring 426 or between the sealing ring and the recess 438,

it will be possible to put the annulus 134 under pressure. Also, there will be an increased hydraulic flow volume into the annulus 134 from the kill line 38. It is not necessary for the packing ring 426 to create a high pressure seal, as most pressures at this stage of the well completion will be in the range of less than 5000 psi (350 kp/cm <2>).

It should be understood that a different embodiment will include making the housing seat 70 and the pipe hanger 50 in one piece, whereby the seat 70 and the pipe hanger 50 can be lowered and arranged in the wellhead 24 in a single trip down the well. The pipe hanger 50 can e.g. including tooth segments for direct engagement with the wellhead tooth segments 66.

Another different embodiment could mean that the housing seat 24 tube ring 424 was extended, whereby the sealing device 210 and/or the actuator holding device 212 could be placed directly on the housing seat 420 and between the seat 24 and the wellhead 24

for sealing and/or hold-down engagement with the wellhead 24. In this case, the sealing ring 426 would no longer be necessary.

Claims (7)

1. Device comprising a holding and sealing unit (180) for placement in a wellhead (24) for a well, between a wellhead housing (46) and a pipe hanger (50, 400, 410) which is carried on a support element (70) or a casing hanger (420) in the wellhead housing, which holding and sealing unit has an upper drive part (218), a middle seal part (220), and a lower comb part (222), which upper drive part is mounted on the pipe hanger (50, 400 , 410) and arranged for axial movement in relation to this, which lower cam part cooperates with a locking element (144)) which is arranged on a shoulder (116) of the pipe hanger, there being also arranged an activation means (182, 250) for application of an axial force on the upper driving part (218) and compression of the middle sealing part (220) between the upper driving part and lower cam part, characterized in that the middle sealing part (220) comprises a number of frustoconical metal rings (334, 336, 338) which have inner and outer edge surfaces and are interconnected for to form a unitary stack of such rings, which unitary ring stack has an upper edge integrally connected to a lower peripheral edge (364) of the upper drive portion (218) and a lower edge integrally connected to an upper peripheral edge (372) of the lower comb part (222), the middle sealing part's metal rings, upon activation of the holding and sealing unit (180) is deformed to a larger cone angle so that their inner and outer edges are moved into metallic sealing engagement with the pipe hanger (50, 400, 410) and wellhead -the house's bore wall (61). 2; Device according to claim 1, characterized in that the frustoconical taper of each metal ring (334, 336, 338) runs in a direction opposite to the frustoconical taper of the neighboring metal rings, the metal rings, the upper drive part (218) and the lower comb part (222 ) all have an external dimension which is smaller than the diameter of the bore (61) in the wellhead housing, and as the metal rings have central parts which resist bending when the central sealing part (220) is compressed. 3. Device according to claim 1, characterized in that the middle sealing part (220) comprises annular links (340, 342) which connect neighboring metal rings (334, 336, 338). 4. Device according to claim 3, characterized in that other annular links (344, 346) connect the end metal rings (334, 338) in the ring stack with the adjacent upper drive part (218) and lower cam part (222) whereby all said links form a positive connection between the upper drive part and lower cam part. 5. Device according to claim 4, characterized in that the annular joints (340, 342, 344, 346) have a width that allows the joints to be bent and allows the edge surfaces of the metal rings (334, 336, 338) to rest against the pipe hanger's (50, 400, 410) wall and the borehole wall (61) of the wellhead housing. 6. Device according to claim 3, characterized in that each of the annular joints (340, 342) and adjacent metal rings (334, 336, 338) form a means for receiving an annular spring element (330, 332) to create an elastomeric seal between the pipe hanger (50, 400, 410) and the bore wall (61) in the wellhead housing. 7. Device according to claim 1, characterized in that the upper drive part (218) and lower cam part (222) both have a frustoconical surface (364, 372) which faces adjacent metal rings (334, 338) on the ends of the ring stack, and that end- the metal rings (334, 338) have frustoconical tapers that taper in the same direction as, but with smaller cone angles than, each frustoconical surface (364, 372) on the upper drive portion and lower cam portion.