NL8300568A - Submarine wellhead system. - Google Patents

Description

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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. To solve the particular problems associated with offshore drilling and finishing at these elevated operating 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 more than 90 m. These drills generally include a floating vessel with a riser swell compensator 15 and drill pipe extending to the blowout preventer and the wellhead that are on the mud line.

The blowout preventer system is generally mounted on a 20 inch pipe, with the riser 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 pcrap tube 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 well bore flow bore for limited access to the wellhead housing. move under the wellhead housing 8300568 v * - 2 - for drilling. In the early days of offshore drilling, 16¾ inch subsea wellhead systems required sub-clearing. At the 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 systems 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 wellhead 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. When 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, the 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 operation. The system 40 has single speed capability but can still use 8300568

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ν% of multi-tour methods. All hangers are interchangeable with regard to the external profile so that they can be 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 (working 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 has a pressure of above or below 1050 bar. The pressure greater than 1050 bar is retained in the sealant after the lowering tool 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 flushed 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 tube hanger is set high. Furthermore, it does not cause a significant reduction of the full pressure 8300568 t - o 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.

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The present patent application relates to a latch block hanger bracket in an undersea wellhead assembly which is particularly useful for offshore wells with operating pressures up to about 1050 bar. The wellhead-5 assembly includes a wellhead, the latch block hanger bracket, a gasket for sealing the latch block hanger bracket to the wellhead and another tube hanger and one or more other tube hangers supported by the latch block hanger bracket.

10 The wellhead has a 17-9 / 16 inch bore to pass a standard 17½ inch drill bit. The suspended casing latch block hanger bracket is placed and connected to the well head to support one or more of the other pipe hangers in the well head and to resist and trap the pressure load in the well. Locking block teeth are provided on the well head and the locking block hanger support for inserting the hanger support into the well head and rotating less than 360 ° to complete the connection therebetween. The locking block teeth comprise six groups of six teeth and are spaced apart helpless threads. Locking block slots are provided between adjacent groups of teeth to provide a natural flow path for well fluid passage. The lock block hanger bracket includes an annular top 25 flange to inhibit the downward movement of the lock block hanger bracket in the wellhead. This ring flange includes grooves aligned with the locking block slots to allow the well fluids to pass through. The grooves are narrower than the latch block slots to prevent the latch block-30 hanger support from passing through the well head.

The top surface of the ring flange forms a support surface for supporting one or more of the other pipe hangers. The support surface of the hanger support will increase the displacement and pan tube load as well as a working pressure of.

35 1050 bar support. The bearing surface of the locking block teeth is larger than the bearing surface formed by the ring flange of the hanger support for the next pipe hanger.

The gasket is fitted to seal the latch block hanger bracket to the wellhead and to the following 40 pipe hanger. The gasket includes means for testing whether the gasket 8300568 - 7 - "" seals are intact.

After placing, connecting, sealing and testing the locking block hanger support, the next pipe hanger with casing is placed on the locking block hanger support.

A hold down and seal assembly is placed between the well head and the next pipe hanger to hold down and seal the next pipe hanger. A second and third pipe hangers are then lowered one after the other into the well and these hangers are similarly sealed on the well head.

10 The locking block support supports three tube hangers with suspended casing and this support also withstands and confines a working pressure of 1050 bar.

Another embodiment of the invention includes the extension of the body of the latch block hanger support allowing a hold down and sealing assembly to be disposed between the latch block hanger support and the well head.

The hold-down and sealing assembly includes a sealing portion with a plurality of frusto-conical metal links joined together by connecting links to form a Z. The adjacent metal links form ring grooves to accommodate resilient elastomeric parts. A tool is provided to operate the hold-down and seal assembly by torque and hydraulic pressure to produce a primary metal-to-metal seal and a secondary elastic seal between the latch block hanger bracket and the wellhead.

8300568 -5> - * »

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

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

Fig. 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 the submarine well blowout valve of FIG. 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.

8300568

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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 representation of a typical installation of a pipe hanger and casing string of the present invention in a wellhead mounted on the sea bed 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 by a column 32 of cement to form a considerably 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 tubing 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 8300568" - "10-kill" conduits 36 resp. 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 17¾ inch drill bit is lowered through the riser 28 and the guide tube 22 to drill a deeper borehole 42 into the seabed for 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 inch 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 wellhead 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 8300568 i - 11 - * above the locking block teeth 66. The locking block teeth 66 have an internal diameter of 17-9 / 16 inches 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 wellhead housing 46 / an upwardly directed downwardly tapered conical seat or support shoulder 80 to engage the casing hanger 50 and a wedge assembly 78 to lock the housing seat 70 into the wellhead 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 inch for supporting the tube hanger 50. The housing seat 70 has a wall thickness that is is large enough to prevent the home seat 70 from collapsing under a vertical compressive stress of 6300 bar. This is important since the well head 24, due to its size, weight and thickness, 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 8300568-12 - corresponding taper to mesh appropriately with the well head teeth 66. Groups 82, 88 each include six rows of segmental teeth, which are approximately half an inch thick from the base to the surface. The threaded surface 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 deserves the preference . . that the segment-shaped teeth 66, 76 are of the same length, so that a 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. A bee- 8300568 *

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An additional advantage of the locking block connection between the well head 24 and the housing seat 70 is that the segmental teeth 76 clean the segmental teeth 66 when the housing seat 70 is rotated in the wellhead 24. The teeth 76 push drill bit from the 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 may 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 to receive one end of the spring 98. The spacers 93 are mounted by screws 95 8300568-14 in the cavity 94 on each side of the claw 92 and leave a slot 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 is adjacent to a stop slot 64 in the well head housing 46 at the full engagement of the internal and external teeth. 66 ', 76 of the well head 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 prior art, the casing hanger hanger support shoulder was formed in one piece with the wellhead housing and large enough to support the casing and compression load. 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 17 inch chisel to pass. 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 the casing casing 44, the 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 8300568 - 15 - the housing seat 70 is connected to a lowering tool (not shown) by shear pins, part of which is illustrated at 104. The lowering tool on a drill string then lowers the housing seat 70 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 the lowering tool. until keys 78 engage in the stop slots 64 to stop 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 110 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 8300568-16-236 to allow the returning material to flow to the surface. A plurality of top and bottom vertical grooves or circulation ports 122, 124 are formed by the top section 114 to allow liquid to flow, such as for the cementing operation, around the tube hanger 50. The bottom grooves 122 form fluid channels through the radial ring shoulder 116 and the upper grooves 124 form fluid channels through the upper screw end of the tubular body 110 to allow fluid to pass around the 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 face 132 that rests and engages the upwardly directed downwardly tapered tapered 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 pressure loading.

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 tube hangers with the suspended casing and one or more pump tube 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 8300568 - 17 - 1 "* of the present invention will support a load of more than 27-000,000 N since the bearing surface is in the range of 420 -452 cm · Such a bearing surface 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 pipe hanger 50 and the housing seat 70 and between the housing seat 70 and the supporting locking block teeth 66 on the wellhead 24 must be sufficient to support such loads 10 without significantly exceeding the tensile limit of the material at vertical pressure, ie by more than 25% of the tensile limit. 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 8300568 '* - - 18 - teeth is determined by the loss of bearing surface due to the six spaces 86 .87 for recording 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 locking ring 144. which is placed on the radial ring shoulder 116. The locking ring 144 may be a split ring which can be expanded into the well head groove 68 for engagement with the well head housing 46 to hold down the hanger 50 and lock it in the well head 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 face 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 upon expansion of the locking ring 144, the vertical plane 148 of the ring 144 engages the vertical wall 146 of the groove 68. Furthermore, the locking ring 144 comprises downwardly directed outward and downwardly tapered lower cam surface 152 which engages with the camming action upwardly directional cam face 136 of the radial annular shoulder 116, an inwardly protruding ring 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 cam action sealing assembly 180 described below. Between the cam head 156 and the ring edge 154, a tapered surface 158 extends parallel to the wall of the 8300568

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room 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. It is necessary during the lowering of the tube hanger 50 that the latch ring 144 passes through several narrow diameters as in the erection valve 40. The erection valve 40 often includes an annular rubber seal that does not retract fully allowing the tube hanger 50 to pass through the rubber seal. - must be printed. 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 actuation 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 8300568 20 -v in downward engagement with the groove 68 of the wellhead 24. The annular body 216 is a continuous and integrally formed 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 thus, is 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 dropped 8300568-21% into the well on the tube hanger 50 by a lowering tool 200. The lowering tool 200 includes a mandrel 230, which is the main body of the tool 200, a connecting 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 on-board pipe 236 extending to the surface 18 and a bottom socket end 238 also with internal screw 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 connecting body or sleeve 240 includes a bore 246 that can be telescopically mounted over the ring edge 252 and the sleeve end 238. The connecting body 240 is telescoped into the ring space formed by the mandrel 230 and the shell - 250. The rim 252 includes annular sealing grooves 258, 262 with O-rings 26 and 6, 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 claws 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 8300568-22-200 to the tube hanger 50. The claws 280 have an upper projection 284 contained in a ring groove 186 around the top inner perimeter 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 healed, 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 240 and the mandrel 230. The lower actuating member 306 has a crenellated bottom end 308 which engages the upper crenellated end 25 198 of the packing nut 182 to provide a torque can be transferred from the lowering tool 200 to the hold-down and sealing assembly 180. The inner diameter of the actuator 306 is large enough to run free from the outer diameter of the thread 118 on the tube hanger 50.

The middle part 302 slidably receives the connecting body 240. The portion 302 includes an internal annular groove 310 that receives the snap ring 298 mounted on the connector body 240 when disconnecting the hold-down tool 20Q 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 extending from its outer circumference to the groove 310 through which bolts (not chamfered) can be screwed into the groove 301 to prevent the snap ring 298 'from engaging the groove 310 during reset from 8300568 - 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 top 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 the groove 310 engages. Thus, to remove the connector body 240 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, packing nut 182 is only suitable. 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 ring flange 268 on the connecting body 240.

The tubular outer surface of the sleeve end 238 abuts and engages the inner side of the jaws 280 whereby the teeth 282 are pressed into the grooves 120 of 8300568-24 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 lower position of the lower tool 200 is not tilted 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 well head 24, the casing casing 44 is cemented into 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 turns the outer sleeve 250 by means of the splice connection 320. The torque of the outer sleeve 250 is transferred to the packing nut 182 on the crenelated 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. 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 jacket 250 upon actuation of the hold-down 40 and sealing assembly 180. This downward movement of the 8300568-25 mandrel 230 releases the jaws 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 when retracting and uncoupling the sealant 210 and the actuator 212 from the wellhead 24. Furthermore, this positive connection link provides metal joint that extends from the drive part 218 to the bottom cam part 222 to allow positive upward loading on the bottom cam part 222 when disengaged. 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, resp. the cam portion 222 must have a minimum length to ensure a sealing contact with the annular links 334 and 338. If the connection rings 344, 35, 346 are too short, there will not be enough curvature 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 bend and the sealing engagement of the links 334, 338 8300568

Jr - 26 -> 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 stretch limit is less than. half of the yield point of about 5950 bar of the material for the well head 24 and the 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 tends 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 upper, intermediate, and lower annular links 334, 336, and 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 ripped upward and the bottom 350 generally facing downward, at least substantially parallel annular inner and outer sides 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 seal contact-40 edges of the links 334, 336, 338 are deformed at least substantially 8300568-27 with the bore wall 61 of the wellhead housing 46 and the outer wall 140 of the tube hanger 50. The upper connection 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 for bending of the Z-section 220 at predetermined locations, namely at the connecting rings 340, 342, 344, and 346. The lower end 364 of the drive section 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 hold positions, the outer and inner sealing contact edges have the same diameter as the outer and inner diameters of the upper drive part 218 and. the lower cam part 222.

The upper and lower elastomeric members 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 top and bottom elastomeric parts 330, 332 have outer and inner annular vertical sealing surfaces 380 and 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 the links 334, 336, 338 form an anti-extrusion seal with the bore wall 61 of the wellhead 24 and the outer sealing face 140 of the well hanger 50.

It is preferred that the sealant 210 includes at least three links. This number is preferable 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. As the cross section of the links 35 334 ,. 336, 338 had the same thickness, links 334, '336, 338 may tend to bend at their center portion. Although the links 334, 336, 338 preferably have a thickened center portion to obtain the point of edge bending for a predetermined plastic deformation 40 and ensure that there is no deformation at 8300568-29 - 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 Pig. 4 and 4A

Fig. 4A the sealant 2X0 in the sealing position. The sealant 210 is compressed when the hold-down actuator 212 reaches the limit of its movement against the lock washer 144 and the packing nut 182 continues its downward movement on the threads 118 of the tube hanger 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 that a balanced force be applied to the top 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 surfaces 8300568 - 30 - 60, 140 may be detrimental to the sealing engagement of 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 outer side 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 members 330, 332 are compressed between links 334, 336, 40, 338 and sealingly engage bore wall 61 8300568-31 - '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 reaches thus a six-pointed ring-shaped metal-to-metal sealing contact. The sealing contact of the inner and outer edges causes the links 334, 336, 338 to become anti-extrusion rings 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 tilt to a more horizontal position upon actuation, each end or inner and outer edge of the links 334, 336, 338 moves into 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 links 334, 336 35 338 were to 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 210. The surface 364 of the drive 8300568 - 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 can be made of other resilient materials such as Grafoil, which is all graphite. 20 existing gasket 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 would not slide down at 8300568 - 33 - in 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 the in particular the Z part 220 is 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 reach the outer bore wall 140 of the tube hanger 50 to function as metal anti-extrusion agents to prevent extrusion of 8300568-34 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 upon compression of the sealant 210 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 IL8. These frictional losses limit the compression load that can be applied to 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 8300568 * - 35 - 38 and in the ring space 134 it is necessary to seal the ring space 134. In FIG. 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 closed 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 the 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 creates 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 given size, the main variable in determining the pressure setting force is the difference in pressure-40 area between the down tool seal 264 and the 8300568 • * - 36 - * drill pipe 236. Thus, this difference can be varied to a predetermined compression setting force to be applied 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 rotated 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 hold-down and seal assembly 180 and to help apply hydraulic pressure to the hold-down and seal assembly 180.

The rotation of the drill pipe 236 to transmit torque through the lowering tool 200 to the hold-down and sealant 180 allows an initial sealing touch of the sealant 210 into the annulus 134 between the well head 24 and the hanger 50. whereby 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 via the kill 8300568 ♦ * - 37 - '' '-% line 38 can be increased gradually until the sealant 210 has a compression setting of approximately 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.

8300568 Λ,. , - 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 actuators 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 tube hanger. 420, a 13-3 / 8 inch tube hanger 50, an 8300568 <- 39 - 9-5 / 8 inch tube hanger 400 and a 7 inch tube hanger 410. The 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 assembly 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 hangers 400, 410. Furthermore, the shoulders on 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 8300568 4 - 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 end 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 which are received in O-ring grooves above the threads 4'42 on the pin 440 for sealing contact with the wall of the counterbore 438. of the ring 424. A test port 30 456 is provided between the O-rings 452, 454 for testing the 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 8300568 * 4 »- 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 tube hanger 50 can be made in one piece, the seat 70 and the hanger 50 being lowered into the well in one row and arranged 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 can be increased, whereby the sealant 210 and / or the actuator retaining means 212 can be applied directly to the housing seat * 420 and between the seat 420 and the wellhead 24 for sealing and / or retaining 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.

8300568

Claims (52)

1- Hanger fitting for supporting a plurality of pipe hangers in a wellhead and for hanging pipes in a well, characterized by a tubular body received in the wellhead, a connecting means applied to the tubular body about the tubular body detachably connectable to the wellhead, a shoulder means on the tubular body to engage the lower pipe hanger by engagement, and a fastener to the tubular body to secure the pipes. 2. Hanger fitting according to claim 1, characterized in that the shoulder means comprises a bearing surface which can support the load of the pipe hangers and the pipes suspended in the well head and a working pressure of 1050 bar. Hanger seat according to claim 1, characterized in that the shoulder means comprises a bearing surface which can support the load of the pipe hangers and the suspended pipes together with the working pressure of the well without the material stretching limit on vertical compression of the tubular body becoming considerable. exceeded. Hanger seat according to claim 1, characterized in that the shoulder means comprises a bearing surface which can support a vertical pressure load greater than 27,000,000. 5. Hanger seat according to claim 1, characterized in that the shoulder means comprises an annular support shoulder with an effective horizontal thickness of at least 33 mm. 6. Hanger seat according to claim 1, characterized in that the shoulder means comprises a tapered ring shoulder with a taper angle greater than 30 °. 7. Hanger seat according to claim 1, characterized by a locking means for locking the tubular body in the well head. Hanger seat according to claim 1, characterized by a means for releasably connecting a lowering tool 8300568 * - 43 to the tubular body. 9. Hanger seat according to claim 1, characterized in that the connecting means comprises screw threads on the head part and the support part for screw-thread engagement of these parts upon rotation of the support part. Hanger seat according to claim 1, characterized in that the connecting means is actuated at a rotation of the tubular body by 30 °. 11. Pendant seat according to claim 1, characterized in that the connecting means comprises locking block teeth. 12. Hanger seat according to claim 1, characterized in that the connecting means comprises teeth with a profile which equalizes the stresses over all teeth. Hanger seat according to claim 1, characterized in that the fastening means comprises threads for connecting the pipes. 14. Device for supporting a hanger from which a pipe hangs and for hanging the pipe in a borehole, characterized by a head part, a hanger support part which is telescopically received in the head part and can engage on the hanger, wherein the hanger support part with thread engages a pipe string to suspend the pipe string in the borehole, multiple circumferentially spaced threadless threads on the inner circumference of the head portion and on the outer circumference of the hanger support portion with the threads aligned on each portion with the spaces between the screw threads on the other part where the screw threads interlock to prevent the parts from moving axially apart upon application of an axial force thereon, whereby the hanger support member may be engaged with the head member and a support means provided to support the borehole hanger and pipe. 15. Device for suspending a pipe in a well, characterized by a head part, a support part which is mounted on a pipe column for hanging it in the well, wherein the support part can be inserted 40 in the head part, teeth arranged on the head part 8300568 - 44 - and the support part for releasably connecting these parts when the support part is rotated, the teeth comprising a plurality of spaced groups of teeth, whereby the groups of the support part can pass between the groups of the head part during insertion of the support part into the head part. 16. Device as claimed in claim 14, characterized in that the teeth engage fully when the support part is rotated over less than one revolution. Device according to claim 15, characterized in that the teeth have a pitch angle 0 and are tapered to increase the shearing surface of the teeth. 18. Device as claimed in claim 15, characterized in that the teeth on the support engage without clamping on the teeth on the head part. 19. Device according to claim 15, characterized in that the teeth have a non-straight shoulder profile to prevent the collection of drill cuttings on the teeth. 20. Device according to claim 15, characterized in that the groups of teeth comprise tooth segments, whereby the rotating tooth segments of the support part clean the tooth segments on the head part upon rotation into engagement. 21. Device as claimed in claim 15, characterized in that the teeth have a tooth profile for equalizing the stresses over all teeth. Device according to claim 15, 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 teeth. 23. Device according to claim 15, characterized in that each of the parts comprises six groups and six spaces. Device according to claim 15, characterized by 8300568 - 45 - characterized in that the groups each comprise six rows of teeth. 25. Device according to claim 15, characterized by a tooth on the support part with an axial width greater than the other support part teeth to prevent premature engagement between these parts. 26. Device according to claim 15, characterized by threaded areas of cylindrical shape slid over each other on each of the parts. Device according to claim 15, characterized in that the groups of teeth on the grain part have at least substantially the same circumferential length as the groups of teeth on the support part. 28. Device according to claim 14, characterized by an anti-rotation means to prevent relative rotation of the parts. 29. Device according to claim 28, characterized in that the anti-rotation means comprises a stop 20 on one of these parts which engages in the other part. 30. Device according to claim 28, characterized in that the anti-rotation means is activated when the support part is rotated by less than one revolution. 31. Device according to claim 28, characterized in that the anti-rotation means comprises a movable element on one of the parts which is placed in a cavity in the other part. 32. Device according to claim 31, characterized in that the movable part can be moved to uncouple the parts upon relative rotation of the parts without relative axial movement followed by relative axial movement of the support part in the absence of relative rotation. 33. Device according to claim 31, characterized in that the support part comprises a means for disengaging the movable element. 34. Well device according to claim 15, characterized in that the passage of the groups of teeth 40 of the support part between the groups of teeth on the head part 8300568 A - 46 - provides an indication that the teeth have engaged with rotation of the support part. 35. Device as claimed in claim 15, characterized by a sealing assembly for sealing between the head part and the support part, comprising: a plurality of frusto-conical metal rings stacked in series, the frusto-conical tapering of the rings alternating , a ring shoulder mounted on the support member, an operating member movably reciprocated on the support member, the ring shoulder and the operating member having opposite surfaces which engage the end rings of the stack upon sealing engagement, the metal rings, the ring shoulder and the actuating member having an outer diameter less than the diameter of the bore of the head member, an actuating means for exerting an axial force on the actuating member, whereby the actuating member engages with the stack of metal rings and the inner and outer edges of the rings in sealing contact of metal-on-metal l with the support part and the head part moves. 36. Sealing assembly according to claim 35, characterized in that the metal rings have a sufficient radial width for the inner and outer edges of the metal rings to engage and support the support part and the head part deformed to a smaller cone angle. Sealing assembly according to claim 35, 30, characterized in that the metal rings are compressed beyond their tensile limit between the ring shoulder and the operating part. 38. Sealing assembly according to claim 35, 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. Sealing assembly according to claim 38, characterized in that the adjacent metal rings form an annular groove for receiving an elastomeric seal. Sealing assembly according to claim 35, characterized in that a spacer is arranged between adjacent metal rings. 41. Device according to claim 35, characterized in that a torque transmission means engages the operating part to transmit a torque and rotate the operating part, the operating part being screwed onto the supporting part, whereby as the torque is transferred to the operating part in one direction, the actuating member moves down on the support member a sufficient distance to energize the sealing assembly to sealing contact, a hydraulic means being applied to apply hydraulic pressure to the sealing assembly, thereby causing the metal rings of the sealing assembly to be energized to a metal-to-metal sealing contact with the head part and the support part, the actuating part following the operation of the sealing assembly downward on the support part to prevent the sealing assembly from being released upon removal of the hydraulic pressure. 42. Well device for suspending pipes in a well and for supporting a plurality of stacked pipe hangers from which pipes are suspended in the well, characterized by a head part, a support part with a first bearing surface which can engage the lower stacked pipe hanger, wherein the support member is attached to the upper pipe section of a pipe string, teeth being mounted on the head member and the support member for releasably connecting these 30 parts / the teeth having a second bearing surface to support the support member on the head member, the the first and second bearing surfaces each have a sufficient surface area, so that the load on the pipe hangers and the suspended pipes together with the working pressure of the well does not significantly exceed the material tensile limit when the support part and the head part are vertically compressed. 43. Well arrangement according to claim 42, characterized in that the head part has a bore of 40 17-9 / 16 inch for receiving a standard 17½ inch 8300568 * - 48 - / · drill bit for drilling the well bore for the pipe suspended from the bottom stacked pipe hanger. 9 44. Well device according to claim 42, characterized in that the head part and support part are made of material with a tensile limit of at least 5950 bar. 45. Well device according to claim 42, characterized in that the bearing surfaces can support a load greater than 27,000,000 N. 46. Well arrangement according to claim 42, characterized in that the first bearing surface comprises a tapered shoulder on the support part with a taper angle greater than 30 °. 47. Well device according to claim 42, 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. 48. Device for suspending a pipe 20 in a well and for supporting a pipe hanger from which another pipe hangs in the well, characterized by a well head part, a hanger support part telescopically received in the well head part, the hanger support part engaging with thread on the top pipe section of a pipe string to suspend the pipe string in the well, a plurality of circumferentially spaced, pitched threads on the inner circumference of the well head portion and on the outer circumference of the hanger support portion, which threads interlock with rotation of the hanger seat-30 part through less than 360 °, the hanger support part having an upwardly directed conical seat, a packing ring having a lower cylindrical part and an upper annular shoulder flange being provided, the shoulder lens having a downwardly facing surface for engaging the upwardly directed conical seat, whereby the cylindrical part of the grommet has external threads for thread engagement on internal threads on the hanger support member, with a sealant applied to seal between the hanger support member and the packing ring, with another sealant applied 8300568 • * - 49 - to be sealed between the shoulder flange and the well head and where the packing ring has an upper thread surface that can engage the pipe hanger. The device of claim 48, g e-5 characterized by a means for testing the sealant and the other sealant. 50. An apparatus according to claim 48, characterized in that the sealant comprises an upper and lower O-ring contained in the cylindrical portion of the packing ring and the test means comprises a test port extending between the upper and lower O-ring. . The device of claim 48, further characterized by grooves extending longitudinally through the teeth. 52. A method of completing an underwater well, characterized in that (a) a drilling means is placed at an underwater well, (b) a guide tube is installed in the bottom of a body of water with a wellhead, blowout valve system and riser tube attached thereto at a point near the bottom, the riser tube extending upward to the drilling means, (c) a drill string and standard 17½ inch drill bit is lowered through the wellhead and guide tube, ( d) a hole is drilled to suspend a 16 inch casing in the well head and guide tube, (e) a hanger seat with a casing column attached is lowered into the well until the hanger seat is placed in the well head, (f) the hanger seat is rotated less than 360 ° every. to connect hanger seat in the well head, (g) the hanger seat is locked in the well head, (h) a hole is drilled to hang another casing in the well head, (i) a pipe hanger with a casing string is lowered by the riser and in the well head and 40 (j) the pipe hanger is placed on the hanger seat. 8300568