NL8300566A - Submarine wellhead system. - Google Patents

Description

V

V Λ γ Ν / 31,328-tM / id Submarine wellhead system.

The invention relates to submarine wellhead systems and more particularly to methods and apparatus for supporting, holding down and sealing pipe hangers in a submarine wellhead.

5 - Increased activity in drilling and finishing at sea has caused an increase in working pressures so that new wells are expected to have a working pressure of 1050 bar. Because of the special problems that. In connection with drilling and finishing at sea to resolve these elevated working pressures, new submarine wellhead systems are required. Wells with operating pressures up to 1050 bar are today drilled off the coast of Canada and in the North Sea at depths of over 90 m. These drills generally include a floating vessel with a riser swell compensator 15 and drill pipe extending to the blowout valve and the wellhead which are on the mud line.

The blowout preventer system is generally mounted on 20 inch pipe / with the riser tube extending to the water surface. A quick-release coupling is often located at the top of the blowout preventer system. A hinge joint has been used to permit vessel movement. Two major problems arise with subsea well systems operating in this environment with an operating pressure of 1050 bar, namely a support shoulder in the wellhead housing, which absorbs the casing and pressure loads, and a sealant between the pipe hangers and the wellhead, which withstands and confines working pressure.

In the past, well-known wellhead designs have allowed sufficient placement support for subsequent pipe hangers. With the increase in pressure value and the placement and support of multiple casing columns and pcnp tubing columns in the well head, a small support shoulder will not support the load. While an obvious solution to the problem would be to use a support shoulder large enough to support the casing and compression loads, large support shoulders protrude into the wellbore flow bore for limited access to the wellhead housing. move under the wellhead housing 8300566 * · Μ - 2 - \ ν for drilling. In the early days of offshore drilling, 16¾ inch subsea wellhead systems required sub-clearing. At that time, most floating drilling rigs were equipped with a 16 inch blowout preventer system to avoid the twin valve system (20 inch and 13-5 / 8 inch) with two risers that had previously been required. When the wellhead terns transitioned from 350 bar to 700 bar operating pressure, the 18 inch 700 bar support shoulder was developed to accommodate the casing and pressure loads and provide full access to the casing under the well head housing.

The second major problem is the sealant. The sealant must be able to withstand and trap 1050 bar operating pressures. Available energy sources for energizing the shutoff means include weight, hydraulic pressure and torque. Each termination means requires different amounts of energy for placement and energization. Weight is least desirable because handling drill collars that deliver the weight is difficult and time consuming on the drill floor. When hydraulic pressure is applied through the drill pipe, cable equipment is required to lower and retrieve "darts" from the hydraulic seal actuation system. If no "darts" are used, handling a wet drill string is very dirty and unpopular in drilling plows. If the seal energizers use the single-speed tube-hanger technique, the cementing fluid can cause problems in the hydraulic system used to energize the seal. Maintenance is also a problem. Although torque is the most desirable method of energizing a seal, there are limitations on the amount of torque that can be transferred from the surface due to friction losses on the riser, blowout preventer system, proper placement, different threads and the drill pipe itself .

The submarine wellhead system of the present invention overcomes the drawbacks of the prior art and includes many other beneficial features. The system is simple, has less than fifty parts and is suitable for H2S operation. System 40 has single speed capability but can still use multi-speed methods 8300566-3. All hangers are interchangeable with respect to the external profile so that they can become. lowered into lower positions. The sealing elements are interchangeable and fully energized to a pressure 5 greater than the expected well bore pressure. Support seals are available. The seals are not de-energized by pressure. The hangers can be lowered without "lock downs" and the sealing elements will seal even if the hanger is placed high.

10 The house support seat supports more than 27,000,000 N (operating pressure plus casing weight or test pressure) without exceeding 150% of the tensile stress limit on pressure. The wellhead will allow a 17½ inch diameter chisel to pass through.

The present invention does not attempt to be placed on two types of seats simultaneously or on two seats simultaneously. Furthermore, the home support seat is not sensitive to collecting debris while drilling or collecting debris while lowering a 13-3 / 8 inch casing. Furthermore, the housing support seat does not require a separate row 20 and does not drag snap rings down the bore. The hanger downholder will keep 9,000,000 N down. The hanger downholder is positively retracted mechanically when retrieving the tube hanger body and is suitable for single-speed operations. The hanger downholder is released for retrieving the tube hanger when the sealing member is retrieved. The hanger downholder is suitable for multi-speed operations and allows the hanger to be lowered with or without the downholder. The sealant will work even if the hold-down device is not used. The hanger downholder is reusable and has a minimum number of tolerances that accumulate between hold-down grooves.

The sealant of the present invention will reliably seal an annular zone 35 of about 47 cm outer diameter by 43.2 cm inner diameter and provide a rubber pressure greater than 1050 bar (1400 bar nominal) when the sealant is energized and the sealant pressures from above or below 1050 bar. The pressure greater than 1050 bar is retained in the sealant after the lowering tool 8300566-4- * * · is removed. The sealant is additionally self-energized to maintain full pressure when full load force is not applied or when full load force is not retained. The sealant will not be de-pressurized. The sealant provides a relatively long sealing zone to bridge housing and / or dirt defects. Furthermore, the sealant provides primary metal-to-metal seals and uses the metal-to-metal seals as a support to prevent extrusion of secondary elastomeric seals under high pressure. The sealant of the present invention positively withdraws the metal-to-metal seals from the walls prior to retrieving the sealant. The elastomeric seals of the sealant can relax during the packing assembly retrieval and are fully retrievable. The sealant of the present invention provides an important metal connection between the top and bottom of the gasket-20 sealing zone to ensure that the bottom ring is retrievable. The design allows single-speed operations. There are no intermediate metal parts in the sealing zone to give irregular rubber pressures. The sealant provides a minimum number of sealing zones to minimize leakage paths. The sealant is positively attached to the packing element so that it cannot be washed away by the flow during the lowering operations. The design also allows multi-speed operations and is interchangeable for all pipe hangers within a nominal size.

The sealant loading means reliably provides a force to energize the sealant to a nominal 1400 bar. It allows pre-circulation when used in a single row. However, the loading means is compatible with a single-speed operation or multi-speed operation. Furthermore, it is interchangeable for all pipe hangers within the wellhead system. The load means will cause the sealant to seal even if the pipe hanger is set high. Furthermore, it does not cause a significant reduction of the full pressure 8300566-5 load after operation. The load means does not require remote engagement of hold-down threads. Furthermore, it has no shear pins. The loading means is reusable and does not need to remotely engage downward threads upon packing nut replacement.

The pipe hanger lowering tool includes a connection between the lowering tool and the pipe hanger that will support more than 315,000 kg of pipe load. The lowering tool can generate an axial force greater than 4,050,000 N to energize the sealant. Furthermore, the lowering tool can retract into the pipe hanger without a left torque. The lowering tool can be lowered onto casing or drill pipe.

Other objects and advantages of the invention will become apparent from the following description.

The present invention relates to an undersea wellhead assembly which is particularly useful for offshore wells with an operating pressure in the range of 1050-20 bar. The wellhead assembly generally includes a wellhead, a housing seat to support the casing and pressure loads, a pipe hanger for suspending the casing in the well, a hold-down and seal assembly for locking the pipe hanger on the wellhead and for Sealing the annulus formed by the pipe hanger and the wellhead, a lowering tool to lower the pipe hanger into the wellhead and to initially operate the holddown sealing assembly, and other associated equipment for applying hydraulic pressure to the holddown and sealing assembly for achieving a compression setting of the hold-down and sealing assembly greater than the working pressure of the well. The wellhead is suitable for receiving other stacked pipe hangers and for holding and sealing these other pipe hangers in the well head.

The wellhead has a through hole of 17-9 / 16 inches to allow passage of a standard 17½ inch drill bit. To provide a bearing surface for supporting a tube hanger and the compression load in the wellhead 40, the housing seat is placed on and connected to the wellhead. 8300566 * 4-6 head. Locking block teeth are provided on the well head and body seat to allow the body seat to insert into the well head and rotate less than 360 ° to complete the connection therebetween. The locking block positions include six groups of 5 six teeth. The teeth are spaced spaced threadless threads. The bearing surface of the locking block teeth is larger than the bearing surface provided by the tube hanger housing seat. The base of the body seat will support the displacement and pump tube loads in addition to the 1050 bar operating pressure.

The pipe hanger includes an annular shoulder with grooves for passage of the well fluids. A detachable seat ring is screwed to the pipe hanger shoulder to provide full 360 ° engagement with the hanger seat to support casing and pump tube weight and compression load. A latch member is mounted above the pipe hanger shoulder and can be expanded into a locking groove in the well head.

20 "The hold down and seal assembly is mounted around the tube hanger and above the latch portion and the tube hanger shoulder. The hold down and seal assembly includes a rotating part that rotatably supports a stationary part. The stationary part comprises an upper operating part which is rotatable mounted on the rotating part, a middle end part with a primary metal-to-metal seal and a secondary elastomeric seal to seal the ring space and a lower cam part to operate the latch part.

The closure portion includes a plurality of frusto-conical metal links connected together by connecting links to form a Z 1. This Z-shaped part is connected to the upper operating part and the lower cam part by connecting links so that a positive connecting link is provided between the upper operating part and the lower cam part. The adjacent metal links form ring grooves to receive resilient elastomeric parts.

The rotating part is screwed onto the tube-40 hanger so that when the rotating part is rotated on the 8300566 - 7 pipe hanger the rotating part moves down, so that the stationary part also moves down into the annular space. Initially, the lower cam portion presses the locking part into the well head locking groove to lock the pipe hanger into the well head. Further rotation of the rotating part compresses the middle sealing part of the stationary part. Initially, when the Z part deforms, the metal links press the elastomers parts in sealing contact with the wellhead and tube hanger. Further compression of the Z-part causes the metal links to bend and deform at the connecting links so that a metal-to-metal seal is obtained between the tube hanger and the well head. The metal links are made of a stretchable material with a tensile limit of less than half the tensile limit of the wellhead and pipe hanger material so that the stretchable material of the Z part deforms and the tops and troughs of the surface imperfections of the wellhead and pipe hanger.

The lowering and placing of the tube hanger 20 includes a jacket that engages the rotating portion of the hold down and seal assembly to transmit torque thereto, a mandrel connected to a drill string and a sleeve telescopically received between the jacket and the thorn. The sleeve includes latches that are pressed into contact with the tube hanger by the mandrel in an upper position. After the hold-down and seal assembly has been operated, the mandrel is moved downward to release the latches and then raised upwardly to engage the sleeve with the jacket so that the latches are pressed out of engagement with the tube hanger 30. Seals are fitted between the lowering tool and the pipe hanger.

The hold-down and seal assembly is initially operated by rotating the lowering tool through the drill pipe. To further operate the seal of the hold-down 35 and seal assembly, blowout valve frames are operated to seal with the drill pipe. Hydraulic pressure is applied under the blowout preventer to apply hydraulic pressure to the lowering tool and hold-down seal assembly. As the hold down of the hold-down 40 and seal assembly is further compressed, the 8300566-8 rotating part of the hold-down and seal assembly moves further down on the pipe hanger as a continued torque is applied to the drill pipe. Once the desired compression setting of the seal of the hold-down and seal assembly 5 is achieved, the hydraulic pressure is removed and the rotating portion of the hold-down and seal assembly prevents the sealing of the seal. hold-down and sealing assembly reduces its sealing contact. An object of the present invention is to obtain a compression setting of the seal of the hold-down and seal assembly that is greater than the well operating pressure.

After removing the lowering tool, a second casing tube hanger is placed on top of the first tube hanger. A similar hold down and seal assembly that is operated in the same manner is placed between the well head and the second pipe hanger to hold and seal the second pipe hanger. A third tube hanger is then lowered into the well on top of the second tube hanger and likewise, a hold down and seal assembly 20 is operated to hold down and seal the third tube hanger. The hanger seat thus supports the three tube hangers and suspended casing, while simultaneously resisting and trapping the 1050 bar operating pressure.

For a detailed description of the preferred embodiment of the invention, reference is now made to the accompanying drawings, in which:

Pig. 1 is a schematic view of the environment of the present invention.

Pig. 2A, 2B and 2C are sectional views of the well head, hanger support ring, pipe hanger lowering tool, gasket hold-down assembly, and a schematic of part of Pig's submarine well blowout preventer. 1.

Fig. 3 is an exploded view of the latch block housing seat and part of the wellhead of FIG. 2.

Fig. 3A is an enlarged side elevational view of the key wedged in FIG. 3.

Fig. 4 is a sectional view of the sealing member in the lowering position, and FIG. 4A is a sectional view of the sealing element in the sealing position.

8300566 * - 9 -

Fig. 5A, 5B and 5C are cross sections of the well head with the tube hangers of the 16 inch, 13-3 / 8 inch, 9-5 / 8 inch and 7 inch casing columns placed and in the hold-down and sealing positions.

The present invention is an undersea wellhead system for lowering, supporting, sealing, holding and testing a pipe hanger in a wellhead in an oil or gas well. Although the present invention can be applied in various environments, Fig. 1 is a schematic view of a typical installation of a pipe hanger and casing string according to the present invention in a wellhead mounted on the seabed of an offshore well.

Referring initially to FIG. 1 shows a well bore 10 drilled in the seabed 12 under a mass of water 14 from a drilling vessel 16 floating on the surface 18 of the water. A base structure or guide base 20, a guide tube 22, a wellhead 24, a blowout valve system 26 with pressure control equipment and a riser 28 located in the sea 20 are lowered from the floating drilling vessel 16 and installed on the seabed 12.

The guide tube 22 can be driven into the sea bed 12 until the well head 24 rests at the sea bed 12 or as shown in FIG. 1 a borehole 30 can be drilled for insertion of the guide tube 22. The guide base 20 is secured around the upper end of the guide tube 22 on the seabed 12 and the guide tube 22 is anchored, within the borehole 30 through a column 32 of cement. a considerable of its length. The blowout preventer system is releasably connected by an appropriate connection to the wellhead 24 on the guide base 20 on the seabed 12 and includes one or more blowout preventers such as blowout preventer 40. Such blowout preventers include a number of cutoff valves such as pipe frames 34 on the blowout preventer 40 which can be actuated to and from the blowout valve housing in and out sealing engagement with a pipe section, such as drill pipe, which extends through blowout valve 40, as is well known. The riser 28 placed in the sea extends from the top of the blowout preventer system 26 to the floating vessel 16. The blowout preventer system 26 includes "choke and 8300566" - 10 - kill "lines 36 and 6, respectively. 38 which extend to the surface 18. These lines are used, among others, to test the pipe frames 34 of the blowout preventer 40. When testing rams 34, a test plug is lowered into the well through riser 28 to seal the well at well head 24. The rams 34 are operated and closed, and pressure is then supplied through the kill line 38 with a valve on the choke line 36 closed to test the pipe rams 34.

Drilling equipment including a drill pipe 10 with a standard 17½ inch drill bit is lowered through the riser 28 and the guide tube 22 to drill a deeper borehole 42 into the seabed for the casing 44. A casing hanger 50, shown in FIG. 2C the casing 44 hangs is lowered through the conduit 22 until the casing hanger 50 is placed on and connected to the wellhead 24 as described below. Other internal casing and pump tube columns are then placed and suspended in the wellhead 24 as will be described later in connection with FIG. 5A, 5B and 5C.

Referring now to FIG. 2C, the wellhead 24 includes a housing 46 having a reduced diameter bottom end 48 which forms a downwardly facing inwardly tapered conical shoulder 52. The reduced diameter bottom end 48 has a reduced tube section 54 at its end which forms another smaller downwardly facing inwardly tapered conical shoulder 56. The guide tube 22 is a pipe with an outer diameter of 20 inches and is welded to the reduced pipe section 54 on the underside of the well head 24. The guide tube 22 has a thickness of half an inch and an internal bore 62 with an inner diameter of 19 inches. to initially receive the drill string and chisel to drill the borehole 42 and later to receive the casing casing string 44 as shown in FIG. 1. The well head housing 46 includes a bore 60 with a diameter of about 18-11 / 16 inches, slightly smaller than the internal bore 62 of the guide tube 22.

Provided on the inside of the wellhead bore 60 are multiple stop slots 64, locking block teeth 66 and four annular grooves (shown in Fig. 5B) such as 40 groove 68 spaced along the bore 60 8300566 v

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above the locking block teeth 66. The locking block teeth 66 are approximately 17-9 / 16 inches internal diameter to allow the standard 17½ inch drill bit to drill the borehole 42.

The well head 24 includes a removable tube hanger support seat or latch block housing seat 70 that can be lowered into the bore 60 and connected to the locking block teeth 66. The housing seat 70 includes a solid tubular ring 72 with a smooth inner bore 74, external latch-10 block teeth 76 which can engage the internal locking block teeth 66 of the well head housing 46, an upwardly directed downwardly tapered conical seat or support shoulder 80 for engaging casing hanger 50 and a wedge assembly 78 to lock the housing seat 70 into the well head housing 46.

The bore 74 of the solid ring 72 has an inner diameter of 16,060 inches and provides a conical support shoulder 80 with an effective horizontal thickness of 1.3 inches to support the tube hanger 50. The housing seat 70 has a wall thickness is large enough to prevent the home seat 70 from collapsing under a vertical compressive stress of 6300 bar. This is important since, due to its size, weight and thickness, the well head 24 is a rigid part compared to the housing seat 70 which is a relatively flexible part.

As shown in Fig. 3, the housing seat 70 includes a plurality of groups 82 of segmental teeth 76 with locking block slots or spaces 86 therebetween for receiving corresponding groups 88 of segmental teeth 66 in the wellhead housing 46 as shown in FIG. 2C.

The segmental teeth 66, 76 may or may not be pitch but are preferably pitchless teeth. The teeth 66, 76 are not designed to engage with rotation of the seat 70 for connection to the wellhead 24. The wellhead 35 teeth 66 tap in and down to facilitate passage of the bit. If the threads 66 had straight shoulders or were of the trapezoidal type, they could engage the bit as it is lowered through the wellhead 24 to drill the bore 42 for the casing 44. The shoulder teeth 76 have 8300566

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- corresponding taper to fit appropriately into the well head teeth 66. Groups 82, 88 each include six rows of segmental teeth, which are approximately one-half inch thick from the base to the surface. The thread area 5 of the six rows of segmented teeth 66, 76 exceeds the shoulder area of the support shoulder 80. A continuous upper annular flange 85 on the seat 70 above the teeth 76 limits insertion of the tooth groups 82 into the spaces 87. The continuous upper annular flange 85 prevents the seat 70 from passing through the well head 24. The lower tooth segment 84 is excessively sized to prevent premature rotation of the seat 70 in the well head 24 until the seat 70 is placed on the annular flange 85.

The six rows or groups 82, 88 of segment-15 shaped teeth 66, 76 provide an even number of rows to evenly support and distribute the load. This design equalizes the stresses exerted on the segment teeth 66, 76. Since there are six groups of teeth, the segment teeth 66, 76 can be connected by rotating the housing seat 70 30 °, so 180 ° divided by the number of groups. If the segmental teeth 66, 76 were longer, greater rotation of the housing seat 70 would be necessary for the connection. It is preferred that the segmental teeth 66, 76 have the same length so that maximum contact is available to support the loads.

The segmental teeth 66, 76 may be circular grooves with slots or spaces 86, 87 for connection. The segmental teeth 66, 76 have a pitch angle 0 and are tapered to increase the thread area so that the threads 66, 76 withstand greater shear stress. The taper of the segmental teeth 66, 76 is greater than 30 °, and is preferably about 55 °, greatly increasing the thread area for shear. This tooth profile tries to equalize the stresses over all segment-shaped teeth 66, 76 so that the teeth 66, 76 do not yield separately.

The teeth 66, 76 may be of the trapezoidal type. A straight shoulder on teeth 66, 76 would trap drill bit 40 and other debris flowing through the well. An additional advantage of the locking block connection between the well head 24 and the housing seat 70 is that the segment teeth 76 clean the segment teeth 66 when the housing seat 70 is rotated in the well head 24. The teeth 76 push drill bit away from teeth 66 so that the drill bit falls into the locking block slots or spaces 86, 87.

Continuous threads have several drawbacks. Threads require multiple rotations for joints and must be supported by dropping a fraction of a centimeter before the threads start to engage initially. Furthermore, the threads run at a point when rotated for connection. The locking block connection 70 and the well head 24 avoid these drawbacks.

When the housing seat 70 is lowered into the well head 24 on a suitable lowering tool, the lower tooth segment 84 on the seat 70 will engage the upper tooth segment of the tooth segments 66 on the well head housing 24. The seat 70 then becomes less than Rotated 30 ° so that the groups 82 on the seat 70 are received in the slot 20 87 between the groups 88 on the wellhead 24. This drop is significant, as much as 30 cm, and can be easily observed on the surface to ensure that the housing seat 70 has engaged with the well head '24 and can be rotated in latch block engagement. The use of the locking block connection of the present invention provides a clear indication when the housing seat 70 is fully engaged with the wellhead 24. The locking block connection of the present invention has the additional advantage that the housing seat 70 may be 30 into the well head 24 and at a 30 ° rotation of the housing seat 70 can achieve full engagement between the housing seat 70 and the well head 24.

Referring now to FIG. 2C, 3 and 3A, the wedge assembly 78 includes a plurality of outwardly biased claws 92 each slidably received in an outwardly facing cavity 94 in each alternate lower tooth segment 84 of the solid ring 72. The claw 92 has flat sides 90, tapered top and undersides 91 and a bore 96 on its inside for receiving one end of the spring 98. The spacers 93 are mounted by screws 95 8300566 * -w - 14 - in the cavity 94 on each side of the claw 92 and leave a slot left for the claw 92. The other end of the spring 98 engages the bottom of the cavity 94 to bias the claw 92 outward. A stop slot 64 is provided under all six groups 88 so that the claw 92 is placed on the solid ring 72 whereby the claw 92 abuts a stop slot 64 in the wellhead housing 46 at the full engagement of the internal and external teeth 66. 76 of the wellhead 24 and the housing seat 70. The claw 92 will be pressed into the slot 64 at the rotation of the ring 72 in the threads 66 to thereby stop the rotation of the ring 72. An opening 102 is provided through the ring 72 into the cavity 94 to expose the claw 92.

According to the known prior art, the support shoulder for the casing casing hanger was constructed in one piece with the well head housing and large enough to accommodate the casing. and pressure loading. However, this prior art fully formed support shoulder limited the borehole in the wellhead housing for full access from the bore to the casing under the wellhead housing for drilling. To use a sufficiently large one-piece shoulder for operating pressures of 1050 bar, the bore of the one-piece shoulder would not allow a standard 17½ inch chisel to pass through. Such submarine wellhead systems required sub-clearing.

According to the present invention, the lock block housing seat 70 is an installable support shoulder that must be installed in the wellhead housing 46 only when greater operating pressures occur. The housing seat 70 is not installed until the drilling operation for casing casing 44 is completed, so that full bore access is obtained. Since only nominal operating pressures occur during drilling for casing 44, the larger support shoulder is not necessary. After completion of drilling for casing casing 44, latch block housing seat 70 is installed to handle casing and pressure loads up to 1050 bar. Thus, sufficient clearance is provided prior to installation of the housing seat 70 to allow a 17½ inch chisel to pass.

40 To install the locking block housing seat 70 8300566 '? - ^ - 15 - the housing seat 70 is connected to a lowering tool (not trimmed) by shear pins, part of which is shown at 104. The lowering tool on a drill string then leaves the housing seat 70 down into the bore 60 of the well head 24 until the lower tooth segment 84 is placed on the upper tooth segment of the tooth segments 66. The seat 70 is then rotated until the tooth groups 88 on the well head 24 fall into the locking block slots 86 and the tooth groups 82 on the ring 72 are received in 10 corresponding slots 87 on the well head teeth 66. The continuous ring flange 85 is placed on the top tooth segment of the segments 66 in the well head 24. The housing seat 70 is then rotated by the drill string and lowering tool until the keys 78 engage the stop slots 64 to stop the rotation. A pressure test can be applied to ensure that the housing seat 70 is lowered. Then the shear pins holding the housing seat 70 on the lowering tool are sheared at 104 to release and remove the lowering tool.

FIG. 2C illustrates the placement of the casing pipe hanger 50 on the latch block housing seat 70 in the well head 24. The pipe hanger 50 has a generally tubular body 11Q that includes a lower threaded sleeve 112 screwed to the top of the spacer. 25 tubing column 44 to suspend the column 44 in the borehole 42, a thickened top section 114 with an outwardly drawn radial annular shoulder 116 and a plurality of annular grooves 120 (shown in Fig. 2B) in the inner periphery of the body 110 for connection to a lowering tool 200 described hereinafter.

Referring now to FIG. 2A and 2B, threads 118 are inserted from the top down along a substantial length of the outer surface of the tubular body 110 for engagement with the hold-down and sealing assembly 180 described below.

The cementing operation for cementing the casing string 44 into the borehole 42 requires passage of the lower annulus 130 between the casing string 44 and the guide tube 22 to the top annulus B4 between the wellhead 24 and the drill string 8300566-16-236- to allow the returning material to flow to the surface. Multiple upper and lower vertical grooves or circulation ports 122, 124 are formed by the upper section 114 to allow liquid to flow, such as for the cementing operation, around the tube hanger 50. The lower grooves 122 form fluid channels through the radial ring shoulder 116 and the top grooves 124 form fluid channels through the top screw end of tubular body 110 to allow fluid to pass around hold-down and seal assembly 180.

Threads 126 are mounted on the outer circumference of the top section 114 below the ring shoulder 116 to screw-thread the threaded shoulder ring 128 around the hanger 50. The shoulder ring 128 has a downwardly directed upwardly tapered conical surface 132 that rests and engages the upwardly directed downwardly tapered conical support shoulder 80 on the locking block housing seat 70. Thus, the tube hanger 50 is placed on the housing seat 70 at engagement of the conical surface 132 of the hanger shoulder ring 128 and the housing seat support shoulder 80, causing the housing seating 70 to withstand the resulting casing casing and compression loads.

Wells with an operating pressure in the range of 25 1050 bar cause special loads on the wellhead supports. Not only must the wellhead support the weight of the pipe hangers with the suspended casing and one or more pump pipe hangers with the suspended pump tubes, but the wellhead must withstand and lock the operating pressure of 1050 bar. The well head must therefore support both the casing and pump tube weight and the pressure load. A well head with a working pressure of 1050 bar must have a sufficient support and bearing surface throughout the well head design so that the load does not significantly exceed the tensile limit on vertical compression of the well head supports material. Although materials with a minimum yield point of 4900 bar have been used at lower operating pressures, a material with a higher yield point of at least 5950 bar is normally used for well heads of 1050 bar. Assuming a vertical pressure stress on the wellhead of 6300 bar, the wellhead 8300566 - 17% by weight according to the present invention will support a load of more than 27,000,000 N since the bearing surface is within the range. from 420-452 cm. Such support must be maintained throughout the design so that the load 5 does not exceed the tensile limit of the material at vertical pressure by more than 25%. The bearing surface between the lower tube hanger 50 and the housing seat 70 and between the housing seat 70 and the supporting locking block teeth 66 on the wellhead 24 should be sufficient to support such loads 10 without significantly stretching the stretch limit of the material at vertical pressure, i.e. exceed 25% of the yield point. Such a design has been achieved in the wellhead system of the present invention.

To ensure sufficient support between the tube hanger 50 and the seat 70, the hanger shoulder ring 128 is screwed onto the radial ring shoulder 116 protruding from the top section 114 of the tube hanger body 110.

The hanger shoulder ring 128 forms a 360 ° conical surface 132 for engaging the support shoulder 80 of the housing seat 70 and thus provides full contact between the shoulder 80 and the conical surface 132. Without the hanger shoulder ring 128, the grooves or circulation ports 122 through the shoulder 116 a 360 ° bearing surface between the hanger 50 and the housing seat 70. The engagement between the support shoulder 80 and the conical surface 132 provides an excessive bearing surface defined by the well head inner diameter of 17-9 / 16 inches and the inside diameter of the body seat 70 is 16,060 inches. The bearing surface between the shoulder 80 and the surface 2 132 is approximately 452 cm and allows this bearing surface to support more than 27,000,000 N load.

The internal and external locking block teeth 66, 76 of the wellhead 24 and the housing seat 70 are also designed to provide sufficient support to support the expected load described above. As previously described, the locking block teeth 66, 76 include six groups 82, 88 of teeth mounted on the wellhead 24 and the housing seat 70. Each group 82, 88 includes six teeth 66, 76 to support the load. The bearing surface of the locking block teeth 66, 76 is greater than the bearing surface 40 between the shoulder 80 and the conical surface 132. The number of 8300566-18 teeth is determined by the loss of the bearing surface due to the six spaces 86, 87 for receiving of the corresponding groups 82, 88 during installation.

Referring again to FIG. 2C, the radial ring shoulder 160 protruding from the top section 114 of the hanger body 110 has an upwardly directed downwardly and tapered conical cam surface 136 with an annular recess groove 138 extending upwardly at its base. An annular chamber 142 extends from the top 10 of the groove 138 to an annular vertical sealing surface 140 extending from the groove 138 to the lower end of the thread 118. A radial annular shoulder 116 is positioned below the annular locking groove 68 in the well. head housing 46 after the hanger 50 is placed in the well head 24. The cam face 136 has an annular bottom edge that ends just above the bottom end of the groove 68.

The tube hanger 50 includes a lock ring 144 placed on the radial ring shoulder 116. The lock ring 144 may be a split ring that can be expanded into the well head groove 68 for engagement with the well head housing 46 to hold down the hanger 50 and to lock into the wellhead 24. The wellhead groove 68 has a vertical base wall 146 with an upwardly tapered wall and a downwardly tapered wall. The locking ring 144 has a vertical base surface 148 with a downwardly tapered face the size of the upwardly tapered wall of the groove 68 and an upwardly tapered face parallel to the downwardly tapered wall of the groove 68, so that when the latch ring expands 144 the vertical plane 148 of the ring 144 engages the vertical wall 146 of the groove 68. Furthermore, the locking ring 144 includes downwardly directed outward and downwardly tapered lower cam surface 152 which engages cam upwardly in the upwardly directed cam surface 136 of the radial annular shoulder 116, an inwardly projecting annular rim 154 received by an annular recess groove 138 in the retracted position and an up and inwardly facing cam head 156 capable of engaging the hold-down and seal assembly 180 with cam action is described below. Between the cam head 156 and the ring edge 154, a tapered surface 158 extends parallel to the wall of the 8300566-19 chamber 142.

The protruding ring edge 154 is received in the groove 138 of the tube hanger 50 to prevent the locking ring 144 from being pulled out of the groove 138 when the tube hanger 50 is lowered into the well. During the lowering of the tube hanger 50, it is necessary for the locking ring 144 to pass through several narrow diameters as in the eruption valve 40. The eruption valve 40 often includes an annular rubber seal that does not retract fully, causing the tube hanger 50 to push through the rubber seal. must be. If the ring edge 144 had not been received in the groove 138, the locking ring 144 would catch on such a narrow diameter and drag along the outer surface. This would allow the locking ring 144 to be pulled out of the groove 138, causing it to slide upwardly along the tube hanger 50 until the locking ring 144 engages the sealant 210. This would not only inhibit the operation of the hold-down actuator 212 but also prevent the Operation of the sealant 210. The ring 20 chamber 142 provides a clearance so that the groove 138 can receive the ring edge 154. This profile also provides a step that prevents the locking ring 144 from having such an upward load when the load is placed on the locking ring 144.

The hold-down and seal assembly 180 is shown in FIG. 2B and 2C, in engagement with the hold-down tool 200 and operated in the hold-down position. The hold down seal assembly 180 includes a stationary portion 184 which is rotatably mounted on a rotating portion or packing nut 30 by a holding means 186. The packing nut 182 has an annular body with a lower pin 188 and a crenellated top end 198 with upwardly projecting stops 202. The inner diameter face of the nut 182 includes screw thread 204 that can be screwed onto the external screw thread 118 of the tube hanger body 110.

The stationary portion 184 has an annular body 216 and includes a sealant 210 to seal between the inner bore wall 61 of the wellhead 24 and the outer sealing surface 140 of the tube hanger 50 and a hold down actuator 212 to actuate the locking ring 144 8300566 4 - 20 - in downward engagement with the groove 68 of the wellhead 24. The annular body 216 is a continuous and integral metal part and includes an upper drive part 218, an intermediate Z part 220 and a lower cam part · 222.

The upper drive member 218 includes an upper counterbore 190 which rotatably receives the lower pin 188 of the packing nut 182. The retaining means 186 includes an inner and outer tread in the counterbore 190 and the pin 188, which contain retaining roll cones or balls 196. The holding means 186 carries no load and is not used to transmit a torque or axial force from the packing nut 182 to the stationary portion 184. A bearing 205 is disposed above the sealant 210 and includes bearings 206, 208 which are mounted between the bottom of the counterbore 190 and the lower end of the pin 188. The bearing rings 206, 208 have a low coefficient of friction to allow a sliding contact between them when operating the hold-down actuator 212 and the sealant 210. The bearing 205 is thus used to transmit an axial force from the packing nut 182 to the stationary part 184. The retaining balls 196 rotatably retain only the stationary part 184 on the packing nut 182.

The hold down actuator 212 includes a lower cam portion 222 with a downward and outwardly facing cam face 224 (shown in Fig. 2C) that engages the cam head 156 of the locking ring 144 with cam action, and an upper drive portion 218 and an intermediate Z portion 220 for transmitting the axial force of the packing nut 182 to the lower cam portion 222.

The sealant 210 includes the Z-section 220 and elastomeric support seals 330, 332 which will be described in detail below in connection with FIG. 4, and the upper drive portion 218 and the lower cam portion 222 to compress the intermediate Z portion 220. The sealant 210 is a combination of a primary metal-to-metal seal and a secondary elastomeric seal. The fact that the primary seal is a metal-to-metal seal has the advantage that it does not deteriorate as quickly as an elastomeric seal.

40 The hold down and seal assembly 180 is lowered 8300566 * ** - 21 - * into the well on the tube hanger 50 through a lowering tool 200. The lowering tool 200 includes a mandrel 230, which is the main body of the tool 200, a far -bonding body or sleeve 240, a jacket or outer sleeve 250, and an assembly nut 260. The mandrel 230 includes an internally threaded top pin end 232 for connection to the bottom pipe section of the down pipe 236 extending to the surface 18 and a bottom socket end. 238 also with internal thread. Above the socket end 238, an annular groove portion 242 of reduced diameter is provided. Another reduced diameter portion 248 is disposed above the groove portion 242 to form an annulus 252. Below the upper pin end 232 and above the reduced diameter portion 248 is a third threaded portion 254 of reduced diameter (shown in Fig. 2A) with a diameter smaller than that of parts 242 and 248.

The connector body or sleeve 240 includes a bore 246 that can be telescopic over the annulus 252 and the sleeve end 238. The connector body 240 is telescoped into the annulus formed by the mandrel 230 and the jacket 250. The edge 252 includes annular sealing grooves 258, 262 with O-rings 264, respectively.

266 for sealing contact with the inner surface of the bore 246. The top end of the connecting body 240 includes an inwardly directed radial ring flange 268 with a sliding fit with the surface of the reduced diameter portion 248. The lower end of the connecting body 240 has a reduced diameter portion 270 slidably received by the bore 272 of the tube hanger 50. The reduced diameter portion 270 forms a downwardly facing ring shoulder 274 that engages the top end 276 of the tube hanger 50 when placing the lowering tool 200, the hold-down and seal assembly 180 on the tube hanger 50 in the wellhead 24. The reduced diameter portion 270 has multiple circumferentially spaced slots or windows 278 in which sliding segments or jaws 280 are included which have multiple teeth 282 that can be received by 40 grooves 120 of the tube hanger 50 to connect the lowering tool 8300566 s' - 22 - 200 to the tube hanger 50. The jaws 280 have an upper projection 284 contained in a ring groove 186 around the top inner circumference of windows 278. Above the windows 278 are a plurality of sealing grooves 5 288, 290 with O-rings 292, 294 in sealing contact with the sealing bore 272 of the tube hanger 50. At the upper outer end of the connecting body 240 there is a snap ring groove 296 in which a snap ring 298 that is used in assembling the lowering tool 200 as described below. The jaws 280 fold back into the groove portion 242 after the lower sleeve end 238 has been moved into the lower position, as offset, upon applying torque to the tool 200 to adjust the hold-down and seal assembly 180.

The shell or outer sleeve 250 includes a generally tubular body with an upper inwardly radial portion 300, a middle portion 302, a transition portion 304, and a lower actuation portion 306. Parts 300, 302, 304, and 306 are adjacent to each other and have dimensions to telescopically receive the top end 276 of the tube hanger 50, the connecting body 24O-and-the mandrel 230. The lower actuating member 306 has a crenellated End 308 that engages the upper crenellated end 25 198 of the packing nut 182 to provide torque. can be transferred from the lowering tool 200 to the hold-down and seal assembly 180. The inner diameter of the actuating member 306 is large enough to run clear of the outer diameter of the thread 118 on the tube hanger 50. The center portion 302 slidably receives the connecting body 240 on. The portion 302 includes an inner annular groove 310 that receives the snap ring 298 mounted on the connector body 240 when disconnecting the hold-down tool 200 from the hold-down and seal assembly 35 180 and the tube hanger 50 as described below. The portion 302 has multiple threaded bores 312 that extend from its outer circumference to the groove 310 allowing bolts (not shown) to be screwed into the groove 301 to prevent the snap ring 298 from engaging the groove 310 during reset. of 8300566% - 23 - the lowering tool 200 on another tube hanger. Snap ring 298 has an upper cam surface 316 that engages the ends of the bolts. Once the connector body 240 is received in the upper portion of the ring zone formed by the outer sleeve 250 and the mandrel 230 through which the snap ring 298 is located above the ring groove 310, the connector body 240 cannot be removed without the snap ring 298 in the groove 310 intervenes. Thus, to remove the connector body 24Q after resetting the lowering tool 200, bolts are screwed into the bores 312 to close the groove 310 and prevent the groove 310 from receiving the snap ring 298. This allows the connecting body 240 to move down on the mandrel 230 for connection to another tube hanger.

The transition portion 304 connects the operating portion 306 and the middle portion 302 to provide an adjustment for the diameter change. Flow ports 318 are provided in the transition portion 304 to allow returning cement to flow through the outer tube 250 into the annulus 134.

The radial top portion 300 has a crenellated annular inner surface that forms a keyed connection 320 to the mandrel 230 to transmit torque.

Referring now to FIG. 2A and 2B, the assembly nut 260 has internal threads 324 for screw connection at 322 to thread 235 of the reduced diameter portion 254 of the mandrel 230. The bottom end face of the assembly nut 260 presses against the top end of the outer sleeve 250 about the outer sleeve 250 on the mandrel 230 30.

In operation, the packing nut 182 is only partially threaded onto screw thread 118 on the top of the tube hanger 50 so that the mandrel 230 is mounted in the lower position on the tube hanger 50. In the lower position, the ring edge 252 abuts the shoulder 269 formed by the radial annular flange 268 on the connecting body 240.

The tubular outer surface of the sleeve end 238 is adjacent to and engages the inside of the jaws 280 whereby the teeth 282 are pressed into the grooves 120 of 8300566 - 24 - of the tube hanger 50 thereby disengaging the lowering tool 200 and the tube hanger 50 is prevented from being lowered into the well on the drill pipe 236. The lowering position of the lowering tool 200 is not shown in Figs.

After placing the face 132 of the shoulder ring 128 of the tube hanger 50 on the support shoulder 80 of the housing seat 70 in the wellhead 24, the casing 44 is cemented in place in the borehole 42. After the cementing operation is completed, the lowering tool 200 is rotated and torque is transmitted to the hold-down and seal assembly 180 to operate the hold-down and seal assembly 180 in the hold-down position shown in FIG. 2B and 2C. The rotation of the drill pipe 236 on the surface 18 causes the mandrel 230 to rotate, which rotates the outer sleeve 250 by means of the splice connection 320. The torque of the outer sleeve 250 is transferred to the grommet 132 on the crenellated connection of the stops 202 of the nut 182 and the lower end 308 of the sleeve 250. The packing nut 182 places an axial load on the hold down and seal assembly 180, thereby engaging the cam portion 222 of the hold down actuator 212 with cam action with ~ 3rd ~ Ti head. 156 of the locking ring 144. This cam action expands the locking ring 144 in the wellhead 25 groove 68 for engagement with the wellhead housing 46 to hold and lock the tube hanger 50 in the wellhead 24 as shown in FIG. 2. The sealant 210 has not yet been operated to seal between the upper ring space 134 and the lower ring space 130. The locking ring 144 requires only a predetermined cam load for operation and therefore has a predetermined contraction tension. The sealant 210 is designed in cross-section to ensure that the sealant 210 will not be prematurely compressed in the operation and cam action of the latch ring 144 by the hold-down actuator 212. The load required to compress the sealant 210 is substantial. larger than that required to expand and operate the locking ring 144. The mandrel 230 moves downwardly with the sheath 250 upon actuation of the hold-down 40 and seal assembly 180. This downward movement of the 8300566 mandrel 230 releases the claws 280.

For a description of the sealant 210, reference will now be made to FIG. 4 and 4A, which hold the sealant 210 in the lowering and holding position, respectively. show the 5 sealing position. The sealant 210 includes a metal Z part 220, upper and lower elastomeric parts 330, respectively. 332 and an upper drive part 218 and a lower cam part 222 for compressing the Z part 220 and the elastomeric parts 330, 332. The metal Z-shaped annular part 220 comprises multiple annular links 334, 336, 338 which are connected together by annular metal connecting rings 340, 342 and are connected to the upper driving part 218 by the upper metal connecting ring 344 and to the lower cam part 222 through the lower metal connection ring 346.

The links 334, 336, 338 together with the connecting rings 340, 342, 344 and 346 form a positive connecting link from the bottom to the top between the lower cam part 222 and the upper driving part 218. This positive connecting link causes the links 334 , 336 and 338 move in an obliquely disengaged position relative to the wellhead 24 and the tube hanger 50 upon withdrawal and disengagement of the sealant 210 and the actuator 212 from the wellhead-24. Furthermore, this positive connecting link provides a metal connection that extends from the driving part 218 to the lower cam part 222 to be able to apply a positive upward load to the lower cam part 222 when disengaging. Except for the benefit of this retraction, the connecting rings 340, 342, 344, and 346 are not required.

The connecting rings 344, 346 at the drive part 218, respectively. the cam portion 222 must have a minimum length to ensure a sealing contact with the annular links 334 and 338. If the connecting rings 344, 35, 346 are too short, there will be insufficient bending to contact the links 334 and 338 with the surfaces 61 and 61, respectively. 140. Since the drive part 218 and cam part 222 are solid compared to the connecting rings 344, 346, the relatively solid parts 218, 222 will not flex and the sealing engagement of the links 334, 338 8300566-26. to allow. It is therefore important that the connecting rings 344, 346 allow this bending. The connecting rings 340, 342, 344 and 346 form a high voltage local contact point along the metal Z part 220.

5 The metal Z part is made of very soft stretchable steel such as stainless steel 316. This metal must have a yield point of approximately 2800 bar. This tensile limit is less than half the tensile limit of about 5950 bar of the material for the wellhead 24 and hanger 50. At 10 sealing contact of the metal Z part 220, the metal Z part 220 plastically deforms while the surface 61 of the well head 24 and the surface 140 of the hanger 50 tend to elastically deform. If there is a flaw in the surfaces 61, 140, the stretchability of the material of the annular Z-section 220 will allow this material to deform or flow into the tops and troughs of the imperfections of the surfaces 61, 140 to obtain a high compression metal-to-metal seal. The metal Z-part 220 can thus, in sealing contact with the walls 61, 140 of the wellhead 24, respectively. the tube hanger 50 is pressed upon operation.

The top, intermediate, and bottom annular links 334, 336, and 44 respectively. 338 each have a diamond-shaped cross section. Since the cross section of the links 334, 336, 338 is substantially the same, a description of the link 336 will serve as a description of the links 334,338. The annular link 336 comprises at least substantially parallel annular tops and bottoms 348, respectively. 350, with the top 348 generally facing upward 3Ό and the bottom 350 generally facing downward, at least substantially parallel annular inner and outer sides 352 and 352, respectively. 354 with the outer side 352 facing radially outward and the inner side 354 facing radially inwardly, and parallel annular inner and outer sealing contact edges 356, respectively. 358. The annular links 334, 338 have similar top and bottom sides, inner and outer sides, and inner and outer sealing contact edges.

In the hold-down position, the sealing contact 40 edges of the links 334, 336, 338 become at least substantially 8300566. 0-27 - widely deformed with the bore wall 61 of the wellhead housing 46 and the outer wall 140 of the pipe hanger 50. The top connecting ring 344 extends from the bottom end 364 of the top drive member 218 to the top 335 of the top link. 334 to form an annular channel 366.

The metal link ring 340 extends from the bottom 337 of the top link 334 to form the top 348 of the intermediate link 336 to form an annular channel 368 and the metal link ring 342 extends from the bottom 350 of the intermediate link 336 to the top 339 of the sub link 338 to form an annular channel 370. The lower connecting ring 346 extends from the bottom 341 of the lower 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 edges allow to reach the bending of the Z part 220 at predetermined locations, namely at the connecting rings 340, 342, 344 and 346. The bottom end 364 of the drive part 218 is at least substantially parallel to the top 335 of the top link 334 and the top end 372 of the cam portion 222 is at least substantially parallel to the bottom 341 of the lower link 338.

In the lower and lower positions, the outer and inner sealing contact edges have the same diameter as the outer and inner diameters of the upper drive member 218, respectively. the lower cam part 222.

The upper and lower elastomeric parts 330, 332 are formed in accordance with the shape of the annular grooves 376, 378 and 30 formed by the links 334, 336, 338 are connected to the links 334, 336, 338. The upper and lower elastomeric parts 330, 332 have outer and inner annular vertical sealing surfaces 380, respectively. 382, which can sealingly engage the bore wall 61 and the outer wall 140 in the sealing position. The annular top and bottom edges formed by the sealing surfaces 380, 382 are chamfered to allow deformation of the parts 330, 332 in the sealing position when compressed. The elastome parts 330, 332 are also chamfered to allow a predetermined deformation of the parts 330, 332 between the links 334, 336, 40, 338. Although the cross-sections of the elastomeric parts 330, 332 are at least substantially the same, the inner elastomeric part 332 may be more chamfered or cut than the outer elastomeric part 330 to prevent premature extrusion of the parts 330,332 before links 334, 336, 338 form an anti-extrusion seal with the bore wall 61 of the wellhead 24 and the outer sealing surface 140 of the well hanger 50.

It is preferred that the sealant 210 includes at least three links. This number is preferred because it provides an anti-extrusion link for each side of the elastomeric members 330, 332. Also, the three links 334, 336, 338 provide a symmetrical design. However, the sealant 280 may include one or more links and may comprise a series of links that enclose multiple elastic members. The surfaces 364 and 372 of the drive part 218, respectively. the lower cam portion 222 would preferably be tapered in the same direction as the adjacent links such as links 334 and 338 shown in the preferred design.

The diamond-shaped cross-section of the links 334, 336, 338 allows the middle part of the links 334, 336, 338 to be very rigid. Since a thick center portion is provided, the reduced zones at the ends of links 334, 336, 338 will form the zone that will yield or bend like the zone adjacent to connecting rings 340, 342, 344, 346. It is not desirably for the links 334, 336, 338 to bend or yield to their center portion. However, the particular diamond-shaped section shown is only due to the ease of manufacture of this shape. Links 334, 336 and 338 may have a continuous convex or elliptical shape. This form can be referred to as frustoconoid. This provides an excellent middle section. If the cross-section of the links 334, 336, 338 had the same thickness, the links 334, 336, 338 might tend to bend at their center portion. Although the links 334, 336, 338 preferably have a thickened center portion to obtain the point of bending at the edges for a predetermined plastic deformation 40 and ensure that there is no deformation at 8300566-29 - the center of the links 334, 336, 338, links 334, 336, 338 may be frusto-conical metal rings of equal thickness in cross section instead of frusto-conical rings.

Referring now to FIG. 4 and 4A

Fig. 4A the sealant 210 in the seal position. The sealant 210 is compressed when the hold-down actuator 212 reaches the limit of its movement against the locking ring 144 and the packing nut 182 continues its downward movement 10 on the pipe hanger threads 118 as shown in FIG. 2B and 2C.

The metal-to-metal sealant 210 is operated in series from bottom to top. In other words, the bottom ring link 338 bends and deforms first on compression of the sealant 210 and is the first link to come into sealing contact with the surface 61 and the surface 140. This series operation is preferable for dragging the top annular links 334, 336 along surfaces 61, 140 to be limited in operation 20 if the upper links 334, 336 made sealing contact earlier than the lower link 338. It is preferable to apply a balanced force to ~~ & e-- upper annular link 334.

The elastomeric parts 330, 332 provide the initial seal. The elastomeric seals 330, 332 touch surfaces 61, 140 before the edges of the annular links 334, 336, 338 touch surfaces 61, 140. No extrusion of the elastomer seals 330, 332 must occur beyond 30 the edges at the initial compression setting of several hundred bar, i.e. 210 bar, of the sealant 210. The links 334, 336, 338 form a support for the parts 330 and 332, an anti-extruder for these parts and are a retainer for these parts. Therefore, it is desirable that the edges of the links 334, 336, 338 engage surfaces 61, 140 before the elastomeric parts 330 and 332 are extruded beyond the adjacent edges. It is undesirable that this extrusion occurs beyond the edges rather than the sealing contact of the edges 40 since elastomeric material between the edges and the surfaces 8300566 - 30 - 60, 140 may be detrimental to the sealing engagement of the links 334, 336, 338 Thus, as shown and described, the volume of the elastomeric material in the parts 330 and 332 has been calculated and predetermined so that the edges touch the surfaces 60, 141 before extrusion of the parts 330, 332 could take place.

Links 334, 336, 338 are designed thin enough to be deformed in sealing contact at a compression setting of several hundred bar. The connecting rings 340, 342, 346 form stress points or weak zones around the annular Z part 220, which place the bend of the Z part 220 at predetermined points to cause the inner and outer edges of the Z part 220 properly sealingly contacts the bore wall 61 and the outer wall 140. When actuated, the edges are pressed onto the bore wall 61 and outer wall 140 to provide a metal-to-metal seal between the well head 24 and the pipe hanger 50 to seal the top ring space 134 with respect to the bottom ring space 130 of the well. The sealant 210 is designed to ensure that there is no fluid channel or leakage path between surfaces 61 and 140.

In the sealing position, the lower link 338 bends at the connecting ring 346, causing the outside 343 of the lower link 338 to lower and engage the upper end 372 of the lower cam portion 222.

The taper of the surface 372 of the lower cam portion 222 forms an initial initial deformation angle for the lower annular link 338. The surface 372 also ensures that the link 338 does not become horizontal so that the link 338 becomes detached when the sealant is removed. 210 is prevented. As the lower end 364 of the drive member 218 moves downward, the upper link 334 bends on the connecting ring 344 causing the inner side 333 of the upper link 334 to engage the lower end 364 as the lower end 364 compresses the Z-section 220. The intermediate link 336 moves from its tilt to a more horizontal position. The elastomeric parts 330, 332 are compressed between links 334, 336, 40 338 and engage sealingly on bore wall 61 8300566 - 31 - τ> and outer wall 140. The inner edges of links 334, 336 make annular sealing contact with the outer wall 140 of the tube hanger 50 at 380, 382, and 384 and the outer edges of the links 334, 336, 338 make annular sealing contact with the bore wall 61 of the wellhead 24 at 386, 388, and 390. The sealant 210 thus achieves a six-pointed annular metal-to-metal sealing contact. The sealing contact of the inner and outer edges causes the links 334, 336, 338 to become anti-extrusion linings for the elastomeric parts 330, 332. The elastomeric parts 330, 332 serve as support seals for the metal seals.

As the links 334, 336, 338 move from their inclined position to a more horizontal position upon actuation, each end or each inner and outer edge of the links 334, 336, 338 moves in contact with the bore walls 61 and 140 Links 334, 336, 338 are not intended to be horizontal. It is important that the inner and outer edges of the links 334, 336 and 338 are tensioned between the bore wall 61 of the wellhead 24 and the outer wall 140 of the tube hanger 50. The inner and outer edges of each link are subject to the reaction of the payload of the other. For example, when the inner edge 356 of the link 336 presses against the tube hanger wall 140, this contact causes a reaction force on the outer edge 385 which moves the outer edge 385 towards the wellhead bore wall 61. If each link had no opposite edge, the link would move further down until its side engaged an adjacent link rather than moving in sealing contact with the wall 61 or 140. This pressing against the inner and outer edges creates it is necessary to prevent buckling or bending in the middle part of the link. Therefore, the diamond cross-section requires that the middle part of the link is so rigid that it cannot kink or relieve itself. Furthermore, if the links 334, 336 35 338 could become horizontal, the tolerances between the inside diameter of the well head 24 and the outside diameter of the tube hanger 50 would become critical. If the links 334, 336, 338 are not horizontal but slanting, it is also easier to loosen the Z part 220 when pulling out the sealant 40. The surface 364 of the drive 8300566 - 32 - part 218 and the surface 372 of the lower cam portion 222 are tapered to prevent links 334 and 44, respectively. 338 become horizontal.

It will be appreciated that the elastomeric seals 330, 332 are unnecessary when the edges of the links 334, 336, 338 sufficiently touch the surfaces 61 of the wellhead 24 and 140 of the tube hanger 50 to apply hydraulic pressure in the ring space 134. Thus, parts 330 and 332 may be omitted in some applications where there will be a void between links 334, 336 and 338. It will also be appreciated that parts 330 and 332 may be replaced by a spacer that allows for a predetermined degree of collapse or deformation of the links 334, 336, 338. As described in the present embodiment, the elastomeric parts 330 and 332 become such a spacer. Also, the present invention is not limited to an elastomeric material.

Parts 330 and 332 may be made of other resilient materials such as Grafoil, an all graphite packing material manufactured by DuPont. Grafoil can be used especially when fire resistance is required. "Grafoil" is described in the publications "Grafoil - Ribbon-Pack, Universal Flexible Graphite Packing for Pumps and Valves" by F.W. Russell (Precision 25 Products) Ltd., Great Runmow, Essex, England, and "Grafoil Brand Packing" · by Crane Packing Company of Morton Grove, Illinois. These publications are incorporated herein by reference.

It will also be appreciated that if a metal-to-metal seal is not desired, channels 368, 370 and 374 can be used to feed elastomeric material to surfaces 61 and 140 to provide a primary elastomeric seal instead of a primary metal-to-metal seal as described in the preferred embodiment. If the elastomeric seals 330, 332 are the primary seals, the annular links 334, 336, 338 become the primary support for the elastomeric seals 330, 332. These links would become actuated support rings for the parts 330, 332. In such a case the support seals should not be down at 8300566 - 33 - Τ '' - ...... ·. · - ....... - slide into place.

The present invention is designed for operating pressures of 1050 bar and therefore it is the object of the present invention to achieve a 1400 bar compression setting 5 on the sealant 210, thereby priming the sealant 210 above the expected operating pressure.

To achieve a compression setting of 1400 bar, the sealant 210 is operated by a combination of a torque and a hydraulic pressure. Initially, an initial torque of about 13,500 Nm is applied to the drill pipe 236 on the surface 18. Tongues are used to rotate the drill pipe 236 so that the torque is transferred to the lowering tool 200 and then an axial force to the sealant 210. In in particular, the drill pipe 236 rotates the mandrel 230 which in turn rotates the outer casing 250 by means of the keyed connection 320. The outer casing 250 drives the packing nut 182 by means of the crenellated connection of the lips 198, 308. The packing nut. 182 presses the drive member 28 by transmitting the axial force through the bearing 205. Since the hold-down actuator 212 has previously reached the limit of its downward movement against the locking ring 144 when moving to the hold-down position, the sealant 210, and in particular the Z part 220 compressed between the drive part 218 and the lower cam part 222. This torque provides an axial force of approximately spring 675,000 N. '

When the Z part 220 is compressed between the drive part 218 and the lower cam part 222, the elastomeric parts 330, 332 are compressed between the links 303, 336, 338 as the links 334, 336, 338 move into a more horizontal position. When this compression occurs, the elastomeric parts 330, 332 begin to completely fill the grooves formed between the links 334, 336, 338 that receive elastomeric parts 330, 332. The amount of the elastomeric material of the elastomeric parts 330, 332 is predetermined such that if the links 334, 336, 338 move in a more horizontal position, the links 334, 336, 338 have sufficient contact with the bore wall 61 of the wellhead 24. and reaching the outer bore wall 140 of the tube hanger 50 to function as metal anti-extrusion agents to prevent extrusion of 8300566/34 elastomeric seals 330, 332. In particular, the annular contact zones 382, 384 on the inside prevent extrusion of the elastomeric parts 332 on the inside and the annular contact zones 386, 388 prevent the extrusion of the elastomeric part 330 on the outside. Thus, an initial anti-extrusion seal is achieved by the links 334, 336, 338 before the elastomeric parts 330, 332 can be extruded beyond their adjacent annular sealing contact zones. It is important that the elastomeric parts 330, 332 have the correct volume of elastomeric material and shape so that when the sealant 210 is compressed metal anti-extrusion contact is achieved for the extrusion of the elastomeric parts 330, 332 beyond the contact zones 382, 384, 386, and 388.

The particular purpose of the initial torque is to adjust the elastomeric support seals 330, 332 and not a metal-to-metal seal between the surfaces 61, 140 of the wellhead 24, respectively. reach the pipe hanger 20 50. The initial torque is unable to fully operate the metal-to-metal sealant 210 due to friction losses in the riser, blowout preventer system, drill pipe itself, and more specifically due to different screw loads such as on threads 118. These friction losses limit the compression load that can be applied -......

facing the sealant 210 through the drill pipe 236.

To achieve the desired compression setting of the sealant 210, a hydraulic pressure 30 is combined with the torque to adjust the metal-to-metal seals of the sealant 210. Referring now to FIG. 2A and 2B, the blowout valve 40 is shown schematically and includes rams 34 with kill line 38 communicating with the ring space 134 below the erup-35 tie valve rams 34. Typically, the kill line 38 is positioned below the lower Ram. If for any reason choke line 36 was the bottom line in blowout valve 40, hydraulic pressure would be applied through choke line 36.

40 When applying pressure via the kill line 8300566 - 35 - 38 and in the ring space 134 it is necessary to seal the ring space 134. In Pig. 2A it is noted that the kill line 38 is depicted in phase with rams 34 but is actually fabricated 90 ° out of phase. Thereby, the pipe frames 34 are sealed to seal around the drill pipe 236, seal O-ring seals 264, 266 between mandrel 230 and sleeve 240, seal O-ring seals 292, 294 between sleeve 240 and inner surface 272 of the hanger 50 and, as discussed above, the sealant 210 provides the initial seal over the ring space 134. Thus, hydraulic pressure can be applied by the kill line 38 in the ring space 134.

Due to the corkscrew effect caused by the application of torque to a drill string such as the drill pipe 236, a torque of 13,500 Nm is generally considered to be the greatest torque that can be transmitted through an underwater drill string. In the present invention, a torque of 13,500 Nm on the drill pipe 236 will create a seal over the ring space 134 which will resist several hundred 20 bar hydraulic pressure. This relatively low pressure seal will then allow the pressurization of the annulus 134 to further compress the sealant 210, which in turn increases the seal in the annulus 134 to resist additional hydraulic pressure. The metal annular Z-section 220 with the annular links 334, 336, 338 is designed such that the rings 334, 336, 338 are thin enough to provide a metal-to-metal seal in conjunction with elastomeric seal 330, 332 to resist a hydraulic pressure of several 30 hundreds of bar when applying a torque of 13,500 Nm.

When pressure is applied to the sealant 210, the effective pressure zones are the diameter of the lowering tool seal 264 minus the diameter of the drill pipe 236 and additionally the annular sealing zone of the sealant 210. Since the annular sealing zone is defined for a wellhead and tube hanger of a certain size, the main variable in determining the pressure adjusting force is the difference in pressure-40 area between the lowering tool seal 264 and the 8300566 ^ 36-I. .......... m __ _ _ _ ............ ____ drill pipe 236. Thus, this difference can be varied to apply a predetermined compression adjustment force to the sealant 210. This difference in diameter can vary, for example, between 12.5 and 25 cm.

The particular function of the hydraulic pressure is to provide an axial force which can generate 1400 bar in the sealant 210 without exceeding the design pressure limits of the equipment in the wellhead system.

The function of the torque on the nut 182 after the hydraulic pressure has been applied is to cause the nut 182 to follow the movement of the sealant 210 as it moves down under force and to prevent its release when the hydraulic force is released. It is important that a high torque, namely 13,500 Nm, be maintained in the drill pipe 236 so that the packing nut 182 follows the sealant 210, otherwise the nut 182 may prevent the downward movement of the sealant 210. This procedure is repeated by gradually and continuously increasing the hydraulic pressure until the packing nut 182 has been turned a sufficient number of revolutions to ensure that a compression setting of 1400 bar has been achieved by the sealant 210.

The lowering tool 200 is a combination tool for applying torque to the holding down and sealing assembly 180 and for applying hydraulic pressure; help exert on the hold-down and seal assembly 180.

The rotation of the drill pipe 236 for transmitting torque through the lowering tool 200 to the hold-down and sealant 180 allows an initial sealing touch of the sealant 210 in the annulus 134 between the wellhead 24 and the hanger 50, thereby providing a hydraulic pressure can then be applied to the annulus 134 to further adjust the sealant 210. As the hydraulic pressure is gradually and continuously increased 35 in the annulus 134 via the kill line 38, the sealant 210 is further compressed to a greater sealing contact against the surface 61 of the wellhead 24 and the surface 140 of the hanger 50. sealing contact increases, the sealant 210 will seal against 40 an even greater pressure in the annulus. Thus, the pressure through the kill 8300566 - 37 - line 38 can be gradually increased until the sealant 210 has a compression setting of about 1400 bar. The pressure applied through the kill line 38 and ring space 134 does not exceed the design limits of the system. All systems have a standard operating pressure that an operator should not exceed. The system of the present invention is designed for operating pressures of 1050 bar, and the hydraulic pressure in the annulus 134 to fully operate the sealant 210 cannot exceed 1050 bar although a compression setting of 1400 bar is desired. The present invention achieves a compression setting of the sealant 210 of 1400 bar without applying a hydraulic pressure greater than 1050 bar.

As the hydraulic pressure is gradually increased in the annular space 134 to achieve a compression setting on the sealant 210 of 1400 bar, the packing nut 182 follows, due to the continuous application of 13,500 Nm of torque to the drill pipe 236 being transferred. on the shroud 250 the sealant 210 down into the annulus 134 on the threads 204. When releasing the hydraulic pressure through the kill line 38 and the annulus 134, the packing nut 182 prevents the 1400 bar compression setting from lifting on the sealant 210 25 due to the engagement of the thread 204 with the tube hanger 50.

It is important that the elastomeric seals 330, 332 be energized to sealing contact after the initial torque is applied through the drill pipe 236.

Unless the elastomeric parts 330, 332 have been brought into contact, the application of hydraulic pressure through the kill line 38 will be lost along the sealant 210 to the bottom ring space 130. The sealing of the elastomeric parts 330, 332 need only be sufficient. to seal against part of the hydraulic pressure via the kill line 38 such as 35 bar. After the initial sealing is achieved, the application of increasing hydraulic pressures will further compress the Z-part 220 and elastomeric parts 330, 332 to increase the metal-to-metal and elast-40 sealing contact with the walls 61, 140.

8300566 * '- 38 -

This enlarged seal contact will allow the continued increase in hydraulic pressure through the kill line 38 to further operate sealant 210.

The sealing actuator just described is a simplification of known operating embodiments. Known operating means exert a downward pressure through the drill pipe to operate an internal port piston system.

A dart seals the end of the drill pipe bore to apply pressure through the piston system which in turn exerts pressure on the seal. Although such a known operating system could be used in the present invention, the embodiment of the present invention has significant advantages over the known system.

It may be necessary to increase the torque initially applied to the drill string 236 after the blow-off valve frames 34 are closed. Although the rubber contact of the rams 34 with the drill pipe 236 does not cause a friction loss such as a metal-to-metal contact, some additional friction loss will occur. Thus, an additional torque can be applied to the drill string 236 above the initial torque if possible to overcome this friction loss. However, the drill pipe 236 will rotate with the rams 34 in the closed position. The annulus between the riser and the drill pipe 236 contains well fluids, whereby well fluids 25 will be located between the pipe rams 34 and the drill pipe 236 upon closure of the blowout preventer 40. It is therefore believed that the torque of 13,500 Nm will not be significantly reduced. If, due to the particular application, the friction between the pipe rams 34 and the drill pipe 236 is to be reduced, a special pipe connection, not shown, can be connected in series in the drill pipe 236, whereby the pipe rams 34 engage a stationary tubular member with a rotating member passing therethrough to transmit the torque along the rams 34. Such a special pipe connection will include rotary seals between the stationary part and the rotating inner part to prevent the passage of liquid.

Referring now to FIG. 5A, 5B and 5C, the complete assembly of the wellhead 24 is shown with a 40 16 inch pipe hanger 420, a 13-3 / 8 inch pipe hanger 50, an 8300566 - 39 - 9-5 / 8 inch pipe hanger 400 and a 7 inch tube hanger 410. Tube hanger 50 is shown in FIG. 5B in the hold-down and seal position described in FIG. 1-4 wherein the hold down and seal sax set 180 is seen in the hold down and seal position. The 9-5 / 8 inch tube hanger 400 is shown supported at 402 on the top of tube hanger 50.

The tube hanger 400 also includes a hold down and seal assembly 404 similar to the assembly 180 of the tube hanger 50. The 7 inch tube hanger 402 is shown supported at 412 at the top of the 9-5 / 8 inch tube hanger 400. The tube hanger 410 includes a hold-down and seal assembly 414 similar to the assembly 180.

Fig. 5A and 5B show the hold-down grooves of the wellhead 24, namely the hold-down groove 68 for the tube hanger 50, the hold-down groove 406 for the tube hanger 400, and the hold-down groove 416 for the tube hanger 410. The tube hangers 400 and 410 do not need a shoulder ring such as the shoulder ring 128 for the tube hanger 50. Since the tube hangers 400, 410 support a smaller load, the amount of contact support surface 20 required for the tube hanger 50 is not needed for the tube hangers 400, 410. The hanger 50 requires a 100 percent contact area that is not required for the hangers 400, 410. Furthermore, the shoulders on the hangers 400, 410 are straight and run smoothly at the top of the support hanger.

FIG. 5C shows an alternative embodiment for a removable tube hanger support seat or latch block housing seat 70 shown in FIG. 2C. Referring now to FIG. 5C shows a modified latch block housing seat 420 that can be lowered into the bore 60 and 30 connected to the latch block teeth 66 of the wellhead 24.

In some areas, there are formations under the 20 inch move that cannot take the pressure of the mud weight used to trap the bottom hole pressure. To prevent the fracture of this formation by the weight of the mud, it becomes necessary to lower a 16 inch casing string through this formation prior to drilling the bore for the 13-3 / 8 inch casing. The 16 inch casing hangs from the modified locking block housing seat 420. The locking block housing seat 40 420 thus has a dual function as a support shoulder for the 8300566 ► - 40 - \ pipe hanger 50 and as a pipe hanger for the 16 inch casing 422.

The housing seat 420 includes a solid tubular ring 424 and a grommet 426. The solid tube-shaped ring 424 includes external locking block teeth 428 that are substantially the same as the locking block teeth 76 described in connection with the housing seat 70. The ring 424 also has an upwardly directed and tapered conical seat or support shoulder 430 configured to engage the packing ring 426. The ring 424 also includes a plurality of keys 432 which are substantially the same as those shown in FIG. 2C shown keys 92 to lock the housing seat 420 into the wellhead housing 46. The ring 424 includes a socket end 434 for screwing to the top pipe section of the 16 inch casing string 422.

The top portion of the ring 424 includes a counterbore 438 for receiving the pin end 440 of the packing ring 426. The packing ring 426 includes external threads for screw connection to the internal screw thread in the counterbore 438 of the ring 424 at 442. The grommet 426 includes an upwardly directed support shoulder 450 for engaging the downwardly directed shoulder 132 of the tube hanger 50. O-ring seals 444 and 446 are provided in O-ring grooves around the top of the gasket-ring 426 for sealing engagement with the bore wall. 61 of the well head 24. The packing ring 426 also includes O-rings 452, 454 contained in O-ring grooves above the threads 442 on the pin 440 for sealing contact with the wall of the counterbore 438. of the ring 424. A test port 30 456 is interposed between O-rings 452, 454 for testing packing ring 426.

Since the 16 inch casing column 422 is to be cemented, the housing seat 420 has slots or channels 435 shown with dashed lines in FIG.

35 5C. The channels 435 include the natural passage of the locking block slots, such as the slots 86, 87 of the housing seat 70 and the wellhead 24 shown in FIG. 3, and a series of circumferentially spaced slots through the continuous ring flange 85 aligned 40 above the latch block slots 86, 87. The slots 8300566 - 41 - of the flange 85 are narrower than the latch block slots 86, 87 to prevent the seat 420 from passing through the wellhead 24. The packing ring 426 is applied to the annulus 134 after cementing. To test the packing ring 426, the blowout valve rams are closed and the lowering tool is sealed under the test port 456 and the annulus 134 is pressurized. If there is a leak between the wellhead housing 46 and the packing ring 426 or the packing ring and the counterbore 438, it is impossible to pressurize the ring-space 134. There will also be increased volume hydraulic flow to ring space 134 from kill line 38. It is not necessary for the packing ring 426 to provide a high pressure seal since at this stage of well completion most pressures will be in the range of less than 350 bar.

It will be appreciated that in another embodiment, the housing seat 70 and the pipe hanger 50 can be made in one piece, the seat 70 and the hanger 50 being lowered into the well in one row and mounted in the well head 24. For example, the hanger 50 may include the locking block teeth for direct engagement with the wellhead locking block teeth 66.

In another embodiment, the length of the tubular ring 424 of the housing seat 420 may be increased, whereby the sealant 210 and / or the actuating retaining means 212 may be applied directly to the housing seat * 420 and between the seat 420 and the wellhead 24 for sealing and / or holding down engagement with the wellhead 24. In such a case, the packing ring 426 is no longer required.

The invention is not limited to the described embodiments which can be modified within the scope of the invention.

8300566

Claims (140)

1. Seat for supporting a plurality of pipe hangers in a wellhead from which pipes hang in a well, characterized by a tubular body received in the wellhead, connecting means arranged on a tubular body to detachably connect the tubular body to the wellhead and shoulder means on the tubular body which are adapted to support the lower pipe hanger by engagement. 2. Seat according to claim 1, characterized in that the shoulder means is provided with a bearing surface which can support the load of the pipe hangers and pipes suspended in the well head and a working pressure of 1050 bar. 3. Seat as claimed in claim 1, characterized in that the shoulder means is provided with a bearing surface that can support the load of the pipe hangers and the suspended pipes together with the working pressure of the well without significant exceeding of the tensile limit of the material at vertical compression of the tubular body. 4. Seat according to claim 1, characterized in that the shoulder means is provided with a bearing surface which can support a vertical pressure load greater than 27,000,000 N. Seat according to claim 1. characterized in that the shoulder means is provided with an annular support shoulder with an effective horizontal thickness of at least 33 mm. 6. Seat according to claim 1, characterized in that the shoulder means is provided with a tapered ring shoulder with a taper angle greater than 30 °. 7. Seat as claimed in claim 1, further characterized by a locking means for locking the tubular body in the well head. Seat according to claim 1, characterized by a means for releasably connecting a lowering tool to the tubular body. 8300566 »> - 43 - 9. Seat as claimed in claim 1, characterized in that the connecting means is provided with screw thread on the head and on a support part for screw thread engaging these parts upon rotation of the support part. 10. Seat according to claim 1, characterized in that the connecting means is operated at a rotation of 30 ° of the tubular body. Seat according to claim 1, characterized in that the connecting means is provided with 10 locking block teeth. 12. Seat as claimed in claim 1, characterized in that the connecting means is provided with teeth with a profile which equalizes the stresses over all teeth. 13. Device for supporting a hanger from which a pipe hangs in a borehole, characterized by a head part, a support part which is telescopically received in the head part and can engage on the hanger, several spaced apart in the circumferential direction. threads on the inner circumference of the head portion and on the outer circumference of the support portion, the threads on each part being aligned with the spaces between the threads on the other part, the threads engaging with each other to prevent the parts from axially extending move together upon the application of an axial force thereon allowing the support member to engage the head member and provide a support for supporting the borehole hanger and pipe. 14. Device for supporting a pipe hanger from which a pipe hangs in a well, characterized by a head part, a support part which can engage on the pipe hanger and which can be inserted into the head part, teeth mounted on the head part and the support -35 part to detachably connect these parts when the support part is rotated, said teeth comprising a plurality of spaced groups of teeth, the groups of the support part being able to pass between the groups of the head part during insertion of the support part 40 in the head section. 33 00 56 6 - 44 - 15. Device as claimed in claim 14, characterized in that the teeth engage fully when the supporting part rotates by less than one revolution. 16. Device as claimed in claim 14, characterized in that the teeth are tapered with a pitch angle 0 for increasing the shearing surface of the teeth. 17. Device as claimed in claim 14, characterized in that the teeth on the support part fit without clamping on the teeth on the head part. 18. Device according to claim 14, characterized in that the teeth have a non-straight shoulder profile to prevent the collection of drill cuttings on the teeth. 19. Device as claimed in claim 14, characterized in that the groups of teeth comprise tooth segments, so that when rotating for engagement the rotating tooth segments of the support part clean the tooth segments of the head part. 20. Device according to claim 14, characterized in that the teeth have a tooth profile for equalizing the stresses over all teeth. 21. Device according to claim 14, characterized in that the teeth all have the same length, the number of groups on the head part is equal to the number of groups on the support part and each of these parts has an even number of groups, so that when engaged the stresses and loads are evenly distributed between the 3 0 teeth. 22. Device according to claim 14, characterized in that each of these parts comprises six groups and six spaces. 23. Device according to claim 14, characterized in that the groups each comprise six rows of teeth. 24. Device as claimed in claim 14, characterized in that a tooth on the support part has an axial width greater than the other support part teeth to prevent premature engagement between these parts. 8300566 - 45 - 25. Device as claimed in claim 14, characterized by interlocked toothless zones of cylindrical shape on each of these parts. 26. Device according to claim 14, characterized in that the groups of teeth on the head part have at least substantially the same circumferential length as the groups of teeth on the support part. 27. Device as claimed in claim 14, characterized by an anti-rotation means for preventing relative rotation of the parts. 28. Device according to claim 27, characterized in that the anti-rotation means is provided with a stop on one of the parts in engagement with the other part. 29. Device according to claim 27, characterized in that the anti-rotation means is activated when the support part is rotated by less than one revolution. 30. Device according to claim 27, characterized in that the anti-rotation means is provided with a movable element on one of the parts which is placed in a cavity in the other part. An apparatus according to claim 30, wherein the movable member is movable to permit decoupling of these parts by relative rotation of the parts without relative axial movement, followed by relative axial movement of the support part from the head part in the absence of relative rotation. . 32. Device according to claim 31, characterized in that the support part is provided with a means for disengaging the movable element. 33. Device according to claim 14, characterized in that the passage of the groups of teeth 35 on the support part between the groups of teeth on the head part provides an indication that the teeth have engaged with rotation of the support part. 34. Device for supporting a plurality of stacked pipe hangers from which pipes 40 hang in a well bore, characterized by a head 8300566% - 46 part, a support part with a first bearing surface which can engage the lower pipe hanger, teeth. head part and on the support part for releasably connecting these parts, the teeth having a second support surface for supporting the support part on the head part, the first and second support surfaces each having a different surface, so that the load of the pipe hangers and suspended pipes together with the working pressure of the well does not significantly exceed the material tensile limit when vertically compressing the support part and the head part. 35. An apparatus according to claim 34, characterized in that the head portion has a minimum bore of 17-9 / 16 inches to receive a standard 17½ inch drill bit to drill the well bore for the pipe suspended from the bottom pipe hanger. Device according to claim 34, characterized in that the head part and the support part are made of material with a tensile limit of at least 5950 bar. Device according to claim 34, characterized in that the bearing surfaces can support a load greater than 27,000,000 N. 38. Device according to claim 34, characterized in that the first bearing surface is provided with a tapered ring shoulder on the support part with a tapered angle greater than 30 °. 39. Device according to claim 34, characterized in that the teeth comprise a plurality of segmental circular grooves on each of the parts, wherein the segmental grooves of the support part can pass between the segmental grooves of the head part. 40. Sealing assembly mounted on a tubular member slidably received in a bore of another member to provide a metal-to-metal seal between the tubular member and the inner wall of the bore, characterized by multiple truncated conical metal rings stacked in series with each ring alternating in frusto-conical taper, with a ring shoulder mounted on the tubular portion, with an operating portion reciprocally mounted on the tubular portion, and 8300566 ♦ - 47 - ~ the ring shoulder and the actuating member have opposite surfaces which engage the end rings of the stack upon sealing contact, the metal rings, the ring shoulder and the actuating member having an outer diameter smaller than the diameter of the bore, an actuating means for applying a axial force on the actuating part causes the actuating part to congr rests on the stack of metal rings and brings the inner and outer edges of the rings into metal-to-metal sealing contact with the tubular portion and the inner wall of bore. 41. Sealing assembly according to claim 25, characterized in that the metal rings have a sufficient radial width, so that the inner and outer edges of the metal rings engage and sealingly engage the tubular part and the inner wall of the bore and so that they are deformed to a smaller cone angle. Sealing assembly according to claim 25, 20, characterized in that the metal rings are compressed beyond their tensile limit between the ring shoulder and the operating part. 43. Sealing assembly according to claim 40, characterized in that annular links between the metal rings, the ring shoulder and the operating part form a positive connecting link between the annular part and the operating part. 44. Sealing assembly according to claim 41, characterized in that the adjacent metal rings form an annular groove for receiving elastomeric sealing. 45. Sealing assembly according to claim 40, characterized in that spacers are arranged between adjacent metal rings. 46. Sealing assembly mounted on a tubular member slidably received in a bore of another member to provide a metal-to-metal seal between the tubular member and the wall of the bore, characterized by a single piece 40 shaped annular body with an upper annular portion, 8300566 '. - a middle part and a bottom annular part, the middle part having a truncated cone shape with a top edge connected in one piece with a lower peripheral edge of the top annular part and a bottom edge 5 connected in one piece with an upper peripheral edge of the lower annular portion, an actuating means for applying a compressive force to the body causes the upper and lower annular portions to move towards each other, deforming the middle portion into a smaller cone angle so that the top and bottom edges of the center portion come into metal-to-metal sealing contact with the tubular portion and the bore wall. 47. Sealing assembly according to claim 46, characterized in that the middle part has a Z-shaped cross section with an upper frusto-conical link, an intermediate frusto-conical link and a lower frusto-conical link. 48. Sealing assembly according to claim 46, 20, characterized in that the middle part comprises a series of frusto-conical links whose direction of frusto-conical taper alternates. 49. Sealing assembly according to claim 48, characterized in that there are an odd number of these frusto-conical links. 50. Sealing assembly for forming a seal between a pipe hanger and a wellhead, characterized by a plurality of frusto-conical metal rings stacked in series, each metal ring having a frusto-conical taper in a direction opposite to the frusto-conical taper of each adjacent metal ring, and having an inner and outer edge, an annular portion that can be mounted on the tube hanger, an actuating member movable back and forth on the tube hanger, the metal rings, the annular portion and the actuating portion have an outer dimension smaller than the diameter of the wellhead bore, with the stack of metal rings arranged between the annular portion and the actuating member, so that when moving from the actuating member to the annular portion, the 8300566 - 49 - inner and outer edges of the metal rings radially inward or. move outward to cause sealing contact with the pipe hanger and wellhead. 51. Sealing assembly according to claim 50, characterized in that the metal rings form a Z and comprise an upper frusto-conical ring, an intermediate frusto-conical ring and a lower frusto-conical ring. Sealing assembly according to claim 50, characterized in that there are an odd number of these frusto-conical metal rings. Sealing assembly according to claim 50, characterized in that the metal rings have a thickness permitting a metal-to-metal seal of at least 15 210 bar between the pipe hanger and the wellhead when a torque of 13,500 Nm is applied to the actuator -part. 54. Sealing assembly according to claim 50, characterized in that the metal rings are made of a metal with a yield point that is less than half the yield point of the pipe hanger material and the wellhead. 55. Sealing assembly according to claim 50, characterized in that the metal rings are made of a stretchable material that deforms plastically upon sealing contact. 56. Sealing assembly according to claim 50, characterized in that the metal rings are made of a stretchable material which allows the plastic deformation of the edges in the imperfections of the walls of the pipe hanger and the wellhead. Sealing assembly according to claim 50, characterized in that annular links connect the adjacent metal rings. 58. Sealing assembly according to claim 57, characterized in that other annular links connect the metal end rings of the stack to the adjacent annular part and operating part, whereby the annular links form a positive connecting link between the annular part and the operating part. 8300566 * - 50 - Sealing assembly according to claim. 58, characterized in that the other annular links have a width that allows these other annular links to bend, so that the edge of these connected adjacent metal ring may contact the adjacent tube hanger and wellhead. 60. A sealing assembly according to claim 59, characterized in that each annular link and adjacent metal ring forms a means for receiving an annular resilient member to produce an elastomeric seal between the tube hanger and the wellhead. 61. A sealing assembly according to claim 50, characterized in that a spacer is arranged between adjacent metal rings to determine the magnitude of movement of the adjacent metal rings towards each other. 62. Sealing assembly according to claim 61, characterized in that the spacer comprises annular resilient parts. 63. Sealing assembly according to claim 62, characterized in that the annular resilient parts are made of elastomeric material. 64. Sealing assembly according to claim 62, characterized in that the annular resilient parts are made of grafoil. Sealing assembly according to claim 50, characterized in that annular elastomeric parts are arranged between adjacent metal rings. 66. Sealing assembly according to claim 65, characterized in that the metal rings block the ex-trusion of the elastomeric parts. 67. Sealing assembly according to claim 65, characterized in that the volume of the annular elastomeric parts in connection with the annular space between the pipe hanger and the well head is determined such that the edges come into contact with the pipe hanger and the well head. before the elastomeric parts are extruded along these edges. 68. Sealing assembly according to claim 65, 8300566 - 51 - characterized in that the annular elastomeric parts have a generally V-shaped cross section, the legs being chamfered opposite the top about the volume of the elastomeric part between the adjacent metal rings 5. 69. Sealing assembly according to claim 65, characterized in that the elastomeric parts are connected to the adjacent metal rings. 70. Device for operating an elastomeric and metal-to-metal seal disposed in the annulus formed by a wellhead and a pipe hanger, characterized by an actuator portion of which extends into the annulus and engages with the seal, a torque transmission means which engages the operating part to transmit a torque and rotate the operating part with the operating part being mounted. screwed onto the tube hanger so that when torque is transferred to the hot actuator in one direction, the actuator moves down on the tube hanger a sufficient distance to energize the seal and seal the ring space against fluid flow, providing a hydraulic means to the exert a hydraulic pressure on the gasket, energizing the metal-to-metal portion of the gasket in sealing contact of metal-to-metal with the wellhead and pipe hanger, the operating part following the operation of the seal downward on the pipe hanger to prevent the seal is released when the hydraulic pressure is removed. 71. An apparatus according to claim 70, characterized in that the hydraulic means comprises a conduit communicating with the annulus above the seal and a pump connected to the conduit to apply hydraulic pressure in the annulus. 72. Device according to claim 70, characterized in that the torque transmission means transmits a torque of 13,500 Nm to the operating part to cause a seal of 210 bar in the ring space. 73. An apparatus according to claim 70, characterized in that the hydraulic means exerts a gradually increasing pressure about a compression setting 8300566 *. Of the seal of 1400 bar. 74. Device according to claim 70, characterized in that the torque transmission means comprises a pipe connected to the operating means and a means 5 for rotating the pipe. 75. Device according to claim 74, characterized by a means for sealing between the pipe and the wellhead. 76. Device as claimed in claim 74, g -10 characterized by a means for sealing between the pipe and the pipe hanger. 77. Tools on a pipe string to lower a pipe hanger and a casing into a subsea wellhead and operate a seal and hold down assembly on the pipe hanger 15, characterized by a mandrel one end of which is connected to the pipe string and the other end is received in the tube hanger, a jacket portion mounted on the mandrel, a torque transmission means on the jacket portion mounted and engaging the sealing and holddown assembly, a sleeve portion telescopically received in the annular chamber formed between the jacket portion and the mandrel, with a portion of the sleeve portion extending between the mandrel and the tube hanger, and a locking means mounted on the sleeve portion and operated by the mandrel to releasably connect the mandrel to the tube hanger. 78. Tools according to claim 77, characterized in that the casing part and the mandrel are connected by co-operating splines for transmitting a torque. 79. A tool according to claim 78, characterized in that the wedges have opposite shoulders on their lower end and are held by a holding member screwed to the mandrel. 80. A tool according to claim 77, characterized in that the casing part is provided with a port for passage of well fluid. 81. Tool for lowering a pipe hanger into a subsea wellhead, characterized by a mandrel screwable at its top end 8300566 - 53 - onto a pipe string and accommodated at its bottom end in the pipe hanger, a sleeve portion reciprocating is movably mounted on the mandrel and a portion of which is disposed between the mandrel and the tube hanger, a locking means 5 mounted on the portion of the sleeve member to engage the tube hanger and connect the mandrel to the tube hanger, the sleeve portion and the mandrel have a first position in which the locking means is engaged and a second position in which the locking means is released. 82. Tool according to claim 81, characterized in that the sleeve part and the mandrel have opposite shoulders for holding the sleeve part on. 83. Tool according to claim 81, g e-15, characterized by a sealing means for sealing between the sleeve part and the mandrel and for sealing between the sleeve part and the pipe hanger. 84. A tool according to claim 81, characterized in that the locking means comprises locking segments 20 mounted in openings through the portion of the sleeve portion, the locking segments movable radially outwardly through these openings in locking engagement with the tube hanger. 85. Tool according to claim 84, characterized in that the locking means comprises a retaining means for holding the locking segments in the openings. 86. A tool according to claim 84, characterized in that the mandrel comprises a biasing means for biasing the latch segments into engagement with the tube hanger in the first position and a release means to allow the inward radial movement of the latch segments to out of engagement with the pipe hanger. the second position. 87. A tool according to claim 86, characterized in that the biasing means comprises a radial annular projection on the mandrel to push out the locking segments. 88. Tool according to claim 86, characterized in that the release means has a ring groove 8300566 *. "- 54 - included in the mandrel to accommodate the bolt segments. 89. A tool according to claim 84, characterized in that the locking means comprises a cam means for urging the cam action locking segments out of engagement with the tube hanger when the sleeve portion and mandrel are in a third position. 90. A tool according to claim 84, characterized by a release means which prevents the mandrel from moving in the first position after the sleeve part and the mandrel have moved in the second position. 91. A tool according to claim 90, characterized in that the release means comprises a snap ring included in the sleeve portion for engagement with the mandrel when the mandrel and the jacket portion are moved into the second position. 92. Sealing and holding down assembly mounted on a pipe hanger placed in a wellhead, characterized by a rotating part screwed to the pipe hanger, a stationary part mounted on the rotating part, these parts being received in the ring -space formed by the pipe hanger and the wellhead, a latch mounted on the pipe hanger below it. stationary part, the stationary part having an upper operating part, a middle sealing part and a lower cam part, the upper, middle and lower part being made in one piece from metal, the upper operating part being rotatably mounted on the rotating part, and a torque transmission means for screwing the rotating part onto the pipe hanger causes the rotating part to move down into the annulus, causing the lower cam part to press the locking part into downward engagement with the well head and then sealingly engage the middle sealing part on the pipe hanger and the wellhead. 93. The sealing and hold-down assembly according to claim 92, characterized in that the lower cam portion includes a downwardly tapered surface opposite an upwardly directed tapered surface on the latch member, said camming surfaces. come into contact with the downward movement of the lower cam part. 94. Sealing and holding-down assembly according to claim 8300566 - 55, characterized in that the locking part is provided with means which engage the tube handle to prevent the bolt part from sliding upwards along the tube handle. 95. Sealing and holding-down assembly according to claim 92, characterized in that the central sealing part has a Z-shaped cross-section, which consists of a series of fused conical links connected in one piece, of which the frusto-conical taper alternates. 96. Sealing and hold-down assembly according to claim 94, characterized in that the lower end of the upper operating section and the upper end of the lower cam section have truncated conical surfaces 15 with a taper in the same direction as the taper of the adjacent truncated links. 97. Sealing and holding down assembly according to claim 92, characterized by a bearing between the rotating part and the stationary part to facilitate the rotation of the rotating part on the stationary part. 98. Sealing and holding-down assembly according to claim 92, characterized by a compression bearing between these parts to transfer the torque from the rotating part to the stationary part. 99. Sealing and holding-down assembly according to claim 98, characterized in that the stationary part comprises a first bearing surface opposite a second bearing surface on the rotating part, the compression bearing bearing rings being arranged between the first and second bearing surfaces. 100. Pipe hanger for suspending a pipe from a wellhead and for sealingly engaging the cylindrical wall of the wellhead bore, characterized by an annular body from which a pipe hangs in a well 35, which body has a reduced diameter portion at one end , a ring shoulder mounted on the reduced diameter portion, a ring slidably mounted on the reduced diameter portion, the ring and shoulder having frusto-conical surfaces, multiple frusto-conical metal rings 8300566 \ - 56 - which are arranged on the reduced diameter portion between the frusto-conical surfaces and are stacked in series with the frusto-conical taper of the rings alternating, the end rings of the stack of metal rings in the same rings being frusto-conically tapered as the adjacent surfaces of the ring and the ring shoulder have only a smaller cone angle d on these surfaces of the ring and shoulder, the ring being movable from a non-sealing position to a sealing position, the ring in the sealing position deforming the stack of metal rings and compressing the metal rings to engage sealingly on the wellhead bore wall and the reduced diameter part. 101 »Pipe hanger according to claim 100, characterized in that the metal rings form a Z-shaped cross-section which is deformed upon application of a compression load. 102. Pipe hanger according to claim 100, characterized in that the metal rings are made of a stretchable material which deforms plastically on sealing contact. A pipe hanger according to claim 100, characterized in that annular links connect the adjacent metal rings. 104. Pipe hanger according to claim 103, characterized in that other annular links connect the metal end rings of the stack to the adjacent ring shoulder and the ring, said ring links forming a positive connecting link between the ring shoulder and the ring. 105. Pipe hanger according to claim 104, characterized in that each annular link and adjacent metal ring forms a means of receiving a resilient part to produce an elastomeric seal between the annular body and the well head. 106. Pipe hanger for suspending a pipe in a well from a well head, characterized by an annular body connected to the top end of the pipe suspended in the well, which body has a ring shoulder placed on the well head , a latch 8300566 * - 57 -% part mounted on the shoulder, a rotating part screwed to the annular body, a stationary part with an upper operating part, a middle sealing part and a lower cam part, the upper, middle and lower parts are made in one piece entirely of metal, the upper operating part being rotatably mounted on the rotating part, the stationary part being received in the annulus formed by the annular part and the well head and arranged above the locking part 10, whereby the stationary part moves in the annulus space during rotation of the rotating part and the lower cam part the locking part in downward engagement d jerks with the well head and then the middle sealing member seals against the annular part and the well head. 107. Pipe hanger according to claim 106, characterized in that the central sealing part has a Z-shaped cross section which consists of a series of truncated conical links connected in one piece, of which the truncated conical taper alternates. 108. Pipe hanger according to claim 106, characterized in that the annular shoulder comprises an annular removable part, the annular removable part having a downwardly directed frusto-conical bearing surface of 360 ° for engagement with the well head 25. 109. Pipe hanger according to claim 108, characterized in that the remaining part of the ring shoulder is provided with flow ports to allow well fluid to pass through. 110. Well device for sealing and locking a pipe hanger placed in a well head, characterized by a rotating part screwed to the pipe hanger, a stationary part with an operating part, a middle sealing part and a lower cam part, the upper part being , middle and lower parts are made in one piece from metal, the upper operating part being rotatably mounted on the rotating part and the stationary part being included in the annular space formed by the tube hanger and the well head, with a locking part 40 mounted on the pipe hanger under the stationary part, 8300566 '' - 58 - Λ. A torque transmission means which engages the rotating part to transfer the torque and rotate the rotating part, causing the rotating part to move down on the pipe hanger, whereby the lower cam part presses the locking part 5 into downward engagement with the well head and middle sealing member sealingly engages the tube hanger and well head to prevent fluid flow through the annulus t $, a hydraulic means for applying hydraulic pressure to the stationary member to further energize the middle sealing member in sealing contact with the tube hanger and the wellhead, the rotating portion following the further actuation of the middle sealing member downwardly along the tube hanger to prevent the middle sealing member from being released upon removal of the hydraulic pressure. Well arrangement according to claim 110, characterized in that the torque transmission means transmits a torque of 13,500 Nm to the rotating part to cause a seal in the annulus. 112. Well device according to claim 110, characterized in that the hydraulic means exerts a gradually increasing pressure to achieve a compression setting of the middle sealing part of 1400 bar. 113. .. Well device for hanging a pipe in a well, characterized k. through a wellhead with a bore, said wellhead having a ring shoulder with an annular locking groove disposed above it, a tube hanger having an annular bearing surface for mounting on the ring shoulder and a bolt mounted on the tube hanger above the bearing groove in the placed position, a sealing and holding down assembly mounted on the tube hanger above the latch part, the sealing and holding down assembly comprising a rotating part and a stationary part, the rotating part being screwed onto the tube hanger and the stationary part being rotatable is mounted on the rotereride part, the stationary part being received in the annulus formed by the pipe hanger and the wellhead, the stationary part having a 40 sealing part and a cam part, the cam part engaging the 8300566 - 59 - * locking part , a torque transmission means for rotating the rotating part on the tube hanger and causing it to rotate part and the stationary part move down into the annular space, the cam part pressing the locking part 5 into the locking groove to hold the pipe hanger down into the well head, the sealing part being compressed by the downward movement of the rotating part, whereby the sealing part sealingly engaging the tube hanger and well head, a hydraulic means for applying hydraulic pressure to the stationary portion thereby further energizing the sealing portion in sealing contact with the well head and tube hanger, the rotating portion moving down on the tube hanger at the further operation of the sealing member, whereby the rotating member prevents the sealing member from being released upon removal of the hydraulic pressure by the hydraulic means. 114. Well device according to claim 113, characterized in that the torque transmission means transmits a torque of 13,500 Nm to the rotating part to produce a seal of 210 bar in the annular space. 115. Device according to claim 113, characterized in that the hydraulic means exerts a gradually increasing pressure up to a maximum of 1050 bar to achieve a compression setting of the sealing part 25 of 1400 bar. A well device according to claim 113, characterized in that the sealing member comprises metal seals for causing a metal-to-metal seal between the pipe hanger and the well head. 117. Well device according to claim 116, characterized in that the sealing part further comprises resilient seals between the metal seals to produce an elastomeric seal between the pipe hanger and the well head prior to application of the hydraulic pressure by the hydraulic means. 118. Tube hanger, characterized by a body with a locating shoulder for placement on a wellhead, a hold-down applied to the body for downward engagement with the wellhead, a 40 metal sealant applied to the body 8300566 • v - 60 - * __ _____________________ ______ _______________________ __________.__ ___ ___ above the metal-on-metal hold-down holding means with the wellhead and an actuating means positioned above the metal sealing means, so that when the actuating means is moved downward, the holding-down means the well head and, upon further downward movement of the operating means, the metal sealant sealingly engages the well head. 119. Pipe hanger according to claim 118, characterized by a coupling means for transmitting a torque to the operating means and a hydraulic means for applying liquid pressure to the metal sealant. 120. Tube hanger according to claim 118, characterized in that the hold-down means comprises a longitudinally movable sleeve with a downwardly directed shoulder, a movable locking ring with an upwardly directed shoulder which engages the downwardly oriented shoulder, the body being a locking recess includes for receiving the locking ring whereby the sleeve moves downwardly when the actuating means moves downwardly, whereby the downwardly facing shoulder presses the locking ring into downward engagement with the well head. A pipe hanger according to claim 120, characterized in that the bottom side of the locking ring 25 and the bottom side of the recess have tapered mating surfaces. A pipe hanger according to claim 120, characterized in that the shoulders have tapered mating surfaces. 123. Well device for suspending a pipe in a borehole, characterized by a well head part, a seat part telescopically received in the well head part, the seat part having an upwardly directed frusto-conical ring shoulder, teeth arranged on the well head part and the seat part to detachably connect the seat part to the wellhead part when the seat part is rotated by less than 360 °, a hanger part which is attached to the top of the pipe column and which has a downward-facing bearing surface engaging 40 the shoulder of the seat part, a gate means extending through the hanger part and around the bearing surface, whereby the bearing surface and the shoulder have a circumferential contact over the full 360 °. 124. Well device according to claim 123, 5, characterized in that the bearing surface has a detachable annular support which is screwed onto the hanger part. 125. Well arrangement according to claim 123, characterized in that the teeth comprise a plurality of spaced groups of teeth, wherein the groups of the seat part can pass between the groups of the well head part during insertion of the seat part into the well head part. 126. Pit device according to claim 125, characterized in that the teeth are spaced apart threadless threads which engage without clamping upon rotation of the seat part in the well head part. 127. Well device according to claim 123, 20, characterized in that a locking part is arranged per the hanger part for expansion in a locking groove in the well head part above the bearing surface, whereby the pipe hanger is locked in the well head. 128. Well device according to claim 123, characterized in that a sealing assembly is arranged on the hanger part, the sealing assembly comprising a plurality of frusto-conical metal rings stacked in series with the frusto-conical taper of the rings alternating, the metals washers have an outer diameter smaller than the inner diameter of the wellhead, whereby an actuator may exert an axial force on the stack of metal rings whereby the metal rings are compressed in metal-to-metal sealing contact with the hanger portion and the well- 35 cup part. 129. Well device according to claim 128, characterized by a ring shoulder on the hanger part and an operating part movably reciprocally mounted on the hanger part, the stack of metal rings 40 being arranged between the ring shoulder and the operating part 8300566 * - 62. ' a 130. Well device according to claim 129, characterized by annular links between the metal rings, the ring shoulder and the operating part to form a positive connecting link between the annular part and the operating part. 131 ·. Well device according to claim 130, characterized in that the adjacent metal rings form ring grooves for receiving elastomeric seals. A well device according to claim 130, characterized by a spacer interposed between adjacent metal rings. 133. Well device as claimed in claim 123, 15, characterized in that a hold-down and seal assembly is arranged on the hanger part and is received in the ring space formed between the hanger part and the well head part, wherein the hold-down and sealing assembly is actuated upon application of a vertical compressive force thereon, an actuating member screwed to the hanger portion and a portion thereof engaging the hold-down and sealing assembly, a torque transmission means engaging the actuating member to transmit torque and rotating the actuating member causing the actuating member to move downward as the actuating member is screwed onto the hanger portion, thereby applying a vertical compressive force to the hold-down and seal assembly, a hydraulic means being applied to apply hydraulic pressure to the hold-down and sealing assembly, whereby the hydraulic pressure exerts an additional vertical pressure on h The hold down seal assembly to further actuate and operate the hold down and seal assembly. 134. Well device according to claim 123, characterized in that a first metal-to-metal sealing assembly is arranged in the annulus between the wellhead part and the hanger part to form a metal-to-metal seal therebetween, a second hanger part is placed on the hanger part and a second metal-to-metal sealant is applied to create a metal-to-metal seal between the second hanger part and the well 8300566 L * * - 63 - ♦ head part, a third hanger part is placed is applied to the second hanger portion and a third metal-to-metal sealant to cause a metal-to-metal seal between the third hanger portion and the wellhead portion. 135. Well device according to claim 134, characterized in that a torque transmission means successively engages the first metal-to-metal sealing assembly, the second metal-to-metal sealing assembly and the third metal-to-metal sealing assembly for a vertical compressive force. to operate these assemblies and a hydraulic means successively applies hydraulic pressure to the first metal-to-metal sealing assembly, the second metal-to-metal assembly and the third metal-to-metal sealing assembly to of these sealing assemblies to act as a sealing engagement. 136. Method of completing an underwater well, characterized in that (a) a drilling means is placed at the location of an underwater well, (b) a guide pipe is installed at the bottom of the body of water with a wellhead, blowout preventer system and a riser connected thereto at a point near the bottom, the riser extending upward toward the drilling means, (c) a drill string and a standard 17½ inch drill bit are lowered through the wellhead and the guide tube, (d) a hole is drilled to hang another casing in the well head and the guide tube, 30 (e) a hanger seat is lowered into the well until the seat is placed in the well head, (f) the hanger seat is rotated less than 360 ° to connect the hanger seat in the well head, 35 (g) the hanger seat is locked in the well head, (h) a pipe hanger with the other casing is lowered through the riser into the well head, and (i) the pipe hanger is placed on the suspension seat. 8300566 &. s, - 64 - 137. A method of completing an underwater well, characterized in that (a) a drilling means is placed at an underwater well, (b) a guide pipe is installed in the bottom of the body of water with a wellhead, blowout preventer system and riser 'connected thereto at a point near the bottom, the riser extending upward to the drilling means, (c) a drill string and standard 17½ inch drill bit are lowered through the wellhead and guide tube, (d) a hole is drilled to suspend another casing string within the well head and guide tube, (e) a hanger seat with lock block screw thread is lowered into the well until the lock block thread of the hanger seat engages the lock block screw thread on the well head, (f) the hanger seat is rotated by less than one revolution until the lock block screw thread on the hanger seat passes between the lock block screw thread on the well head making the hanger seat several centimeters moves down relative to the wellhead, (g) the hanger seat is rotated less than one revolution to connect the hanger seat within the wellhead, (h) a pipe hanger with a casing string is lowered through the riser into the wellhead, and ( i) the tube hanger is placed on the hanger seat. 138. A method of completing an underwater well, characterized in that (a) a guide tube is installed in the bottom of a mass of water with a wellhead, blowout preventer system and riser connected thereto at a point at the bottom, the riser extends upward to the surface, (b) a tube hanger with a casing string is lowered through the riser, (c) the. pipe hanger is placed in the well head 4. 8300566 * »- 65 - (d) an actuation ring screwed onto the pipe hanger is rotated above a seal assembly, (e) the seal assembly is compressed by the downward movement of the actuation ring 5 on the tube hanger, (f) the cone angle of the frusto-conical metal rings provided on the sealing assembly is reduced, (g) resilient parts included between the frusto-cone metal rings are compressed as the cone angles are reduced, (h) the well head and pipe hanger is sealed from liquid flow by the compression of the resilient parts, (i) hydraulic pressure is applied to the sealing assembly, (j) the well head and pipe hanger are brought into contact with the inner and outer edges of the frusto-conical metals rings if the seal assembly is further compressed by the hydraulic pressure, (k) the actuation ring is moved downward on the pipe hanger as the seal assembly is further compressed by the hydraulic pressure; (l) the hydraulic pressure is removed from the sealing assembly. 139. A method according to claim 138, characterized in that (m) a second pipe hanger with a casing column is lowered through the riser into the well head, 30 (n) the second pipe hanger is placed on the first pipe hanger (o) the steps Cd) to (e) are repeated to provide a sealing assembly for sealing the second pipe hanger on the well head, (p) a third pipe hanger with a casing column is lowered through the riser into the well head, (q) the third tube hanger is placed on the second tube hanger (r) steps (d) to (e) are repeated 40 to operate the sealing assembly to seal the third tube hanger 8300566 ', *' - 66 - *> on the well head. 140. Method of completing an underwater well, characterized in that (a) a lowering tool is connected at the end of a drill string, (b) the lowering tool is connected to a pipe hanger, (c) the pipe hanger is sealed on the lowering tool, 10 (d) the pipe hanger with a casing string is lowered through a riser, a blowout preventer system into a well head, (e) the pipe hanger is placed on a shoulder in the well head, 15 (f) the drill string and part of the lowering tool is rotated, (g) a torque is applied to an actuating nut using the part of the lowering tool, (h) the actuating nut is screwed onto the pipe hanger when the torque is applied thereto, (i) a sealing assembly under the actuating nut is compressed, (j) an elastomeric sealing of the sealing assembly is caused between the wellhead and the pipe hanger, (k) a torque of 13,500 N m is applied to the drill string until no further torque is transferred to the seal assembly, 30 (1) the erupt ieafs lazy terrains of the eruption valve system are closed, (m) a pressure is exerted on a pipe communicating with the annulus between the drill pipe and the wellhead and under the blowout preventer, 35 (n) a hydraulic pressure is applied to the seal assembly, (o) truncated conical metal gaskets in the seal assembly are compressed, (p) a metal-on metal seal is caused 40 between the well head and pipe hanger, 8300566 * - 67 - (q) the actuator is rotated further down on the pipe hanger as the hydraulic pressure further compresses the seal assembly, (r) the hydraulic pressure through the pipe 5 is removed, (s) the lowering tool is detached from the pipe hanger and (t) the lowering tool is removed from the well. A method according to claim 140, characterized in that the drill pipe is moved upwards to release the lowering tool from the pipe hanger. 142. A method of releasably attaching a lowering tool to a pipe hanger, by 15 acknowledging that (a) a sleeve of the lowering tool is slid into the pipe hanger, (b) a mandrel of the lowering tool is lowered into the sleeve moved, (c) latches arranged in the sleeve are pressed into engagement with the tube hanger, (d) the latches are held in engagement by the mandrel, (e) the tube hanger is lowered into the well with a casing string 25, ( f) the pipe hanger is placed on the well head, (g) the mandrel of the lowering tool 4 is further lowered into the sleeve when operating a sealing assembly, (h) the pressing part of the mandrel is removed from the latches , (i) the mandrel is moved upward, (j) the sleeve is connected to the mandrel for the mandrel is moved upward enough to push the latches back in, (k) the latches are pressed out of engagement with the tube hanger , and ( l) the lowering tool is removed 40 from the well. 8300566