DE3305310A1 - HANGER INSERT - Google Patents

Description

The invention relates to a hanger insert with a sawtooth connection for a variety of pipe hangers for use in an underwater wellhead.

The increased drilling of holes in the coastal area requires increased working pressures, so that It can be assumed that with new boreholes to be developed

Working pressures of 1054.65 kp / cm ² (= 10.342 χ 10 ⁷ N / m ² = 15,000 ps; i) will occur. To cope with these high Ar-IG pressures in subsea drilling and casing, new wellheads are required. Drill holes with working pressures up to 1054.65

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kp / cm are currently being developed off the coast of Canada and in the North Sea, at depths greater than 90 meters (300 feet). For such wells floating drilling rigs are generally required, which are provided with a dowel compensation for the riser pipe and the drill pipe, which extend to the eruption shut-off device and the wellhead on the seabed. The eruption shut-off device is usually connected to a 20 inch pipe (= 50.8 cm) with the riser pipe extending to the surface. A quick-release connection is often provided on the eruption shut-off device, while an articulated connection enables the drilling rig to move. The two greatest difficulties with underwater wellheads, which have to be used at such high working pressures, occur on the one hand with the carrying shoulder, which carries the casing and is exposed to full pressure, and with the sealing between casing hanger and wellhead, which is acted upon by the working pressure and must withstand this.

The conventional wellheads had sufficient support forces for successive casing hangers. However, at elevated working pressures and when lowering and supporting multiple columns of casing

and a plurality of risers within the wellhead a narrow shoulder shoulder can no longer cope with the load. One might think of this difficulty because of this to eliminate that the shoulder is designed large enough to accommodate the hangers and the pressure to resist, however, their engagement with the wellbore in the wellhead casing results in reduced access to it the hangers below the wellhead housing for drilling purposes. Previous ocean drilling required subsea wellheads 16 3/4 inches (= 42, 545 cm) a re-drilling. At that time most of them were swimming Drilling rigs with 16 3/4 inches (= 42.545 cm) eruption shut-off devices provided by the previously required double device of 20 inches (= 50.8 cm) and 13 5/8 inches (= 34, 60 cm) and the two-riser system to replace. When adapting wellheads to

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Working pressures of 703.1 kp / cm instead of 351.55 kp / cm became a support shoulder of 18 3/4 inches (= 47.625 cm) designed to support the hangers while maintaining full accessibility to the hangers below the wellhead housing.

A second difficulty lies in the sealing. the

2 Waterproofing must be able to withstand pressures of 1054.65 kg / cm take in and resist them. Conventional energy sources operate to operate the sealing devices with weight, hydraulic pressure and torque. Each sealing device requires different ones Amounts of energy to be operated. The exposure to weight is undesirable because of the difficult handling the drill sleeves that exert the weight and also time consuming. The transmission of hydraulic Printing via the drill pipe requires appropriate cabling to send and receive signals from the hydraulically operated drives that move the seal. If no signals are used, the stake is of so-called "wet pipes" extremely cumbersome and accordingly unpopular with drilling teams. Becomes the

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The sealing device is driven by the one-way pipe hanger technology used, the sealing fluid can cause difficulties in the hydraulic system, which is used to operate the sealing device, with maintenance also being difficult brings. While it is desirable to use torque to operate the seal, it does exist Limits of the force to be applied, which is transmitted from the surface, due to friction losses the riser, in the eruption shut-off device, the various thread transmissions and in the drill pipe self.

The wellhead installation according to the invention overcomes the known disadvantages and at the same time offers a number of advantages. The arrangement is simple, less than 50 has components and is for denfl-, ^s ~ suitable ^use. The arrangement is intended for one-way design, but can also be used for reusable processes. All hangers are interchangeable so that they can be placed in lower positions. The sealing parts are interchangeable and are energized in order to withstand a pressure which is greater than the assumed working pressure in the borehole. Stop seals can be used. The seals are not deactivated. The hangers can be let in without any shut-off devices and the sealing arrangements provide a seal even if the hangers hit the top.

The housing insert withstands loads of more than 2,718,000 kg (working pressure and weight of the pipe material or test pressure) without exceeding 150% the resistance of the material to compression pressure. The wellhead leaves a drill bit 17 1/2 inches (= 44.45 cm) in diameter through. The present invention avoids leaning on two Types of bets at the same time or at the same time on two

Sentences. The housing insert is insensitive to the Pick-up of contaminants while drilling or while entering 13 3/8 in. Pipe (= 33.97 cm) diameter. The housing insert also does not require, nor does it require, an extra inlet process he insert rings in the hole.

The hanger lock can withstand a force of 900,000 kg. The lock is withdrawn mechanically, when the hanger body is caught up and is rait compatible with the one-way method. The hanger lock will released to catch up the casing hanger when the seal assembly is released. The hanger lock is also compatible and enabled with the reusable method letting in the hanger with or without the locking device. The sealing device works even if the locking device is not used. The hanger lock is reusable and has a minimal Number of tolerances. between the locking grooves.

The sealing device of the invention effectively seals a, annular area from about 18 1/2 inches (= 46.99 cm) outside diameter and 17 inches (= 43.18 cm) inside diameter

knife and exerts a pressure of more than 1050 kp / cm

(14 00 kp / cm nominal) when it is pressurized

2 and is subjected to a pressure of more than 1050 kgf / cm.

The pressure exceeding the pressure of 1050 kgf / cm remains in the sealing device after the inlet tool has been removed. The sealing device is also operated to maintain the full Pressure, even if it has not been subjected to full pressure or has not maintained full pressure Has. The pressure on the sealing device is not released. The sealing device has a relatively large Sealing surface to avoid defects in the housing and / or contamination to compensate. Furthermore, it primarily has a metal-to-metal seal that

at the same time, the additional elastomer seals emerge prevented at high pressure. The sealing device according to the invention enables a release of the Metal-to-metal seal before it is caught up, with the elastomer seal also being removed during the catch-up is relaxed and reusable. The sealing device provides an essentially metallic connection between the upper part and the bottom of the sealing surface in order to be able to catch up with the lower ring. The order enables one-way operation. There are no discontinuous metal parts in the sealing surface, which can lead to irregular printing. The sealing arrangement includes a minimum number of parallel sealing surfaces to prevent leaks.

The sealing device is securely fastened in such a way that it can also flow past during operation Fluid is not affected. The design also enables reusable operation and is for all pipe hangers of normal sizes can be used.

An arrangement for actuating the sealing device

2 applies a force of 1400 kp / cm to this.

This is possible with one-way operation as well as with multi-way operation. It is also for all pipe hangers suitable within the wellhead system. The loading device brings the sealing device into its sealing position, even if the casing hanger hangs at the top, with full pressure being maintained after actuation. The loading device requires no remote engagement with locking threads and no shear pins; she is reusable and avoids remote intervention in a locking thread when it is moved the sealing nut.

The inlet tool for the casing hanger includes a connection between the inlet tool and the hanger, that can withstand a pipe weight of more than 317,000 kg. That

Inlet tool can generate an axial force greater than 407,000 kg to operate the sealing device. It can also be withdrawn into the pipe hanger, without an opposite torque being exerted.

The inlet tool can either be in the pipe stock or in the pipe string be operated.

According to the invention, a hanger insert with a saw Proposed tooth connection for a subsea wellhead assembly for marine drilling up to working pressures

2 on the order of 1050 kgf / cm is suitable. the Arrangement includes a wellhead, the hanger insert, a sealing arrangement for sealing the hanger insert within the wellhead with another pipe hanger and one or more other pipe hanger, which are carried by the hanger insert.

The wellhead has a 17 9/16 inch (44.16 cm) through bore for running a conventional 17 1/2 inch (= 44.45 cm) drill bit.

The hanger insert with attached pipes is brought in and with the wellhead to support a or several pipe hangers connected within the wellhead, whereby it is the working pressure within the wellbore resists and holds this work pressure. A sawtooth connection is between the wellhead and the Insert provided with the hanger insert inserted into the wellhead and rotated less than 360 ° is used to establish this connection. This sawtooth connection has six groups of six each Teeth, where they are spaced from each other and have no thread pitch. Appropriate Slots are arranged between adjacent groups of teeth so as to allow natural passage of the borehole fluid to enable. The hanger insert has an upper annular flange for termination the downward movement of the insert into the wellhead. This annular flange has grooves that with the

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Align slots for passage of borehole fluid. The grooves are narrower than the slots to prevent the hanger bit from migrating through the wellhead.

The upper surface of the annular flange has a support surface for receiving one or more others Pipe hanger. The support surface of the hanger insert carries the weight of the hangers and pipes in addition to the working pressure of 1050 kp / cm. The support surface of the saw teeth is larger than that of the hanger insert for the next pipe hanger.

The seal seals the hanger insert with the wellhead and the next pipe hanger. She gives orders to test the effectiveness of the seals achieved.

After inserting, connecting, sealing and checking the hanger insert, the next pipe hanger is attached to the Tube applied to the top of the hanger insert. A locking and sealing arrangement between the Well head and the next pipe hanger for locking and sealing the next pipe hanger then enters Action. Second and third pipe hangers are then successively inserted into the wellhead and in a similar manner Way sealingly connected to the wellhead. The hanger insert carries the three pipe hangers with attached Pipes and resists and lasts at the same time

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the working pressure of 1050 kgf / cm (15,000 psi).

In another embodiment of the invention the body of the hanger insert can be extended with a locking and sealing arrangement between the hanger insert and the wellhead can be provided. The locking and sealing assembly includes a Sealing part on with a variety of frustoconical Metal rings that are connected to one another via Z-shaped metal rings. Adjacent metal links form ring-

shaped grooves for receiving elastic materials made of elastomer. A tool is provided for transmitting torque and hydraulic pressure on the locking and sealing arrangement so as to produce a first metal-to-metal seal and a Establish a second Elastotner seal between the trailer insert and the wellhead.

In the following the invention is explained in more detail with reference to the drawing explained, in which a preferred embodiment is shown. Show it:

Figure 1 is a schematic view of an overall system;

characters
2A, 2B, 2C

Figure 3

Cuts through the wellhead, hanger pressure ring, casing hanger inlet assembly, the sealing and locking arrangement and a schematic view of part of the eruption shut-off device for the subsea borehole shown in Figure 1;

an exploded view of the hanger insert with sawtooth connection and one Part of the wellhead of Figure 2;

Figure 3A is an enlarged view of the portion shown in Figure 3;

FIG. 4 shows a section through the sealing arrangement in the inlet position and

FIG. 4A shows a section through the sealing arrangement in FIG

the sealing position;

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5A, 5B, 5C sections through the wellhead with casing hangers for the 16 inches (= 40.64 cm), 13 3/8 inches (= 33.97 cm), 9 5/8 inches, (= 24.45 cm) and 7 inches (= 17.78 cm) recessed casing columns in the locked and sealed positions.

The wellhead assembly according to the invention is suitable for Letting, carrying, sealing, locking and testing of casing hangers within a wellhead for oil

or gas sources. Although the invention is suitable for all possible areas of application, it is shown schematically in FIG a typical arrangement for casing hangers and a casing column is shown with a wellhead on top Bottom of the sea for a sea hole.

In FIG. 1, 10 is the one to be drilled in the sea bed 12 Borehole referred to through the water 14 starting from an oil rig 16, which is on the water surface 18 swims. With a guide arrangement 20 is referred to, with 22 a guide tube, with 24 the wellhead, with 26 the eruption shut-off device with a Drudcontrol! Device and with 28 a riser pipe that is the floating rig 16 is lowered and penetrates the sea floor 12. The guide tube 22 can so be deeply embedded in the seabed 12 until the wellhead 24 rests in the vicinity of the seabed 12 or, As Figure 1 shows, engages in an enlarged borehole 30, which is used for letting the guide tube 22 into the Seabed is drilled. The guide device 20 is attached to the upper end of the guide tube 22 on the sea bed 12 and the guide tube 22 is in the borehole 30 by means of a cement column 32 which extends along a substantial Partly extends, anchors. The eruption shut-off device 26 is detachable via a suitable connection with the Wellhead 24 connected, which is on the seabed 12 · arranged guide device 20 is arranged and one or more eruption shut-off devices, such as 40, having. Such eruption shut-off devices have a number of tight gripper jaws, such as 34, which can be operated from the housing of the eruption shut-off device for sealing and releasing engagement with a pipe, e.g. dried up. The riser 28 extends from the top of the eruption shut-off device 26 to the floating drilling rig 16. The eruption shut-off device 26 has "delivery and dead center lines" 36 and 38, which extend up to the upper

area 18 is enough. These lines are required, among other things, to test the gripper jaws 24 of the shut-off device 40. For this purpose, a TesLi; pot is let through the riser pipe 28 into the borehole to seal it at the level of the borehole head 24. Thereafter, the gripper jaws 34 are actuated and closed while pressure is supplied through the dead center line 38, with a valve on the delivery line 36 the gripper jaw 34 is closed for testing purposes.
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The drill string including a conventional 17 1/2 inch (44.45 cm) drill bit is threaded through the riser pipe 28 and the guide tube 22 sunk to deepen the borehole 22 in the seabed for the casing 44.

A casing hanger 40, shown in Figure 2C with the casing 44 is shown, is lowered through the guide tube 22 until the hanger 50 is seated and with the wellhead 24 is connected as it will be explained in more detail. More inner risers and casing pipes are then added brought down and fastened in the wellhead 24, as is still in connection with FIGS. 5A, 5B and 5C will be described.

The wellhead 24 shown in FIG. 2C has a housing 26 with a reduced diameter at the lower end 48 as well as a downwardly directed, inwardly conical decreasing shoulder 52. The lower diameter end 48 has a reduced tubular member 25 at its end, the one pointing downwards and inwardly conically increasing smaller shoulder 56 forms. The guide tube 22 is a tube with an outer diameter of 20 inches (= 50.8 cm) and is welded to the tubular portion 54 at the bottom of the wellhead 24. the The wall thickness of the guide tube 22 is 1/2 inch (= 1.24 cm) with an inner diameter 62 of 19 inches (= 48.26 cm) initially pick up the drill bit and bit for drilling hole 42 and later pick up casing 44 as it is is shown in FIG. The casing 46 of the borehole

head has an opening 60 with a diameter of approximately 18/11/16 inches on (= 47.47 cm) that a little is smaller than the inner opening 62 of the guide tube 22.

Inside the wellhead opening 60 are a plurality of locking detents 64, locking part teeth 66 and four annular grooves (see FIG. 5B) such as the groove 68, above the locking part teeth 66. The teeth 66 have an inner diameter of approximately 17 9/16 Inches (= 44.61 cm) to pass conventional 17 1/2 inch ( -A'i, 45 cm) drill bits for the borehole

The wellhead 24 has a removable insert for the casing carrier or plug housing insert 70, which can be lowered into the opening 60 and can be connected to the teeth 66. The insert 70 includes a solid annular hollow ring 72 with a smooth inner opening 74, outer locking piece teeth 76 leading to the Engagement with the plug teeth 66 of the wellhead housing 46 are suitable, also an upwardly directed one , insert or shoulder 80 that decreases conically downwards to accommodate the casing hanger 50 and a subassembly 78 for securely connecting the insert 70 within the wellhead housing 46.

The bore 74 of the fixed ring 72 has an inner diameter of 16.60 inches (= 40.79 cm) and is conditioned thereby an effective horizontal thickness of the conical support ...

shoulder 60 of approximately 1.3 inches (= 3.30 cm) for absorption of the casing hanger 50. The insert 70 has a wall thickness that is large enough to deform the insert 70 at a vertical compression pressure of

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6328 kp / cm to prevent. This is important because, because of its size, weight and thickness, the wellhead 24 is a very rigid component compared to the housing insert 70 which is relatively flexible.

As Figure 3 shows, the housing insert 70 has a variety of

number of groups 82 of segmented teeth 76 on, with areas or spaces 86 therebetween, for receiving corresponding groups 88 of segmented Teeth 66 in the well housing 46 shown in Figure 2C. The teeth 66, 76 can have slopes, but are advantageously teeth without slopes. They are also not designed in such a way that they are with Rotation of the insert 70 for connection to the wellhead 24 interfere with each other. The teeth 66 of the wellhead taper inwards and downwards to facilitate the passage of the chisel. Would the teeth 66 have a rectangular cross-section or a sawtooth cross-section, they could cut the chisel through the Interfere with the wellhead 24 for drilling the hole 4 2 for the casing 44. The teeth 76 are of adapted shape to securely engage teeth 66 of the wellhead to be able to. The groups 82, 88 each have six rows of teeth divided into segments, whose thickness from base to surface is approximately 1/2 inch (= 1.27 cm). The thread surface of the six rows of teeth 66, 76 exceed the shoulder surface the support shoulder 80. A continuous upper annular flange 85 on the insert 70 above the teeth 76 limits the engagement of the groups of teeth 82 in the spaces

87. The upper annular flange 85 prevents the passage of the insert 70 through the wellhead 24. The lowermost tooth segment 84 is oversized to prevent premature rotation of the insert 70 within the wellhead 24 before the insert 70 rests on the annular flange 85.

The six rows or groups 82, 88 of teeth 66, 76 'represent an even number of rows to be even Support and distribute the load. Such a configuration distributes the forces evenly to the teeth 66, 76, which are divided into segments. By providing The teeth 66, 76 of six groups of teeth can be offset by turning the housing insert 70 by 30 °.

tied, i.e. divided by the number of groups by 180 °. If the teeth 66, 76 were divided into segments longer, the housing insert 70 would have to be rotated through a larger angle for connection. Preferably are the teeth 66, 76, which are divided into segments, have the same length, thus providing a maximum contact surface for absorbing the load to obtain.

The teeth 66, 76 can also be circular grooves with slots or recesses 86, 87 for connecting. the Teeth 66, 76 have a helix angle 0 and taper to increase the thread surface, so that the Threads 66, 76 withstand greater shear stress. The taper of the teeth 66, 76 is greater than 30 ° and preferably about 55 °, so that the thread area is significantly increased. This tooth profile is for this suitable to compensate for the stresses over all teeth 66, 76 which are divided into segments, so that the teeth 66, 76 cannot be deformed.

The teeth 66, 76 can also have a sawtooth shape be. A rectangular cross-section of the teeth 66, 76 would pick up contaminants from the oil well. A Another advantage of this sawtooth connection between the wellhead 24 and the housing insert 70 is that that the segmented teeth 76 clean the segmented teeth 66 when the insert 70 is rotated within the wellhead 24. The teeth 76 free the teeth 66 from any contamination, these falling into the free areas 86, 87.

Continuous threads have several disadvantages. A large number of revolutions are required for the connection, whereby A slight reverse rotation is required at the beginning, by lowering the thread start slightly first intervention takes place. Furthermore, the same position is always applied during the rotary movement. The sawtooth connection between the housing insert 70 and the borehole

head 24 avoids these disadvantages. If the stake is 70 lowered into the wellhead 24 by a suitable inlet tool, the lowermost toothed segment 84 engages on the insert 70 into the uppermost tooth segment of the tooth segments 66 on the housing of the wellhead 24. The stake 70 is then rotated by less than 30 °, so that the groups 82 on the insert 70 within the free locations 87 between the groups 88 come to rest on the wellhead 24. The subsequent lowering of approximately 12 inches (= 30.48 cm) is essential and can be easily ascertained on the surface to ensure that the Housing insert 70 has engaged in the wellhead 24, and are brought into sawtooth connection by rotation can. The sawtooth connection according to the invention enables a clear indication that the insert 70 has fully engaged the wellhead 24. The sawtooth connection has the further advantage that the insert can be fully inserted into the wellhead 24 and a complete connection between the insert 70 and the wellhead 24 through a rotation of 30 ° he follows.

In Figures 2.C, 3 and 3A, the Kell connection 78 is shown, which has a plurality of outwardly biased stops 92 which each sliding in an outwardly directed recess 94 in the lowest tooth segment 84 of the fixed ring 72 are arranged. The stop 92 has flat sides 90, tapered upper and lower Pages 91 on, and a bore 96 on its inside for receiving a spring 98. Seals 93 are means Screws 95 are provided in recess 94 on either side of stop 92 leaving a slot free for the stop 92. The other end of the springs 98 engages in the bottom part of the recess 94 around the stops 92 to issue an outward bias. A locking catch 64 is provided between all six groups 88, so that the stop 92 on the fixed ring 72 in such a way

is arranged to be adjacent to a ratchet 64 after full engagement of the inner and outer teeth 66, 76 of the wellhead 24 and the housing insert The stop 92 is in the locking catch 64 by rotation of the ring 72 is prestressed within the thread 66 and thus terminates the rotary movement of the ring 72. An opening 102 penetrates the ring 72 into the recess 94 in order to release the stop 92.

Previously, the shoulder shoulders for the casing hangers were part of the wellhead casing and were large enough to withstand the casing and the pressure loads. With these integrated shoulder shoulders, however, was the Drilling in the wellhead housing for full access to the casing below the wellhead housing for drilling purposes limited. The use of a large enough

2 integrated shoulder for working pressures of 1055 kp / cm would limit the bore so that a conventional 17 1/2 inch (= 44.45 cm) chisel could not pass. Such subsea wellhead arrangements have been required. consequently re-drilling.

According to the invention, the insert 70, which can be used in a sawtooth shape, is an additional support shoulder that is only then installed gets into wellhead housing 46 when larger working pressures appear. The insert 70 is not installed until the casing 44 drilling operation is complete so that full wellhead access is assured is. Since only normal pressures are encountered for the outer casing 44 for drilling purposes, one is greater Shoulder not required. After drilling the casing 44 is complete, the insert 70 is installed to accommodate the pipes and loads up to 1055 kp / cm. This gives a sufficient opening before installing the insert 70 to insert the 17 1/2 (= 40.45 cm) chisel.

To install the insert 70 this is not with a

-29-Dargefetelte inlet tool connected via Shear pins / of which a part is denoted by 104. The inlet tool on the drill pipe then lowers the insert 70 into the bore 60 of the wellhead 24 until the lowest tooth segment 84 on the uppermost tooth segment sits on. The insert 70 is then rotated until the groups of teeth 88 on the wellhead 24 to the smooth Slide along surfaces 86 and the groups of teeth 82 on ring 72 in corresponding surfaces 87 of the wellhead teeth slide along. The continuous annular flange 85 sits on the uppermost tooth segment of the teeth 66 in the Borehole head 24. The insert 70 is then twisted through the drill pipe and the inlet tool for such a long time until the parts 78 strike the locking catches 84 to terminate the rotary movement. A pressure test can be carried out to be sure that the insert 70 is lowered. The pins holding the insert 70 with the grooving tool connect are sheared at 104 so as to expose the inlet tool.

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Figure 2C shows the placement of the top tube hanger on the housing insert. 70 within the wellhead 24. The hanger 50 has a generally tubular body 110 having a lower threaded portion Has part 112, which is threadedly engaged with the upper . Connecting part of the tube 44 stands around it within of the borehole 4 to hold 2 and a thickened upper portion 140 with an outwardly protruding radial annular shoulder 116 and a plurality of annular grooves 120 (see Figure 2B) on the inner circumference of the Body 110 for connection to the inlet tool 200 as it will be described in more detail.

In Figures 2A and 2B, threads 118 are provided which extend from above over a substantial length of the exterior of the annular body 110 extend for engagement with a locking and sealing arrangement 180, which will be described in more detail

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The cementing for the upper casing 44 in the wellbore 42 requires a passage from the lower ring 130 between the tube 44 and the guide tube 22 to the upper one Ring 134 between wellhead 24 and drill pipe 236 returning to the surface. A multitude of upper and lower grooves or circulation ports 122, 124 extend through the upper portion 114 for the passage of a fluid e.g. for permanent installation around the 50 hangers around. The lower grooves 122 allow the passage of fluid through the radial annular

• Shoulder 116 and the upper grooves 124 allow the Passage of fluid through the threaded upper end of tubular body 110 around the fluid around the lock and bolt Guide sealing device 180 around.

The threads 126 are provided on the outer periphery of the upper portion 114 below the annular shoulder 116 for threaded engagement with the threaded shoulder ring 128 around the hanger 50. The shoulder ring 128 has a downwardly directed and tapered conical surface 132 / which is fitted to the upwardly directed, downwardly conically tapered support shoulder 80 in which engages the housing insert 70 conical surface 132 of the hanging shoulder ring 128 on and on the support shoulder 80 of the housing insert, the insert 70 having to withstand the pipes so arranged and the working pressures.

Boreholes with working pressures in the order of magnitude of

1055 kp / cm create special loads. The wellhead not only must the weight of the pipe hangers with their attached pipes and one or more riser pipe hangers withstand with their attached pipes / but also absorb this working pressure and withstand it. This means / that the wellhead must bear both the weight of the pipes and the pressure. A borehole

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head for 1055 kp / cm working pressure must have sufficient support and seat surface so that when the pressure is applied vertically there is no deformation of the wings. Although materials that can withstand loads of 31,700 kg are used at lower working pressures, for wellheads when working

printing of 1055 kp / cm requires a minimum resistance to loads of 38,500 kg. The inventive However, the drill head can withstand a load of over 2,718,000 kg, since its support surface is of the order of

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420 to 450 cm. During the design phase, this support surface must be designed in such a way that the load that occurs does not exceed the deformation resistance of the material in vertical loading by more than 25%.

The support surface between the lowermost pipe hanger 50 and the housing insert 70 and between the housing insert 70 and the tooth connection 66 at the wellhead 24 must be sufficiently dimensioned to withstand such loads, without the material strength in vertical exposure exceeding the dimensional strength by more than 25%. The wellhead assembly of the present invention meets this requirement.

In order to obtain a sufficient support surface between the pipe hanger 50 and the insert 70, the shoulder ring is 28 of the hanger onto the radial annular shoulder 160 extending from the upper portion 150 of the hanger body 110 extends, screwed on. The shoulder ring 128 forms a conical surface 132 extending through 360 ° Receipt of the carrying shoulder 80 of the housing insert 70 and thus enables complete contact between Shoulder 80 and conical surface 132. Without the shoulder ring 128 of the hanger, the grooves or obstructions prevent circulation 122 through the shoulder 116 a 360 ° support surface between the hanger 50 and the housing insert 70. The interaction between the support shoulder 80 and the conical surface 132 enables an additional one Support surface, which is determined by the inner diameter of the borehole

head of 17 9/16 inches (= 44.61 cm) and the inside diameter of the housing insert 70 of 16.06 inches (= 40.8 cm). As a result, the support surface is

2 between shoulder 80 and surface 132 about 450 cm, so that the entire support surface can withstand a load of more than 2,720,000 kg.

The inner and outer connecting teeth 66, 76 of the wellhead 24 and the housing insert 70 are designed so that they have a sufficient support surface to take the above load. As already mentioned, the rows of teeth 66, 76 have six groups 82 / 88 of teeth on wellhead 24 and housing insert 70. Each group 82, 88 has six teeth 66, 76 to Load on. The support surface of the sawtooth connection 66, 76 is larger than the support surface between the shoulder 80 and conical surface 132. The number of teeth is determined by the reduction in the support surface due to the six openings 86, 87 intended to receive corresponding groups 82, 88 during assembly.

In Figure 2C, the radial annular extends Shoulder 116 from the upper portion 114 of the hanger body 110, having an upwardly directed downwardly and outwardly tapered conical cam surface 136, with an annular groove 138 extending on its Base part extends upwards. An annular chamber 142 extends from the top of the groove 138 an annular perpendicular sealing surface 140 which in turn extends from the groove 138 to the lower end of the thread 118. The radial annular shoulder 116 is below the annular locking groove 68 located in the wellhead housing 56 after the hanger 50 touches down within the wellhead 24. The cam surface 136 terminates at its lower annular edge just above the lower end of the groove 68.

The pipe hanger 50 has a locking ring 144,

which is arranged on the radial annular shoulder 160 is. The locking ring 144 may be a slotted ring that can be retracted into the groove 68 engages wellhead housing 46 to lock hanger 50 within the wellhead 24. Wellhead groove 68 has a vertical base wall 146 with one upward and one upward downward tapering wall. The locking ring 144 has a vertical base 148, with a downwardly tapering surface corresponding to the extent of the upwardly tapering wall of the groove 68 and a downwardly tapered surface parallel to the downwardly tapered wall of the groove 68, so that at Expansion of the locking ring 144 extends the vertical surface 148 of the ring 144 on the vertical wall 146 the groove 68 rests. Furthermore, the locking ring 144 has a downwardly directed outward and downwardly tapering lower cam surface 152, which with an upwardly directed cam surface 136 of the radial annular shoulder 160 cooperates with an inwardly directed annular rib 154 in the annular Groove 138 engages in the retracted state and an upwardly and inwardly directed cam head 156 for cooperation cooperates with the locking and sealing arrangement 180, as will be explained will. Between the cam 156 and the annular rib 154 is a tapered surface 158 parallel to the Wall of chamber 142.

The protruding annular rib 154 engages the groove 138 of the pipe hanger 50 and prevents the locking ring 144 from being pulled out of the groove 138, when the tubing hanger 50 is inserted into the wellbore. During this introduction of the hanger 50, it is necessary that the locking ring 144 assumes a smaller diameter several times, for example during passage through the blowout shut-off device 40. This device 40 often includes an annular rubber seal

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on, which makes it necessary that the pipe hanger is pressed through this seal. Would be the annular rib 154 is not arranged in the groove 138, the ring 144 could hang on such a narrowed cross section stay and slide along the outer surface. As a result, he could get out of the groove 138, on the hanger 50 after slide up until it reaches the seal assembly 210. As a result, not only would the actuating device 212 blocked for locking, but also the actuation of the seal 210. The annular chamber 142 has enough clearance so that the groove 138 can receive the annular rib 154. This prevents also that the locking ring 144 is subjected to an upward load.

The locking and sealing device 180 is shown in Figures 2B and 2C, specifically in engagement with an inlet tool 200 in the locked position. The device 180 has a stationary Part 184 on which is rotatable on a rotating part or a Sealing nut 182 is fastened by means of a part 186. The sealing nut 182 has an annular Body on with a lower pin 188 and an openwork upper end 198 with upwardly protruding Stops 202. The inner wall of nut 182 has threads 204 that mate with outer threads 118 of the casing hanger body 110 intervenes.

The stationary member 184 has an annular body 216 and contains a seal assembly 210 for sealing the inner bore wall 61 of the wellhead 24 and the outer sealing surface 140 of the casing hanger 50 and an actuating device 212 for locking by acting on the locking ring 144 / the in Locking engagement within the groove 68 of the wellhead 24 arrives. The annular body 216 is a continuous and integral metal part with an upper drive piece 280, a Z-shaped intermediate

-35 part 220 and a lower cam part 222.

The upper drive part 280 has an upper counterbore 190 for rotatably receiving the lower pin 188 of the seal nut 182. The part 116 has inner and outer races in the counterbore 190 and in the Pin 188 on for receiving rollers or balls 196. The holding part 186 is not loaded and not for Transmission of a torque or a shock from the sealing nut 182 to the stationary part 184 is required. A support part 205 is provided above the sealing arrangement 210 and has support rings 206/208, the between the bottom of the counterbore 190 and the lower end of the pin 188 are provided. The support rings 206, 208 have a low coefficient of friction and allow sliding engagement between them Actuation of the drive device 212 and the sealing arrangement 210. The support arrangement 205 is thus used to transmit force from the sealing nut 182 to the stationary member 184. The retaining balls 196 are used exclusively the rotatable mounting of the stationary part 184 on the sealing nut 182.

The lock actuator 212 has a lower cam portion 222 with one down and one out directed cam surface 224 (see Figure 2C) to the cam-shaped Engaging in the cam 156 of the locking ring 144, as well as an upper drive part 280 and a Z-shaped intermediate piece 220 for power transmission on the sealing nut 182 to the lower cam part 222.

The seal assembly 210 includes a Z-shaped piece 220 and resilient interception seals 330, 332 that will be described in more detail in connection with FIG. 4, as well as an upper drive part 280 and a lower one Cam part 222 for pressurizing the intermediate piece 220. The sealing arrangement 210 is first Line a metallic sealing arrangement and only in

second, an elastic arrangement. A metallic seal has the advantage of a longer service life compared to an elastic seal.

The locking and sealing assembly 180 is through the casing hanger 50 and inlet tool 200 in drilled the borehole. The tool 200 has a bolt 230 which is the main part of the tool 200, a connector or sleeve 240, a rim or an outer sleeve 250, and a Nut 260. The bolt 230 has an upper end 232 internally threaded 234 for connection to the lowermost one Pipe section of a drill pipe 236 that extends to the surface 18 is enough and a lower end 238 also has an internal thread. Above the end 238 is an annular one Groove 242 is provided. Another reduced diameter part 248 is provided above the groove 242 and forms an annular rib 252. Below the upper end 232 and above the portion 248 is a third threaded part 254 of reduced diameter (see Figure 2A) is provided, the diameter of which is smaller than that of parts 24 2 and 248. -

The connector or collar 240 has a bore 246 which is dimensioned to be telescopically over the annular rib 252 and the end 238. The connecting part 240 is retractable from the ring formed by the bolt 230 and the rim 250. The rib 252 has annular sealing grooves 258, 262 in which O-rings 264, 266 sit to seal the inner surface of bore 246. The top of the connector 240 has an inwardly directed radial annular flange 268 that is slidable on the surface 248 is seated. The lower end of the connector 240 has a reduced diameter portion 270 that is dimensioned to fit into bore 272 of casing hanger 50 slidably fits. The part 270

33G5310

forms a downwardly directed annular shoulder 274 which forms the upper end portion 276 of the forage tube hanger after inserting the tool 200 of the locking and sealing arrangement 180 onto the feed tube hanger 50 receives into the wellhead 24. The part 270 has a plurality of slots distributed along its circumference or windows 278 in which slidably segments or stops 280 are arranged with a plurality of Teeth 282 for receipt by the grooves 120 of the casing hanger 50 so as to connect the inlet tool 200 to the casing hanger 50. The stops 280 have one upper protrusion 284 which engages an annular groove 286 along the upper inner periphery of windows 278. A plurality of sealing grooves 288, 290 with O-rings 292, 294 are provided above the windows 278 for receiving the sealing bore 272 of the casing hanger 50. Near the upper outer end of the Connection part 240 is provided with an annular groove 296 with a clamping ring 298 for assembly with the inlet tool 200. The stops 280 spring back into the grooves 24 2 after the lower end 238 is in its lower position assumes, as shown, by applying rotational force to the tool 200 about the locking and sealing assembly 180 to be installed.

The outer sleeve 250 has a generally annular body with an upper inwardly directed radial part 300, a middle part 302, a transition part 304 and a lower actuating part 306. Parts 300, 302, 304 and 306 are related and are sized to be telescopic the top end 276 of the hanger 50, the connector 240 and the bolt 230 can receive. The lower Actuating part 306 has a perforated lower end 308 which is the upper perforated end 198 of the Gasket nut 182 receives, so that a torque from the inlet tool 200 on the locking and Sealing device 81 can be transferred. Of the

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inner diameter of the operating part 306 is sufficient large to allow play with the outer diameter of the thread 118 of the pipe hanger 50.

The middle part 302 is slidable with the connecting part 240 connected. The part 302 has an inner annular groove 310 for receiving a clamping ring 298 on connector 240 upon disengagement from inlet tool 200 from locking device 180 and from the casing hanger 50. Part 302 has a plurality of threaded bores 312 extending from the outer periphery to Groove 310 extend so that bolts (not shown) can be screwed into groove 310 to release it of the clamping ring 298 on the groove 310 during engagement of the inlet tool 200 in another hanger. The clamp ring 298 has an upper cam surface 360 for engaging the pin ends. After intervention of the connecting part 240 into the upper part of the annular surface formed by the outer sleeve 52 and the bolt 230, wherein the clamping ring 298 is located above the groove 310, the connecting part 240 can no longer be removed without clamping ring 298. To connect the connecting part 240 after the insertion of the inlet system, To solve stuff 200, the bolts are screwed into the bores 312 in order to close the groove 310 and to prevent the clamping ring 298 from engaging this groove. As a result, the connecting part 2 40 can follow the bolt 230 slide down,

The transition part 304 adjoins the actuation part 306 and the middle part 302 and compensates for the change in diameter. Passage openings 318 are in the transition part 304 and allow the cement to flow back through the outer sleeve 250 into the annulus 134.

The upper radial end 300 has a perforated annular inner surface and can be cotter pins

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connected to the bolts 230 for the transmission of rotational forces will.

The connecting nut shown in Figures 2A and 2B 260 has an internal thread 324 for screw connection at 322 with the thread 235 of part 254 of the Bolt 230. The lower end face of nut 260 rests on the upper end of the outer sleeve 250 to determine this on the bolt 230.

In operation, the sealing nut 282 is only partially screwed onto the upper thread 118 of the casing hanger 50 / so that the bolt 230 is located on the hanger 50 in its inlet position. In this position the rib 252 is supported on that formed by the radial annular flange 268 on the connecting part 240 Shoulder 269 off. The outer annular surface of end 238 engages the inside of the stops so that the teeth 282 bias into the grooves 120 of the hanger 50 and a loosening of the inlet tool 200 and the hanger 150 when they are introduced into the borehole on the drill string 236. The inlet position of the inlet tool 200 is not shown.

After the surface 132 has been placed on the shoulder 128 of the casing hanger 50 on the shoulder 80 of the insert 70 in the wellhead 24, the casing 44 becomes cemented within the borehole 42. After cementing, the inlet tool 200 is rotated and a force exerted on the latch and seal assembly 180 around the same in the Figures To hold 2B and 2C shown locking position. A rotation of the drill rod 236 at the surface 18 causes a rotation of the bolt 230 and thus a rotation twisting of the outer cuff 250 due to the split pin connection 320. The torque from the cuff 250 is thereby over the sealing nut 182

-4 ΟΙ wear through the connection of stops 202 of the Nut 182 and the lower end 308 of collar 250. Nut 182 exerts an axial force on the locking mechanism Seal assembly 180 so that cam portion 222 of actuator 212 is in meshing engagement arrives with the cam 156 of the locking ring 144. This moves the locking ring 144 into the groove 68 of the wellhead is brought into engagement with the wellhead 146 so as to place the hanger within the wellhead to hold and lock, as shown in Figure 2 is. The sealing arrangement 210 has not yet been actuated for sealing between the annular space 134 and the annulus 130. The locking ring 144 requires a predetermined operating force and has a predetermined Contraction tension on. The cross section of the sealing arrangement 210 is chosen such that it does not prematurely compressed by the actuation and engagement of ring 144 by actuator assembly 212 will. The compressive force required for the seal assembly 210 is significantly greater than that to expand and actuate the ring 144. The bolt 230 moves with the edge 240 after actuation · the locking and sealing assembly 180 downward. This downward movement of the bolt 230 releases the stops 280.

The seal assembly 210 is shown in Figures 4 and 4A shown in the inlet and locking position and in the sealing position. The arrangement 210 has a metallic Z-shaped part 220, upper and lower elastic parts 330, 332 and an upper one Drive part 218 and a lower cam part 222 to compress the Z-shaped part 220 and elastic Parts 330, 332. The metallic annular Z-shaped part 220 has a plurality of annular intermediate members 334, 336, 338, which have an inclined position after detachment from the wellhead 24 and the hanger 50 after releasing and releasing the sealing arrangement 210 and

of the actuator 212 from the wellhead 24 The intermediate links also form a .Metal connection that extends from the drive part 3 218 to v.um lower cam member 222 extends so that the application in a to allow upward force on the lower cam member 522 after disengagement. For this reason the connecting rings 240, 242, 244 and 246 are advantageous, which could otherwise be omitted.

The connecting rings 344, 346 that are adjacent to the drive part and the cam part 222 must have a Have a minimum length in order to ensure a sealing engagement of the annular intermediate members 234 and 238. If the rings 244, 246 are too short, there is no sufficient binding to touch the Areas 61, 41 of the intermediate members ■ 234 and 238 to enable. Because the drive part 280 and the cam part 222 are considerably more massive than the connecting rings 244 and 246, portions 218 and 222 do not flex through to sealingly engage the intermediate members 334, 338. It is therefore essential that the connecting rings 344, 346 exhibit such a sagging behavior exhibit. The connecting rings 340, 342, 344 and 346 provide individual heavy-duty locations in the metallic Z-shaped part 220.

The Z-shaped metallic part 220 is made of a very soft, malleable steel, such as stainless Steel 316. The flow limit of such a material

2
is reached at about 2812 kgf / cm which is less than half the yield point of about 6000 kgf / cm 'of the wellhead 24 material and the hanger. When the Z-shaped metallic part 220 engages in a plastic manner, the latter begins to deform plastically, while the surface 61 of the wellhead 24 and the surface 144 of the hanger 50 tend to be elastically deformed. Are irregularities in the areas §1 and 41 vgrhanjen. _# § © causes dig

ness of the material of said annular Z-shaped portion 220, that the material in the irregularities of the surfaces 61 and 41 penetrate so as zubilden a high pressure metallic compound. The metallic Z-shaped member 220 can thus form a tight interference fit with the walls 61/41 of the wellhead 24 and casing hanger 50 when actuated.

The upper, middle and lower annular pontics 334, 336, 338 each have a diamond-shaped cross section. As the cross sections of the pontics 334, 336, 338 are essentially the same, a description of the intermediate member 336 is needed. It essentially has parallel upper and lower annular sides 348, 350, with the upper side 348 generally facing upward and lower side 350 facing generally downward and generally parallel, interior ones and outer annular surfaces 352, 354 with the outer side 352 facing radially outward and the inner side 354 points radially inward and parallel inner and outer annular sealing ribs 356, 358. The intermediate links 334, 338 have comparable top and bottom sides, inner and outer sides, and inner and outer sealing ribs.

In the locking position, the sealing ribs of the intermediate links 334, 336, 338 are essentially parallel to the bore wall 61 of the wellhead housing 46 and the outer wall 140 of the casing hanger 50 are deformed. The upper connecting ring 344 extends from the lower end 364 of the upper drive part 280-12 to the upper side 335 of the upper intermediate member 334 and forms an annular channel 366. The metallic Connecting ring 340 extends from the bottom 337 of the upper intermediate link 334 to the top 348 of the Intermediate member 336 and forms an annular channel 368, while the metallic connecting ring 342 from the lower side 350 of the intermediate member 336 to

upper side 339 of lower intermediate member 338 extends to form an annular channel 370. Of the lower link ring 346 extends from the lower side 341 of the lower intermediate link 338 to the upper end 372 of the lower cam portion 222 to form an annular channel 374. The annular channels 366, 368, 370 and 372 between adjacent webs facilitate the bending of the Z-shaped part 220 at predetermined ones Locations, namely on the torsion rings 340, 342, 344 and 346. The lower end 346 of the drive part 218 is substantially parallel to the top 335 of the upper intermediate member 334 and the upper end 372 of the cam member 222 is substantially parallel to the lower side 341 of the lower link 338. In the inlet position and in the locked position, the outer and inner sealing ribs are of the same diameter such as the outer and inner diameters of the upper drive part 218 and the lower cam part 222, respectively.

The upper and lower elastic parts 330, 332 are shaped to conform to the shapes of the annular grooves 376, 378 / formed by the intermediate members 334, 336, ' 338 are formed, are adapted and are glued to them. The upper and lower elastic parts 330, 332 have outer and inner annular vertical sealing surfaces 380 and 382, respectively, for sealing engagement on the bore wall 61 and the outer wall 140 in the sealing position. The upper and lower annular Bars, which are formed by the sealing surfaces 380, 382, are beveled to avoid deformation Sealing position of parts 330,332 at compression pressure to enable. The elastic parts 330, 332 are also beveled by a predetermined deformation of the Parts 330, 332 between the intermediate links 334, 336, 338 to enable. Although the cross sections of the elastic Parts 330, 332 are essentially the same, the inner elastic parts 332 may be more tapered or be tapered than the outer ones

elastic parts 330 to prevent premature deformation of the To prevent parts 330, 332 in front of the intermediate members 334, 336, 338 and thus an early seal with the wall 61 of wellhead 24 and outer surface 140 of the Casing hanger 50.

The sealing arrangement 210 preferably has at least three intermediate members. This number is advantageous » because it ensures a good connection with the elastic parts 330, 332 and a symmetrical design enables. However, the sealing arrangement 210 can also have more intermediate members with a plurality of elastic parts. The surfaces 364 and 372 of the drive portion 218 and the lower cam portion 222 are tapered advantageously in the same direction as the neighboring ones Intermediate members 334 and 338 as shown in the preferred embodiment.

The diamond-shaped design of the intermediate links 334, 336, 338 enables very rigid intermediate parts of the individual intermediate links, so that the end parts of reduced thickness of the intermediate links those places that deform or flex to contact the connecting rings 340, 342, 344, 346. It is undesirable that the central portions of the intermediate links 334, 336, 338 deform or bend. The one shown diamond-shaped cross-section is easy to manufacture; the intermediate links can also be continuous Can be made convex or ellipsoidal with a protruding central part. Would the cross sections of the pontics 334, 336, 338 have the same thickness, they would tend to bend at their central points. Although it is advantageous to provide thickened middle fins of the intermediate links 334, 336, 338, to define the deflection points on the ribs for given plastic deformations and none To allow disturbances of the center points of the pontics, but these can be as frustoconical metal

be designed rings whose cross-section is uniform.

In Figure 4A, the sealing arrangement 210 is in the sealing position shown. The assembly 210 is compressed, when the actuator assembly 212 abuts the locking ring 144 at the end of its advance and the seal nut 182 continues its downward movement on the threads 118 of the hanger 50 as in the figures 2B and 2C.

The metal-to-metal seal assembly 210 is repeatedly operated from top to bottom. That is, the bottom Intermediate member 338 is the first to deform due to the compression of seal assembly 210 and is that first link that is in sealing contact with surface 61 and 140. This series actuation is advantageous the resistance of the upper intermediate members 334, 336 along the surfaces 61, 140 when actuated of the upper links prior to sealing engagement of the lower link 338. Preferably a precisely predetermined force is exerted on the upper intermediate piece 334.

The elastic parts 330, 332 form the initial seal. They lie on the surfaces 61, 140 in front of the ribs of the intermediate links 334, 336, 338. Deforming the elastic seals 330, 332 over the ribs addition after an initial compression pressure of about

2
200 kp / cm on the arrangement 210 is to be prevented.

The intermediate members 334, 336, 338 form supports for the parts 330 and 332 and receive them. Therefore, it is it is desirable that the ribs of the intermediate members 33 ', 336, 338 the surfaces 61, 140 in front of the elastic parts 330 and 332 that protrude past the adjacent ribs. The appearance of elastic material between the ribs and the walls 61, 140 is detrimental to a seal; the size of the elastic parts

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330 and 332 are selected to be correspondingly small, so that the ribs touch the surfaces 61, 140 first.

The intermediate members 334, 336, 338 are designed to be thin enough to deform into a sealing engagement when a compression pressure of a few hundred kgf / cm is exercised. The connecting rings 340, 342, 346 form Pressure points or weak points around the Z-shaped part 220, so that the deflections of the part 220 are predetermined Place takes place and so the inner and outer ribs of the part 220 seal against the walls 61 and snuggle up. When actuated, the ribs rest against the walls 61 and 41 and thus form a metal-to-metal seal between wellhead 24 and hanger 50, with the upper annulus 134 also separated from the lower annulus is sealed. The sealing arrangement 210 is designed so that there is no fluid opening between the surfaces and 140 consists.

In the sealing position, the lower intermediate member 338 bends in the direction of the connecting ring 346, whereby the outer side 343 of the lower intermediate link 338 moves downwards and at the upper end 372 of the lower cam part 2.22 is applied. The taper of surface 372 of lower cam portion 222 provides a Initial deformation for the lower intermediate link 338. The surface 372 also ensures that the link 338 does not move horizontally, so that a loosening of the member when removing the seal assembly 210 does not occur.

When the lower end 364 of the drive part 218 moves downward, the link 334 at the connecting ring 344 flexes through / whereby the inside 333 of the upper. Gliede.-s 334 rests against the lower end 364 when the end 364 the Z-shaped part 220 is applied. The intermediate link 336 moves from its inclined position to a more horizontal position. The elastic parts 330, are compressed between the members 334, 336, 338 and are sealing against the wall 61 and the outer

applied 140. The inner ribs of members 334, 336 form annular sealing contacts with outer wall 140 of casing hanger 50 at 83, 382 and 384 and the outer ribs of members 334, 336, 338 form annular sealing contact with wall 61 of wellhead 24 at 386 , 388 and 390. The sealing arrangement 210 thus enables six annular Motall-metal sealing surfaces. Causes the sealing contact of the inner and outer ribs, that the members 334, 336, 338 retention arrangements for the elastic members 330, 332 which act as an additional seal to the metal seal.

When the links 334, 336, 338 move from their inclined position to a more horizontal position upon actuation each end or inner and outer ribs of the links come into contact with walls 61 and 140, the links 334, 336, 338 not lying horizontally come. It is essential that the inner and outer ribs of members 334, 336 and 338 be under pressure the walls 61 of the wellhead 24 and 140 of the casing hanger 50 abut. The inner and outer ribs each link is subjected to force by the others. Based on 2, B. the inner rib 356 of the Member 336 on the hanger wall 140, this contact causes a reaction force on the outer rib 358, which is pressed against the wall 61. If the limbs did not have opposing ribs, the limb would Slide down until its side rests against the adjacent link instead of sealing against the walls 61 or 140. This supporting of the inner and outer ribs requires prevention of warping or bending the midsections of the limbs. But this is precisely because of the diamond-shaped shape of the cross-section achieved, whereby the middle part is particularly stiff. A horizontal alignment of the links 334, 336, 338 would result in the tolerances between the inner diameter of the wellhead 24 and the outer

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diameter of the casing hanger 50 would be critical. By arranging the links 334, 336, 338 at an angle, the Z-shaped part 220 can also be loosened more easily when the sealing arrangement 210 is pulled out. The area of the drive part 218 and the surface 372 of the lower cam

some 222 are tapered and thus prevent the links 334 and 338 from aligning horizontally.

It should be emphasized that seals 330, 332 made of an elastomer are superfluous when the ribs of the Members 334, 336, 338 sufficiently rest against the walls 61 and 140 for hydraulic pressure to be able to create in the annular space 134. For some applications, parts 330 and 332 are omitted, so that the space between the intermediate links 334, 336 and 338 remain empty. It is also possible to use spacers to separate parts 330 and 332 to replace, which allow a deformation of the intermediate members 334, 336, 338 by a predetermined amount. As stated above, the elastomeric parts 330 and 332 form such spacers. The invention also includes materials other than elastomers; the parts 330 and 332 can also be other Resilient material such as Grafoil, which is manufactured by the DuPont company. This refractory Material is described in the following two publications: "Grafoil - Ribbon Pack, Universal Flexible Graphite Packing for Pumps and Valves "from F.W. Russell (Precision Products) Ltd. of Great Runmow, Essex, England and" Grafoil Brand Packin " from Crane Packing Company of Morton Grove, Illinois.

In the event that sealing with metallic flat surfaces is undesirable, the channels 368, 370 and 374 can be used to bring material made of an elastomer to the surfaces 61 and 140, wherein this contact is made first. If the elastomers 330, 332 are to be the first seals, then so the annular intermediate members 334, 336, 338 serve as holding pieces for the elastomers 330, .332. In this

In case, the retaining seals can not be in place be pressed.

The present invention is suitable for working pressures up to 1050 kgf / cm ² (15,000 psi), so the sealing assembly 210 is provided with a compression pressure for safety

1400 kgf / cm (20,000 psi) is applied.

To this end, the sealing assembly 210 is both applied with a torque than with a hydraulic pressure. First a torque of about 1380 10,000 ft.ibs. (kgm) issued to drill pipe 236 at surface 18. The rotating linkage 236 transmits this Torque the inlet tool 200 and acts on the sealing device 210. The rotary linkage 236 rotates the bolt 230, which in turn entrains the outer sleeve 250 due to the split pin connection 320. The cuff 250 takes the sealing nut 182 with it due to the crown connection 198,308. The mother supports herself on the drive part 28 and transmits the force via the support surface 205. Since the actuation arrangement 212 is already has previously reached its lowest value of the downward movement, up to the locking ring 144 in the direction the locking position, the sealing device 210 and in particular the Z-shaped part 220 compressed between the drive part 218 and the lower cam part 222. This torque causes a Axial force of approximately 68,000 kg.

After the Z-shaped part 220 is compressed between the drive part 218 and the lower cam part 220 has been, the elastomers 330, 332 between the "members 334, 336, 338 are compressed while these be moved into a more horizontal position. During this compression process, the elastomers 330, 332 fill completely the grooves between the members 334, 336, 338 in which they are inserted. The amount of elastomer is chosen so that the members 334, 33f, 338 in a

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rather reach a horizontal position and sufficient. Contact with the walls 61 of the wellhead 24 and 140 of the hanger 50 while preventing the elastomers 330, 332 from jumping out. In particular, prevent the inner annular contact surfaces 382, 384 a protrusion of the inner elastomer 332 while the annular contact surfaces 386, 388 a Prevent the outer elastomer 330 from protruding. The first sealing process takes place through the links 334, 336, 338 before the elastomers 330, 332 make their contacts. It is important that parts 330, 332 made of elastomer are of the correct size and shape so that when the Sealing device 210 a metallic sealing contact is made before the elastomers 330, 332 their Establish sealing contact.

The real purpose of initial torque delivery is to make the stop seals 330, 332 elastomeric set correctly without the complete metal-to-metal sealing contact between the surfaces 61, wellhead 24 and hanger 50 is made. The torque applied first is insufficient fully actuate the sealing device 210 due to friction losses in the riser in the eruption shut-off device in the drill pipe itself and in particular because of the numerous threads, such as 118. These Frictional losses limit the force to be transmitted from the drill pipe 236 to the sealing device 210.

To achieve the desired application of compression pressure to the sealing device 210 and for manufacture a full metal-to-metal seal uses hydraulic pressure. In the figures

ö5 2A and 2B has the eruptions abspei shown schematically rvorrichtung 40 jaws 34 on, the dead center line 38 communicates with the annular space 134 below the gripper jaws 34. This line

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device 38 is usually below the lowermost jaws arranged. Conversely, should line 36 be the lowest line in device 40 for any reason then the hydraulic pressure would flow through this line 36 are fed.

When pressure is supplied through line 38 into the annulus 134 this must be sealed. Figure 2A shows that the conduit 38 is positioned in phase with the jaws 34 is, but is actually produced out of phase by 90 °. This means that the gripper jaws 34 are closed and seal the drill pipe 236, with ring seals 264, 266 the seal between Bolt 230 and collar 240 effect, ring seals 292, 294 the seal between collar 240 and the inner wall 272 of the hanger 50 and, as stated above, the sealing device 210 effect the initial seal of the annular space 134 makes. The hydraulic pressure can consequently through the line 38 into the annulus 134 are directed.

Due to the corkscrew effect caused by application torque is applied to drill pipe 236, the upper limit for transmitting torque is at 1380 kgm seen, for underwater use. In the present Case requires a transmitted torque of 1380 kgm a seal of the annular space 134, the

2 a hydraulic pressure of a few hundred kp / cm could resist. This relatively low pressure seal would then pressurize the annulus 134 allow in order to further compress the sealing device 210, whereby the seal in the annulus 134 rises and withstands further hydraulic pressure. The metallic Z-shaped part 220 with annular Intermediate links 334, 336, 338 is sized so that the links 334, 336, 338 are thin enough to fit a Metal-metal sealing contact together with the elastomers 330, 332 to produce a hydraulic pressure

2
of a few hundred kp / cm when a torque of about 1380 kgm is applied.

When the device 210 is pressurized, the actual pressure areas the diameter of the inlet tool seal 264 less the diameter of the drill string 236 and additionally the annular sealing surface of the device 210. Since the annular sealing surface for Fixed to a particular wellhead and casing hanger is the primary variable in determining the pressure force is the difference in pressure area between the seal 264 for the inlet tool and the drill string 236. This difference can be varied to achieve a certain compression force on device 210. The difference in diameter can vary, for example, between 12 and 25 cm.

The application of the hydraulic pressure provides an axial

force applying 1400 kgf / cm to device 210 without affecting the pressure limits in the wellhead assembly To exceed. The application of the torque to the nut 182 according to the hydraulic pressure, ' causes this nut to follow the path of device 210 as it is moved downward under pressure and prevents it from relaxing when the hydraulic force is no longer available. It is essential that a high torque, i.e., 1380 kgm is maintained in the drill pipe 236 so that the sealing nut 182 of the device 210 follows, otherwise the nut 182 will cause the downward movement of the device 210 could prevent.

This process is repeated a number of times as the hydraulic pressure increases until the sealing nut 182 rotates a sufficient number of times has traveled to ensure that the compression pressure of 1400 kgf / cm has been transferred to the device 2 '.

The inlet tool 200 is a combination tool

gur transmission © INEI torque for locking · - \ ma & bdiehtv © rriehtung 180 and for supplying hydraulic pressure to the device 81. Di © rotation of the drill pipe 230 to transmit the torque via the Sinlaßwerkseug 200 sur device 180 allows the sealing of the device 210 Annulus 1.34 is the wellhead 24 and hanger 50 so that hydraulic pressure can then be applied to annulus 134 to activate device 210. A constant and continuous increase in the hydraulic pressure in the linfsaum 134 through the line 38 causes the

210 wtittr is compressed and tine stronger atr Filehin 11 dei! © hrloehkopfei 24 and the Flee © 140 äee Longer SO causes. With increased abdishtunf the device 210 also tolerates higher inputs druete © »The pressure routed through line 38 can consequently i © are greatly increased, biü the device

210 with a Ke-mpreiiionidruek of about 1400 kp / em

is mandated. The hydraulic pressure in the line 3S and in the annular space 134 does not override the pressure rings dei iyatemi. All systems are based on a standard which must not be exceeded.

The system of the present discovery is for a work pressure of 10S0 kp / em so that a hydraulic Lower pressure in the annular space 134 for complete actuation of the device 210 the value of 1050 kg / cm not overlooked, although a pressure of congress from 1400 kg / cm is desirable. The invention enables © int compression of the device 210 with 1400 kp / em, Without using a hydraulic pressure of 1050 kp / cm exceeds.

Due to the higher hydraulic pressure in the Input room 134 to derive the compression pressure of

1400 kp / em ² on the device 210, the sealing nut 112 is due to the continuous supply of torque! of 1380 kgm to the drill rod 236 and thus to the edge 250 of the device 210 near the bottom

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Annular space 134 along the thread 204. Does not become .hydraulic If more pressure is supplied through line 38 and space 134, sealing nut 182 prevents one

2
Release of 1400 kp / cm compression pressure on device 210 through threads 204 with casing hanger 50.

It is important that the seals 330, 332 be made of elastomer only then exercise their sealing contact after the first torque has been transmitted through the drill rod 236 is. If the parts 330, 332 are not in contact, the hydraulic pressure would be applied through the line 38 ineffective on the device 210 by being discharged into the lower annular space 130. The sealing effect of the parts 330, 332 just has to be big enough to add an additional

2 hydraulic pressure in line 38 of about 35 kp / cm endures. After the original sealing process, the supply of ... larger hydraulic pressures causes another Compression of the Z-shaped part 220 and the elastomers 330, 332 so that the metal-to-metal seal and the elastic seal with the walls 61, 140 is increased. This higher sealing contact enables the further supply of hydraulic pressure through the Line 38 for further actuation of device 210.

The sealing actuator described above is a simplification of known actuator assemblies. The pressure down through the drill pipe was used to build a built-in to operate the slotted piston system.

The end of the pipeline for the pressure supply to the piston system was sealed, thereby pressure the seal was fed. Although such a conventional actuation system could be used, that of the present invention Design advantageous.

It may be necessary to increase the torque initially applied to drill string 236 after

3 3Ό53Ίϋ

Closing the gripper jaws 34. Although the rubber contact creates no such frictional loss between the gripper jaws 34 and the drill pipe 236 as a Metal-to-metal contact would result in additional friction loss. Therefore, if possible, a Verden additional torque given to the drill pipe 236 to compensate for this friction loss. That. Drill rod 236 rotates the gripper jaws 34 into the closed position Position. The annulus between the riser and drill pipe 236 contains wellbore fluid which between the gripper jaws 34 and the drill rod 236 when the eruption shut-off device 40 is closed. It is believed that this does not significantly reduce the torque of 1380 kgm. But must the friction between the gripper jaws 34 and the drill rod 236 can be reduced, so a not shown Special pipe connectors are additionally provided in the drill pipe 236, so that the jaws 34 in a stationary Engage tubular part, which is penetrated by a rotating part to the torque on the other side of the Gripper jaw 34 to be transferred. This pipe connector could Have rotary seals between the stationary and rotating parts to prevent fluid passage.

In Figures 5A, 5B and 5C the complete assembly is of the wellhead 24 with a 16 inch (40.64 cm) casing hanger 420 a 13 3/8 inch (= 33.97 cm) casing hanger 50 a 9 5/8 inch Casing hanger 4 00 and a 7 inch (17.78 cm) casing hanger 410 are shown. The trailer 50 is in the locking and sealing position in FIG. 5B shown, which is described in connection with Figures 1 to 4, the locking and Sealing device 180 is in this position. The hanger 400 is attached to the top of the hanger 50 at 402 and has also a locking and sealing device 404 on, which is comparable to the device 180 of the hanger. The hanger 410 is at the top of the hanger 400 at 412

solidifies and has a locking and Abdichtvor- ^··: direction 414 / the similar to the device 81 is. FIGS. 5A and 5B show the locking _{grooves of the borehole head 24 t,} ie the groove 68 for the hanger 50, the groove 406 for the hanger 400 and the groove 416 for the hanger 410.

The hangers 400 and 410 do not require ring shoulders such as the ring shoulder 128 for the hanger 50. Since the hangers 400 and 410 carry less loads, need it has smaller support areas than the hanger 50 / whose contact area must be 100%. The shoulders of the Hangers 400, 410 are rectangular and lie uniformly on top of the hanger that carries them.

FIG. 5C shows another exemplary embodiment for a removable support insert for the hanger as shown in FIG is designated at 70. This sawtooth-shaped Insert 420 in Figure 5C is adapted to be let into bore 60 and connect to the teeth 66 of the wellhead 24 to produce.

Since there are certain soil formations below the 20 inch (= 50.8 cm) pipes, the soil pressure that occurs not withstand. In this case it is necessary a 16 inch (= 40/64 cm) pipe before drilling the hole for the 13 3/8 inch (= 33.97 cm) pipe is drilled. The insert 420 shown carries the 16 inch tube. The insert 420 thus acts both as a shoulder for the hanger 50 as well as a hanger for the 16 inch tube 422.

The insert 420 has a solid tubular ring 424 and a sealing ring 426. The ring 424 has outer teeth 428 which are arranged in a sawtooth shape and which look essentially the same as the teeth 76 of the insert 70. The ring 424 has an upwardly directed, conically tapering support shoulder 430 for engagement

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with the sealing ring 426. Furthermore, or has a plurality of parts 432, which are similar to parts 92 of Figure 2C, for clamping the insert 4 20 within of the wellhead housing 46. The ring 424 is provided with a End 434 provided for threaded engagement with the upper tube portion of tube 422.

The upper part of the ring 424 has a counterbore 438 for receiving a pin 440 of the ring 426.

The ring 426 has an external thread for screwing Engaged with the internal threads of counterbore 438 of ring 424 at 442. Ring 426 has one upward facing shoulder 450 to abut the downward facing shoulder 132 of the hanger 50. Ring seals 444 and 446 are in annular grooves along the top End of the ring 426 provided for sealing the wall 61 of the wellhead 24. The ring 426 also has sealing rings 452/454 on / in annular grooves above thread 442 on pin 440 around the wall of the counterbore 438 of the ring 424 to be sealed. A test port 456 is between seals 452 and 454 provided to test the ring 426.

Because the 16 inch (= 40/64 cm) pipe is firmly anchored the insert has 420 grooves 435 shown in FIG

5C are shown in phantom. The grooves 435 connect the natural flow past along the interstices 86/87 of insert 70 and the wellhead 24 shown in Figure 3 a and a number of comparable along the circumference QQ allocated slots by the continuous annular flange 85, which above the openings 86, 87 is provided. The slots of the flange 85 are narrower than the locations 86/87 so that the insert 420 will not fit through the wellhead 24. After fixing, the ring 426 is provided with the annular space 134. To test the ring 426, the grapple jaws of the blowout shut-off device are closed and the inlet tool is sealed below the test port 456 and the annulus

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134 pressurized. If there is a leak between the wellhead housing 46 and the ring 426 or between the ring and the counterbore 438, the annulus 134 cannot be pressurized. Furthermore, a constant amount of hydraulic fluid would be fed to it via the line 38. The ring 426 ^needs:% .ke ine characterized by very high sealing force because at this stage of the casing of a well bore most Prints

are on the order of less than 350 kg / cm.

In another embodiment, the insert and the hanger 50 can be made in one piece, with Binsatz 70 and hanger 50 in the wellhead 24 are lowered together. For example, the hanger 50 may have teeth for direct engagement with teeth 66 of the wellhead.

In another embodiment, the longitudinal extent of the ring 424 of the insert 420 can be increased a sealing arrangement 210 and / or actuating device 212 for the locking directly on the insert 420 and between the insert 4 20 and the wellhead 24 for locking and Seal with this. In this case the ring .426 can be omitted.

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Claims (52)

Patent claims 1. Hanger insert for a number of pipe hangers within a wellhead, which are suitable for receiving pipes for a borehole, characterized by: a tubular member disposed in the wellhead; a connection arrangement arranged on this tubular part around the tubular part with the wellhead to be releasably connected; a shoulder assembly on the tubular member around the record the lowest pipe hanger and a suspension device on the tubular part for recording of the pipe. 2, insert according to claim 1, characterized in that the shoulder assembly is provided with a support surface, which is able to support the weight of the pipe hanger and the one attached to it. R, © h, £ Sj injier-haljg cles gghglQclikopfes as well 2 to carry a working pressure of 1050 kp / cm. 3. Use according to claim 1, characterized in that the shoulder arrangement has a support surface that supports the weight the pipe hanger and attached pipes together with a working pressure of the borehole endures without the Material yield point is exceeded with vertical compression of the tubular part. 4. Use according to claim 1, characterized in that the shoulder arrangement has a support surface which withstands a vertical compression force of more than 2.9 million kg. 5. Use according to claim 1, characterized in that the shoulder arrangement has an annular support shoulder with an actual horizontal thickness of at least 3.3 cm. 6. Use according to claim 1, characterized in that the shoulder arrangement has a tapered annular Shoulder with a taper angle greater than than having. 7. Use according to claim 1, characterized in that it additionally has locking arrangements for locking the tubular member within the wellhead. 8. Use according to claim 1, characterized in that it has an arrangement for releasably connecting an inlet tool to the tubular member. 9. Use according to claim 1, characterized in that the connection arrangements thread on the head part and on the Have support part for screw connection of the parts when the support part is rotated. 10. Use according to claim 1, characterized in that the connecting ^{arrangement is actuated by a 30 p} rotation of the tubular part. 11. Use according to claim 1, characterized in that the connection arrangement has a sawtooth connection. 12. Use according to claim 1, characterized in that the connection arrangement has teeth whose profile distributes the pressure over all teeth. 13. Use according to claim 1, characterized in that the connector assembly has threads for threaded engagement with the pipe. 14. Device for carrying a hanger with an attached A pipe within a borehole characterized by: a head portion; a telescopically received support member within the headboard for receiving the hanger; a plurality of circumferentially spaced and unpitched threads on the inner circumference of the head part and on the outer circumference of the support part; • threads on each part leading to the spaces in the Thread are aligned on the other part, the threads can interlock so that they the Keep parts from axial movement when an axial force is applied; -4- wherein the support part can engage in the head part and forms a support assembly for receiving the hanger and tubing for the wellbore. 15. Device for holding a pipe hanger with attached Pipe within a borehole, characterized by: a headboard; a support part for receiving the pipe hanger, wherein the support part can be inserted into the head part; Teeth, both on the head part and on the support part, for the detachable connection of the parts with one another by twisting of the support part; wherein the teeth have a plurality of spaced apart groups of teeth, the groups of the Support part can be inserted between the groups of the head part during the insertion of the support part into the head part. 16. The device according to claim 15, characterized in that the teeth are fully engaged by rotating the support member less than one full turn. 17. The device according to claim 15, characterized in that the teeth taper without an increase to enlarge the shear surface of the teeth. 18. Apparatus according to claim 15, characterized in that the teeth on the supporting part engage with the teeth on the head part without interference. 19. The device according to claim 15, characterized / that the teeth have a different than rectangular shoulder profile have to prevent the accumulation of debris on the teeth. 20. Apparatus according to claim 15, characterized in that the tooth groups have tooth segments, so that pre-rotation in the direction of engagement, the rotation of the Zuhnsegmehte of the supporting part, the toothed segments of the head part clean. 21. The device according to claim 15, characterized in that the teeth have a tooth profile for uniform distribution of the pressure on all teeth. 22. The apparatus according to claim 15, characterized in that all teeth have the same length that the number of
Groups on the headboard equal to the number of groups on the
Is supporting part and that the parts are an even number of
Have groups so that when engaged the prints and
Loads evenly distributed between the teeth
are. 23. The device according to claim 15, characterized in that each part has six groups and six spaces. 24. The device according to claim 15, characterized in that each group has six rows of teeth. 25. The device according to claim 15, characterized in that the support part has a tooth whose axial width
larger than the other teeth of the support part are by one
to prevent premature screw engagement between the parts. 26. The device according to claim 15, characterized in that each part of extendable threadless surfaces of cylindrical
Has design. 27. The device according to claim 15 / characterized / that the groups of teeth on the head part have essentially the same circumferential extent as the groups of teeth on the support part. 28. The device according to claim 15 / characterized in that it has an arrangement for preventing the relative rotation of the two parts with respect to one another. 29. The device according to claim 28 / characterized / that this arrangement has a stop on one of the parts in Having engagement with the other part. 30. Apparatus according to claim 28 / characterized / that the arrangement is effective when the support part is rotated by less than one full revolution. 31. The device according to claim 28 / characterized / that the arrangement for preventing rotation is a movable one Has part on one of the two parts / which is arranged in a recess of the other part. 32. Apparatus according to claim 31 , characterized / that the movable part is movable to enable a release of the part by relative rotation without relative axial movement / followed by a relative axial movement of the support part to move away from the head part in the absence of the relative rotation. 33. Apparatus according to claim 32 / characterized / that the support part has arrangements for moving the movable one Partly towards loosening. 34. Apparatus according to claim 15 / characterized / that the passage of the groups of teeth on the supporting part between the groups of teeth of the head part triggers an indication / that the teeth are engaged by rotating the supporting part are long enough. 35. Apparatus according to claim 15, with a sealing arrangement for creating a seal between the head part and the supporting part, characterized by the following parts: a multitude of frustoconical metal rings, which are arranged one above the other, each ring having an alternating frustoconical shape; an annular shoulder on the support member; an actuating part that alternates on the tubular part is arranged, the annular shoulder and the actuating part cooperating / facing Have surfaces that receive the end portions of the stacked metal rings upon sealing; wherein the metal rings, the annular shoulder and the actuating member have an outer diameter that is smaller than the diameter of the bore; and an actuator assembly for applying an axial force on the actuator so that it rests against the metal rings and the inner and outer edges of the Brings rings in a metal-to-metal sealing connection with the support part and the head part. 36. Sealing arrangement according to claim 35, characterized in that that the metal rings have sufficient radial widths for the inner and outer edges of the metal rings for cooperating and sealing engagement of the tubular part with the inner wall of the bore in the event of deformation to a smaller cone angle. 37. Sealing arrangement according to claim 35, characterized in that the metal rings between the annular shoulder and the actuating part are compressed beyond their yield point. .-.- «-: 330531ο - R - 38. Sealing arrangement according to claim 35, characterized in that that annular members are provided between the metal rings of the annular shoulder and the actuating part are / which establish a firm connection between the annular part and the actuating part. 39. Sealing arrangement according to claim 38 / characterized / that adjacent metal rings form an annular groove for receiving an elastomer seal. 40. Sealing arrangement according to claim 35 / characterized in that that it has spacers between adjacent metal rings. 41. Apparatus according to claim 35, characterized in that that it further comprises: a torque transmitting arrangement in engagement with the actuating part for transmitting a torque to and rotating the actuating part; wherein the operating part is in screw engagement with the support part, so that a torque transmitted to the support part in one direction a downward movement of the actuating part on the support part over a certain distance allows Bring sealing assembly into sealing engagement; a hydraulic arrangement for supplying a hydraulic one Pressure on the sealing assembly so that the metal rings of the sealing assembly in metal-to-metal sealing engagement with get the head part and the support part; wherein the actuating part, when the sealing arrangement is actuated, migrates downward on the supporting part in order to release it the sealing arrangement when the hydraulic pressure is removed to prevent. 42. Drilling device for attaching pipes within a Boreholes and for receiving a large number of pipe hangers arranged one above the other with attached pipes, marked characterized by the following parts:
a headboard; a support part with a first support surface for receiving the lowermost pipe hanger, the support part on the upper part a drill string is attached; a tooth arrangement both on the head part and on the support part for the releasable connection of the two parts with one another, wherein the tooth arrangement has a second support surface for receiving the support part on the head part; wherein the first and second support surfaces have sufficient area so that the weight of the pipe hangers with the attached pipes and the working pressure of the borehole determine the strength of the material with vertical compression of the Do not significantly exceed the supporting part and the head part. 43. drilling arrangement according to claim 42, characterized in that that the headboard has a bore of 17 9/16 inches (= 44.61 cm) to accommodate a conventional 17 1/2 inch (= 44.45 cm) drill bit around so the hole for the lowest Pipe hanger to drill attached pipe. 44. Drilling device according to claim 42, characterized in that that the head part and the support part are made of one material stand whose breaking strength is greater than 5976 kp / cm. 45. Drilling device according to claim 42, characterized in that that the support surfaces can withstand a load of more than 2.9 million kg. 46. Drilling device according to claim 42, characterized in that the first support surface has a tapered annular shape Has shoulder on the support part, the taper angle is greater than 30 °. In that the gear arrangement has 47. Drilling apparatus according to claim 42, characterized in that a plurality of segmented _t-circular grooves on each part, wherein the segmented grooves of the supporting part between segmented grooves of the head part fit. 48. Device for suspending a pipe within a borehole and for receiving pipe hangers with attached Pipes for the borehole, characterized by the following parts: a wellhead; a telescopically changeable hanger insert in the wellhead which screw-engages the upper hole il a pipe string for receiving the drill string is within the borehole; a plurality of circumferentially spaced apart., non-pitch threads on the Inner circumference of the wellhead and on the outer circumference of the hanger insert; wherein these threads engage one another when the hanger insert is rotated by less than 360 °; wherein the hanger insert has an upwardly directed conical surface; and a sealing ring, a lower cylindrical part and a has upper annular shoulder-shaped flange part, wherein the flange with a downwardly directed flat: is provided for engagement with the upwardly directed conical surface; and the cylindrical piece of the externally threaded sealing ring for screw-engaging the internal threads of the hanger insert is provided; with a sealing arrangement for sealing between the hanger insert and the sealing ring; with other sealing arrangements for sealing the shoulder flange with the wellhead; wherein the sealing ring has an upper piece zfIM 'he to engage with the pipe hanger. 49. Apparatus according to claim 48, characterized in that it further comprises an arrangement for testing the sealing arrangement and the other sealing arrangement. 50. Apparatus according to claim 48, characterized in that the sealing arrangement has upper and lower ring seals, which sit in cylindrical pieces of the sealing ring and that the test assembly is located between the has upper and lower sealing rings arranged toost opening. 51. Apparatus according to claim 48, characterized in that it further extends longitudinally through the tooth arrangement Has grooves. 52. A method for casing an underwater borehole, characterized by the following step a) arrangement of a drilling assembly at the subsea borehole; b) installing a guide tube in the seabed with a wellhead, eruption shut-off device and an associated riser at a point near the sea floor, wherein the riser is extends to the drilling assembly; c) Running a drill string through the wellhead with a conventional 17 1/2 inch (= 44.45 cm) drill bit and the guide tube; d) Drilling a hole to arrange another chuck • pipe within the wellhead and the guide pipe; e) lowering a hanger insert into the wellbore until it protrudes into the wellhead; f) Turning the hanger insert by less than 360 ° connect it to the wellhead; g) locking the hanger insert within the wellhead; h) drilling a hole for running another casing within the wellhead; i) Letting in a casing hanger with a casing through the riser into the wellhead? and j) Attaching the casing hanger to the hanger insert.