GB2156881A - Subsea wellhead systems - Google Patents

Abstract

An apparatus for supporting one or more hangers 50 suspending pipe within a wellbore 10 comprises a wellhead member 24, a support or seat member 70 telescopingly received within or insertable into the member 24 to engage the hanger(s), and a plurality of spaced no-lead threads or groupings of teeth 66,76 on the inner circumference of the member 24 and the outer circumference of the member 70 for releasably connecting the members together. <IMAGE>

Description

1

SPECIFICATION

Subsea wellhead system Th is invention relates to su bsea well head systems and more particularly, to methods and apparatus for supporting, holding down, and sealing casing hangers within a subsea wellhead.

Increased activity in offshore drilling and comple- tion has caused an increase in working pressures such that it is anticipated that newwells will have a working pressure of as high as 15, 000 psi. To cope with the unique problems associated with underwater drilling and completion at such increased working pressures, new subsea wellhead systems are required. Wells having a working pressure of up to 15,000 psi are presently being drilled off the coast of Canada and in the North Sea in depths of over300 feet. These drilling operations generally include a floating vessel having a heave compensatorfor a riser and drill pipe extending to the blowout preventer and wellhead located at the mud line. The blowout preventerstack is generally mounted on 20 inch pipe with the riser extending to the surface. A quick disconnect is often located on top of the blowout preventerstack. An articulation joint is used to allowforvessel movement. Two major problems arise in 15,000 psi working pressure subsea wellhead systems operating in this environment, namely, a support shoulder in thewellhead housing which will supportthe casing and pressure load, and a sealing means between the casing hangers and wellhead which will withstand and contain the working pressure.

Inthe past, prior art wellhead designs permitted adequate landing support for successive casing hangers. However,with the increase in pressure rating and the landing and supporting of multiple casing strings and tubing strings within the wellhead, a small 100 support shoulder wil I not support the load. Although an obvious answer to the problem would be to merely use a support shoulder large enough to supportthe casing and pressure load, large support shoulders projecting into the flow bore in the wellhead housing 105 for restricted access to the casing belowthe wellhead housing for drilling. In the early days of offshore drilling, 16-3/4 inch bore subsea wellhead systems required u nderreaming. At that time, most floating drilling rigs were outfitted with a 16-3/4 inch blowout preventer system to eliminate thetwo stack (20 inch and 13-5/8 inch) and the two riser system required up until thattime. As wellhead systems moved from 5,000 psi to 10,000 psi working pressure, the 18-3/4 inch, 10,000 psi support shoulderwas developed to carry casing and pressure loads and to provide full access into the casing below the wellhead housing. The second major problem is the sealing means. The sealing means must be capable of withstanding and containing 15,000 psi working pressures. Available energy sources for energizing the sealing means include weight, hydraulic pressure, and torque. Each sealing means requires different amounts of energy to position and energize. Weight is the least desirable GB 2 156 881 A 1 becausethe handling of drill collars providing the weight is difficult and time consuming on the rig floor.

If hydraulic pressure is applied through the drill pipe, there is a need forwireline equipmentto run and recover darts from the hydraulic-toactuated sea[ energization system. If darts are not used, the handling of "wet strings" of drill pipe is very messy and unpopularwith drilling crews. If the seal energization means uses the single trip casing hangertechnique, the cementing fluid can cause problems in the hydraulic system used to energizethe seal. Maintenance is also a problem. Although torque is the most desirable method to energize a seal, there are limitations on the amount of torque which can be transmitted from the surface due to friction losses to riser pipe, the blowout preventer stack, off location, various threads, and the dril I pipe itself.

The subsea well head system of the present invention overcomes the deficiencies of the prior art and includes many other advantageous features. The system is simple, has less than 50 parts and is suitable for H2S service. The system has single trip capability but can still use multiple trip methods. All hangers are interchangea ble with respect to the outer prof He so that they can be run in lower positions. The seal elements are interchangeable and arefully energized to a pressure in excess of the anticipated wellbore pressure. Back-up seals are available. The seals are not pressure de- energized. The hangers can be run without lock downs and the seal elementswill seal even if the hanger lands high.

The housing support seat supports in excess of 6,000,000 lbs. (working pressure plus casing weight or test pressure) without exceeding 150% of material yield in compression. The wellhead will pass a 17-1/2 inch diameter bit. The present invention does not attemptto land on two types of seats at once or on two seats at once. Further, the housing support seat is not sensitive to collecting trash during drilling orto collecting trash during the running of a 13-3/8 inch casing. Further,the housing supportseatcloes not requirea separatetrip nordoes itdrag snap rings down the bore.

The hanger hold down will hold down 2,000,000 lbs. The hanger hold down is positively mechanically retracted when retrieving the casing hanger body and is compatible with single trip operations. The hanger hold down is released for retrieval of the casing hangerwhen the seal element is retrieved. The hanger hold down is compatible with multiple trip operations and permits the running of the hangerwith orwithout the hold down. The sealing means will work even if the hold down is not used. The hanger hold down is reusable and has a minimum number of tolerances to stack up between hold down grooves.

The sealing means of the present invention will reliably sea[ an annular area of approximately 18-1/2 inch outside diameter by 17 inch inside diameter and provide a rubber pressure in excess of 15,000 psi (20,000 psi nominally) when the sealing means is energized and the sealing means sees a pressure from above or below of 15,000 psi. The pressure in excess of The drawing(s) originally filed was (were) informal and the print here reproduced is taken from a later filed formal copy.

2 15,000 psi is retained in the sealing means afterthe running tool is removed. The sealing means is additionally self-energized to hold full pressure where full loading forcewas not applied orwhere full loading force was not retained. The sealing means will not be 70 pressure de-energized. The sealing means provides a relatively long seal area to bridge housing defects andlortrash. Further, the sealing means provides primary metal-to-metal seals and usesthe metal-to metal seals as backups to prevent high pressure 75 extrusion of secondary elastomeric seals. The sealing means of the present invention positively retracts the metal-to-metal seals from the walls priorto retrieving the sealing means. The elastomeric seals of the sealing means are allowed to relax during retrieval of 80 the packoff assembly and is completely retrievable.

The presentsealing means provides a substantial metallic link between the top andthe bottom of the packing seal area to insure thatthe lower ring is retrievable. The design allows forsingle trip opera- 85 tions. There are no intermittent metal parts in the seal area to give irregular rubber pressures. The sealing means provides a minimum numberof seal areas in parallel to minimize leak paths.The sealing means is positively attachedtothe packing elementso that it 90 cannot be washed off byflow during the running operations. The design also allows for multiple trip operations and is interchangeable for all casing hangers within a nominal size.

The meansto load the sealing means reliably 95 provides a forceto energize the sealing meansto a nominal 20,000 psi. It allows full circulation if used in a singletrip. However,the loading means is compatible with eithera singletrip operation or multiple trip operation. Further, it is interchangeable for all casing 100 hangerswithin the wellhead system. The loading meanswill cause the sealing meansto seal even if the casing hanger is set high. Further, it does not release anysignificant amount of thefull pressure load after actuation. The loading means does not require a 105 remote engagement of hold down threads. Further, it has no shear pins. The loading means is reusable and does not have to remotely engage hold down threads on packing nut replacement.

The casing hanger running tool includes a connec- 110 tion between the running tool and casing hanger which will support in excess if 700,000 lbs. of pipe load. The running tool is ableto generate an axial force in excess of 900,000 Ibs. to energizethe sealing means. Further, the running tool is able to tie back into 115 the casing hangerwithout a left hand torque. The running tool can be run on either casing or drill pipe.

Other objects and advantages of the invention will appearfromthefollowfng description.

The present invention relates to a subsea wellhead 120 assembly particularly useful for offshore wells having a working pressure in the range of 15,000 psi. The wellhead assembly generally includes a well head, a housing seatfor supporting the casing and pressure load, a casing hanger for suspending casing within the well, a hoiddown and sealing assemblyfor locking the casing hanger to the wellhead and forsealingthe annulus created bythe casing hanger and wellhead, a running tool for lowering the casing hanger into the wellhead and for initially actuating the hoiddown and GB 2 156 881 A 2 sealing assembly, and other related apparatusfor applying hydraulic pressuretothe holdclown and sealing assemblyfor achieving a compression setof the holdclown and sealing assembly in excess of the working pressure of the well. The wellhead is adapted to receive other casing hangers stacked one on top of another, and to hold down and seal such othercasing hangers within the wellhead.

The wellhead has a through bore of 17-9116 inches to permitthe passage of a standard 17-112 inch drill bit. To provide a bearing surface forsupporting a casing hanger and pressure load within the wellhead, the housing seat is landed and connected to the wellhead. Breech blockteeth are provided on the wellhead and housing seatto permitthe housing seatto be stabbed into the wellhead and rotated less than 360'for completing the connection therebetween. The breech blockteeth include six groupings of six teeth. The teeth are spaced-apart no-lead threads. The bearing surface of the breech blockteeth is greaterthan the bearing surface provided bythe housing seatforthe casing hanger.The bearing surface of the housing seatwill supportthe casing ancitubing load in addition tothe 15,000 psiworking pressure.

Thecasing hangerincludes an annularshoulder having flutesforthe passage of well fluids.A releasable seat ring isthreadedto the casing hanger shoulderto provide afull 3600 circumferential engagementwiththe hangerseatto supportthe casing and tubing weight andthe pressure load.A latch member is disposed abovethe casing hanger shoulder and adapted for expansion into a lockdown groove in the wellhead.

The holdclown and sealing assembly is disposed aroundthe casing hangerand above the latch member and casing hanger shoulder. The hoiddown and sealing assembly includes a rotating member rotatably supporting a stationary member. The stationary member includes an upper actuator portion rotatably mounted on the rotating member, a medial seal portion having a primary metal-to-metal seal and a secondary elastomeric seal for sealing the annulus, and a lower cam portion for actuating the latch member.

The seal portion includes a plurality of frustoconical metal links connected together by connector links so as to form a Z shape. This Zshaped portion is connected to the upper actuator portion and lower cam portion by connector links so as to provide a positive connective link between the upper actuator portion and the lower cam portion. The adjacent metal links form annulargroovesfor housing resilient elastomeric members.

The rotating member is threadingly engaged to the casing hangerwhereby as the rotating member is rotated on the casing hanger,the rotating member moves downwardly causing the stationary memberto also move downwardly within the annulus. Initially, the lowercam portion camsthe latch memberintothe lockdown grooveof thewellheadto lockthe casing hanger within the w& i head. Further rotation ofthe rotating member compresses the medial seal portion of the stationary member. Initially, as the Z portion deforms, the metal links compress the elastomeric members into sealing engagement with the wellhead 3 GB 2 156 881 A 3 and casing hanger. Further compression oftheZ portion causesthe metal linksto bend and deform adjacentthe connector links so asto establish a metal-to-metal seal between thecasing hangerand wellhead.The metal links are made of a ductile material having ayield of lessthan one-half the yield of the material of thewellhead and casing hangersuch thatthe ductile material of the Z portion deformsfilling the peaks and valleysof the imperfections inthe surfaces ofthewellhead and casing hanger.

The running tool for lowering and landing the casing hanger includes a skirt engaging the rotating member of the hoiddown and sealing assemblyfor the transmission of torque thereto, a mandrel con nected to a string of drill pipe, and a sleevetelesco pingly received between the skirt and mandrel. The sleeve includes latches biased into engagementwith the casing hanger bythe mandrel in an upper position.

Afterthe hoiddown and sealing assembly is actuated, the mandrel is moved downwardlyto unbiasthe latches and then lifted upwardlyto engage the sleeve with the skirt such thatthe latches are cammed out of engagementwith the casing hanger. Seals are pro vided between the running tool and the casing hanger.

The hoiddown and sealing assembly is initially actuated by rotation of the running tool via the drill pipe. To further actuate the seal of the holdclown and sealing assembly, blowout preventor rams are actu ated to seal with the drill pipe. Hydraulic pressure is applied belowthe blowout preventerto apply hyd raulic pressureto the running tool and the hoiddown sealing assembly. Asthe seal of the hoiddown and sealing assembly is further compressed, the rotating member of the hoiddown and sealing assembly travels further downwardly on the casing hanger as continued torque is applied to the drill pipe. Once the desired compression set of the seal of the hoiddown and sealing assembly is achieved, the hydraulic pressure is removed and the rotating member of the 105 hoiddown and sealing assembly prevents the seal of the hoiddown and sealing assemblyfrom releasing any of its sealing engagement. It is one object of the present invention to achieve a compression set of the seal of the hoiddown and sealing assemblywhich is 110 greaterthan theworking pressure of thewell.

Upon removing the running tool, a second casing hangerwith casing is landed on top of thefirstcasing hanger. A like hoiddown and sealing assembly, similarly actuated, is disposed between the wellhead 115 and the second casing hangerto hoiddown and seal the second casing hanger. Athird easing hanger is then run into the well on top of the second casing hanger and similarly, a hoiddown and sealing assem bly is actuated to hoiddown and seal the third easing 120 hanger. Thus, the hanger seat supports the three casing hangers and suspended casing and atthe same time, withstands and contains the 15,000 psi working pressure.

For a detailed description of the preferred embodi- 125 ment of the invention, reference will now be made to the accompanying drawings wherein:

Figure 1 is a schematic view of the environment of the present invention; Figures 2A, 213, and 2C are section views of the wellhead, hanger support ring, casing hanger running tool, pack off and hold down assembly, and a schematic of a portion of the blowout preventerforthe underwaterwell of Figure 1; Figure 3 is an exploded view of the breech block housing seat and a portion of the wellhead of Figure 2; Figure 3A is an enlarged elevation view of the key shown in Figure 3; Figure 4 is a section view of the sealing element in the running position and Figure 4A is a section view of the sealing element in the sealing position; and Figures 5A, 513 and 5C are section views of the wellhead with the casing hangers of the 16-inch, 13-3/8 inch, 9-5/8 inch and 7 inch casing strings landed and in the hold down position and in the sealing position.

The present invention is a subsea wellhead system for running, supporting, sealing, holding, and testing a casing hangerwithin a wellhead in an oil or gas well. Although the present invention may be used in a variety of environments, Figure 1 is a diagrammatic illustration of a typical installation of a casing hanger and a casing string of the present invention in a wellhead disposed on the ocean floor of an offshore well.

Referring initiallyto Figure 1,there is shown a well bore 10 drilled into the sea floor 12 below a body of water 14from a drilling vessel 16 floating atthe surface 18 of the water. A base structure or guide base 20, a conductor casing 22, a wellhead 24, a blowout preventer stack 26 with pressure control equipment, and a marine riser 28 are lowered from floating drilling vessel 16 and installed into sea floor 12. Conductor casing 22 maybe driven orjetted into the sea floor 12 until wellhead 24 rests near sea floor 12, or as shown in Figure 1, a borehole 30 maybe drilled forthe insertion of conductor casing 22. Guide base 20 is secured aboutthe upper end of conductor casing 22 on sea floor 12, and conductor casing 22 is anchored within bore hole 30 by a column 32 of cement about a substantial portion of its length. Blowout preventer stack26 is releasably connected through a suitable connection to wellhead 24 disposed on guide base 20 mounted on sea floor 12 and includes one or more blowout preventers such as blowout preventer40. Such blowout preventers include a number of sealing pipe rams, such as pipe rams 34 on blowout preventer 40, adapted to be actuated to and from the blowout preventer housing into and from sealing engagement with a tubular member, such as drill pipe, extending through blowout preventer40, as is well known. Marine riser pipe 28 extends from the top of blowout preventer stack 26 to floating vessel 16.

Blowout preventer stack 26 includes "choke and kill" lines 36,38, respectively, extending to the surface 18. Choke and kill lines are used, for among other things, to test pipe rams 34 of blowout preventer40. In testing rams 34, a test plug is run into the well through riser 28to seal off the well atthe wellhead 24. The rams 34 are activated and closed, and pressure is then applied through kill line 38 with a valve on choke line 36 closed to test pipe rams 34.

Drilling apparatus, including drill pipe with a stan- 4 GB 2 156 881 A 4 dard 17-1/2 inch drill bit, is loweredthrough riser28 and conductorcasing 22to drill a deeper bore hole42 intheocean bottom for surface casing 44.Asurface casing hanger5O, shown in Figure 2Csuspending surfacecasing 44, is loweredthrough conductor casing 22 until surface casing hanger5O lands and is connected to wellhead 24as hereinafter described.

Other interior casing andtubing strings aresubse quently landed and suspended in wellhead 24 as will bedescribed laterwith respectto Figures 5A, 5B and 5C.

Referring nowto Figure 2C, wellhead 24includes a housing 46 having a reduced diameter lower end 48 forming a downwardly facing, inwardly tapering conical shoulder52. Reduced diameter lowerend 48 80 has a reduced tubularportion 54atitsterminus forming another smaller downwardly facing, inwardly tapering conical shoulder 56. Conductorcasing 22 is inch (outside diameter) pipe and isweldedto reducedtubular portion 54 on the bottom of wellhead 85 24. Conductorcasing 22 has.athickness of 1/2 inch and a 19 inch innerdiameter internal bore 62to initially receivethe drill string and bitto drill bore hole42 and laterto receivesurface casing string 44as shown in Figure 1. Wellhead housing 46 includes a bore 60 90 having a diameter of approximately 18-11/16 inches, slightly smallerthan internal bore 62 of conductor casing 22.

Disposed on the interior of wellhead bore 60 are a plurality of stop notches 64, breech blockteeth 66, and 95 four annular grooves (shown in Figure 5B) such as groove 68,spaced along bore60 above breech block teeth 66. Breech blockteeth 66 have approximately a 17-9/16 inch internal diameterto permitthe pass through of the standard 17-1/2 inch drill bit to drill 100 borehole42.

Wellhead 24 includes a removable casing hanger support seat means or breech block housing seat 70 adapted for lowering into bore 60 and connecting to breech block teeth 66. Housing seat 70 includes a solid 105 annulartubular ring 72 having a smooth interior bore 74, exterior breech blockteeth 76 adapted for engage mentwith interior breech blockteeth 66 of wellhead housing 46, an upwardlyfacing, downwardlytapering conical seat orsupport shoulder80 for engaging 110 surface casing hanger5O, and a key assembly 78 for locking housing seat70 within wellhead housing 46.

Bore 74 of solid ring 72 has an internal diameter of 16.060 inches providing conical support shoulder80 with an effective horizontal thickness of approximate- 115 ly 1.3 inches to support casing hanger 50. Housing seat70 has a wall thickness great enough to prevent housing seat 70 from collapsing under a 90,000 psi vertical compressive stress. This is of concern since wellhead 24, because of its size, weight and thickness, 120 is a rigid member as compared to housing seat 70 which is a relatively flexible member.

As shown in Figure 3, housing seat 70 includes a plurality of groupings 82 of segmented teeth 76 with breech block slots or spaces 86therebetween for 125 receiving corresponding groupings 88 of segmented teeth 66 in wel!head housing 46 shown in Figure 2C.

Segmented teeth 66,76 may or may not have leads, but preferably are no-lead teeth. Teeth 66,76 are not designed to interferingly engage upon rotation of seat 130 for connection with wellhead 24. Wellhead teeth 66 are tapered inwardly downward to facilitate the passage of the bit. If threads 66 were square shouldered or of the buttress type, they might engage the bit as it is lowered through wellhead 24 to drill bore 42 for surface casing 44. Shoulderteeth 76 have corresponding tapers to mating ly engage well head teeth 66. Groupings 82,88 each include six rows of segmented teeth approximately 112 inch thick from base to face.

The thread area of the six rows of segmented teeth 66, 76 exceeds the shoulder area of support shoulder 80. A continuous upper annularflange 85 on seat 70 disposed above teeth 76 limits the insertion of tooth groupings 82 into spaces 87. Continuous upper annularflange 85 prevents seat 70 from passing through wellhead 24. Lowermost tooth segment 84 is oversized to prevent a premature rotation of seat 70 within wellhead 24 until seat 70 has landed on annular flange85.

The six rows or groupings 82,88 of segmented teeth 66,76 provide an even number of rows to evenly support and distribute the load. Such design evens out the stresses placed on segmented teeth 66,76. By having six groupings of teeth, segmented teeth 66,76 may be connected by rotating housing seat 70 30', i.e., 180'divided bythe number of groupings. Should segmented teeth 66,76 be longer in length, a greater degree of rotation of housing seat 70 would be required for connection. It is preferable that segmented teeth 66,76 be equal in length so that a maximum amount of contact will be available to supportthe loads.

Segmented teeth 66,76 may merely be circular grooves having slots or spaces 86,87 for connection. Segmented teeth 66,76 have a zero lead angle and are tapered to increasethe thread area so thatthreads 66, 76 will withstand a greater amount of shearstress. The taper of segmented teeth 66,76 is greaterthan 30'and preferably is about 55'whereby the thread area is substantially increased for shear. Thistooth profile attempts to equalize the stresses over all of the segmented teeth 66,76 so thatteeth 66,76 do notyield one at a time.

Teeth 66,76 may be of the buttress type. A square shoulder on teeth 66,76 would catch debris and other junkflowing th rough the well. An added advantage of the breech block connection between wellhead 24 and housing seat 70 is that segmented teeth 76 clean segmented teeth 66 as housing seat 70 is rotated within wellhead 24. Teeth 76 knock any debris off teeth 66 so thatthe debris drops into the breech block slots orspaces86, 87.

Continuous threads have several disadvantages. Threads require multiple rotations for connection and must be backed up until they drop a fraction of an inch priorto the leads of the th reads making initial engagement. Further, threads ride on a point as they are rotated for connection. The breech block connection between housing seat 70 and wel lhead 24 avoids these disadvantages. As housing seat70 is lowered intowellhead 24on an appropriate running tool, the lowermosttooth segment84 on seat70will engage the uppermosttooth segment of tooth segments 66 on wellhead housing 24. Seat 70 is then rotated less than 30'to permit groupings 82 on seat70 to be received GB 2 156 881 A 5 within slot87 between groupings 88on wellhead 24. groupings88 onwellhead 24drop into breech block This drop is substantial, as much as 12 inches, and can slots 86 and teeth groupings 82 on ring 72 are received easily be sensed atthe surface to insure that housing in corresponding slots 87 on wellhead teeth 66.

seat 70 has engaged wellhead 24 and can be rotated Continuous annual flange 85 lands on the uppermost into breech block engagement. Using the breech block 70 tooth segment of segments 66 in wellhead 24.

connection of the present invention provides a clear Housing seat70 is then rotated bythe drill string and indication when housing seat70 isfully engaged with running tool until keys 78 are engaged in stop notches wellhead 24. The breech block connection of the 64to stop rotation. A pressure test may be performed present invention has the added advantage of permit- to be sure housing seat 70 is down. Then shear pins 0 ting housing seat70 to be stabbed into wellhead 24 75 holding housing seat 70 to the running tool are and made up upon a 30'rotation of housing seat 70 to sheared at 104to release and remove the running tool.

accomplish full engagement between housing seat 70 Figure 2C illustrates the landing of surface casing andwellhead24. hanger 50 on breech block housing seat 70 within Referring nowto Figures 2C, 3 and 3A, key assembly wellhead 24. Casing hanger 50 has a generally tubular 78 includes a plurality of outwardly biased dogs 92 80 body 110 which includes a lowerthreaded box 112 each slidingly housed in an outwardly facing cavity 94 threadingly engaging the upperjoint of casing string in every other lowermosttooth segment 84 of solid 44forsuspending string 44within borehole 42, a ring 72. Dog 92 hasflat sides 90, upper and lower thickened upper-section 114 having an outwardly tapered sides 91, and a bore 96 in its inner side to projecting radial annularshoulder 116, and a plurality receive one end of spring 98. Washers 93 are mounted 85 of annular grooves 120 (shown in Figure 2B) in the by screws 95 in cavity 94 on each side of dog 92 inner periphery of body 110 adapted for connection leaving a slotfor dog 92. The other end of spring 98 with a running tool 200, hereinafter described.

engages the bottom of cavity 94to bias dog 92 Referring nowto Figures 2A and 213, threads 118 are outwardly. Stop notch 64 is located beneath all six provided from thetop down along a substantial length groupings 88 sothat dog 92 is positioned on solid ring 90 of the exterior of tubular body 1 10for engagement 72whereby dog 92 will be adjacent a stop notch 64 in with holdclown and sealing assembly 180, hereinafter wellhead housing 46 upon the complete engagement described.

of interior and exteriorteeth 66,76 of wellhead 24 and The cementingoperation for cementing surface housing seat70. Dog 92 will be biased into notch 64 casing string 44 into borehole 42 requires a passage upon the rotation of ring 72 within threads 66 to 95 wayfrom lower annulus 130, between surface casing thereby stop rotation of ring 72. An aperture 102 is string 44 and conductor casing 22, to upper annulus provided through ring 72 and into cavity 94to permit 134, between wellhead 24 and the drill string 236, to the release of dog 92. flowthe returns to the surface. A plurality of upper and In the prior art, the support shoulderforthe surface lowerflutes or circulation ports 122,124 are provided casing hangerwas integral with the wellhead housing 100 through upper section 114to permitfluid flow, such as and was large enough to supportthe casing and forthe cementing operation, around casing hanger 50.

pressure load. However,this prior art integral support Lowerflutes 122 provide fluid passageways through shoulder restricted the bore in the wellhead housing radial annular shoulder 116 and upperf lutes 124 forfull bore access to casing belowthe wellhead providefluid passageways through the upper housing for drilling. To use a sufficiently large integral 105 threaded end of tubular body 110 to pass fluids around shoulderfor 15,000 psi working pressures, the bore of holdclown and sealing assembly 180.

the integral shoulderwould not pass a standard 17-1/2 Threads 126 are provided on the external periphery inch bit. Such subsea wellhead systems required of upper section 114 below annular shoulder 116 to underreaming. threadingly receive and engage threaded shoulder In the present invention, breech block housing seat 110 ring 128 around hanger 50. Shoulder ring 128 has a is an installable support shoulderwhich need not downwardly facing, upwardly tapering conical face be installed in wellhead housing 46 until greater 132to matingly restand engage upwardlyfacing, working pressures are encountered. Housing seat70 downwardly tapering conical support shoulder 80 on is not installed until the drilling operation forsurface breech block housing seat70. Casing hanger 50thus casing 44 is complete, permitting full bore access. 115 lands on housing seat 70 upon engagementof conical Since only nominal working pressures are encoun- face 132 of hangershoulder ring 128 and housing seat tered during the drilling forthe surface casing 44, the support shoulder 80 whereby housing seat 70 must larger support shoulder is not needed. After comple- withstand the resulting casing and pressure load.

tion of the drilling forthe surface casing 44, breech Wells, having a working pressure in the range of block housing seat 70 is installed to handle casing and 120 15,000 psi, create unique loads on the wellhead pressure loads of upto 15,000 psi. Thus, sufficient supports. Not only must the wellhead support the clearance is provided priorto installation of housing weight of the casing hangerswith theirsuspended seat70 to pass a 17-1/2 inch bit. casing and one or moretubing hangerswith their To install breech block housing seat70, housing suspended tubing, butthe wellhead mustwithstand seat70 is connected to a running tool (notshown) by 125 and contain the 15,000 psi working pressure. Thus,the shear pins, a portion of which are shown at 104. The wellhead mustsupport both the casing and tubing running too[ on a drill string then lowers housing seat weight and the pressure load. A 15,000 psi working into bore 60 of wellhead 24 until lowermosttooth pressure wellhead must have sufficient support and segment 84 lands on the uppermosttooth segment of bearing area throughoutthe wellhead design such tooth segments 66. Seat 70 is then rotated until teeth 130 that the load does not substantially exceed the yield 6 GB 2 156 881 A 6 strength in vertical compression of the material of the wellhead supports. Although at lowerworking press ures materials having a 70,000 minimum yield are used, a higherstrength yield material with an 85,000 minimum yield is normally used for 15,000 psi wellheads. Conservatively assuming a 90,000 vertical compressive stress on the wellhead,the wellhead of the present invention will support over6,000,000 lbs.

of load sincethe bearing area is in the range of 65 to 70 square inches. Such a bearing area must be consistent throughoutthe design so thatthe load does not exceed over25% of the material yield strength in vertical compression. The bearing area between the lowermostcasing hanger5O and housing seat70, and between housing seat70 and supporting breech block teeth 66 onwellhead 24 mustbe sufficientto support such loads without substantially exceeding their material yield strength in vertical compression, i.e.

over25% of yield strength. Such a design has been achieved inthewellhead system of the present 85 invention.

To assure sufficient bearing area between casing hanger5O and seat:70, hanger shoulder ring 128 has been threaded onto radial annularshoulder 116 projecting from uppersection 114 of casing hanger body 110. Hangershoulder ring 128 provides a 360' conical face 132 for engaging support shoulder 80 of housing seat:70 thus providing full and complete contact between shoulder 80 and conical face 132.

Without hanger shoulder ring 128, flutes or circulation 95 ports 122through shoulder 116 prevent a 360' bearing area between hanger 50 and housing seat:70. The engagement between support shoulder 80 and conic al face 132 provides an excess bearing area deter mined bythe wellhead internal diameter of 17-9116 100 inches and the internal diameter of housing seat 70 of 16.060 inches. Thus, the bearing area between shoul der8O and face 132 is approximately 70 square inches permitting such bearing area to support in excess of 6,000,000 lbs. in load.

Interiorand exterior breech blockteeth 66,76 of wellhead 24 and housing seat 70 also have been designed to provide sufficient bearing area to support the anticipated load described above. As described previously, breech blockteeth 66,76 include six groupings 82,88 of teeth provided on wellhead 24 and housing seat:70. Each grouping 82,88 includes six teeth 66,76to supportthe load. The bearing area of breech blockteeth 66,76 is greaterthan the bearing area between shoulder8O and conical face 132. The numberof teeth is determined bythe loss of bearing area dueto the six spaces86,87 for receiving corresponding groupings 82.88 during makeup.

Referring again to Figure 2C, radial annular shoul der 116 projecting from uppersection 114 of hanger body 110 has an upwardlyfacing, downwardly and outwardly tapering conical cam surface 136with an annular relief groove 138 extending upwardly at its base. An annularchamber 142 extends from the upper side of groove 138 to an annularvertical sealing surface 140 extending from groove 138to the lower end of threads 118. Radial annular shoulder 116 is positioned below annular lockgroove 68 in wellhead housing 46 after hanger 50 is landedwithin wellhead 24. Cam surface 136 has its lower annular edge 130 terminating just abovethe lowerterminus of groove 68.

Casing hanger 50 includes a latch ring 144 disposed on radial annularshoulder 116. Latch ring 144 may be a split ring which is adapted to be expanded into wellhead groove 68 for engagementwith wellhead housing 46to hold and lock down hanger 50 within wellhead 24. Wellhead groove 68 has a base vertical wall 146 with an upwardlytapered wall and a downward lytapered wall. Latch ring 144 has a base vertical surface 148 with a downwardly tapered surface of the extent of the upwardlytapered wall of groove 68 and an upwardlytapered surface parallel to the downwardlytapered wall of groove 68 whereby upon expansion of latch ring 144, the vertical surface 148 of ring 144 engages the vertical wall 146 of groove 68. Further, latch ring 144 includes a downwardly facing outwardly and downwardly tapering lower camming face 152 cammingly engaging upwardly facing camming surface 136 of radial annular shoulder 116, an inwardly projecting annular ridge 154 received by annular relief groove 138 inthe retracted position, and an upwardly and inwardlyfacing camming head 156 adapted for camming engagement with holddown and sealing assembly 180, hereinafter described. Extending between camming head 156 and annular ridge 154 istapered surface 158 parallel to the wall of chamber 142.

Projecting annular ridge 154 is received within groove 138 of casing hanger 50 to prevent latch ring 144from being pulled out of groove 138 as casing hanger 50 is run into the well. It is necessary during the lowering of casing hanger 50that latch ring 144 pass several narrow diameters such as in blowout preventer40. Blowout preventer40 often includes a rubber doughnut-type seal which does notfully retract thereby requiring casing hanger 50 to pressthrough that rubberseal. If annular ridge 154was not housed in groove 138, latch ring 144 might iatch at such a narrow diameter and drag along the exterior surface. This mightdraw latch ring 144from groove 138 and permit itto slide upwardly around casing hanger 50 until latch ring 144 engages seal means 210. This would not only preventthe actuation of holddown actuator means 212, butwould also preventthe actuation of sealing means 210. Annularchamber 142 provides clearance so thatgroove 138 can receive annular ridge 154. This profile also provides a step which keeps latch ring 144 from having such an upward load as the load is placed on latch ring 144.

Holddown assemblyand sealing 180isshown in Figures 2B and 2C, engaged with running tool 200 and actuated in the holddown position. Holddown and sealing assembly 180 includes a stationary member 184 rotatably mounted on a rotating memberor packing nut 182 by retainer means 186. Packing nut 182 has a ring-like bodywith a lower pin 188 and a castelated upperend 198with upwardly projecting stops202.The inner diameter surface of nut 182 includesthreads 204threadingly engaging the externalthreads 118 of casing hangerbody 110.

Stationary member 184has a ring-like body216and includesa seal means 210forsealing betweenthe internal borewall 61 of wellhead 24 and external sealing surface 140of casing hanger5O,and a 7 holdclown actuator means 212 for actuating latch ring 144 into hoiddown engagement with in groove 68 of wellhead 24. Ring-like body 216 is a continuous and integral metal member and includes an upper drive portion 218, an intermediate Z portion 220, and a lower cam portion 222.

Upper drive portion 218 includes an upper counterbore 190 that rotatably receives lower pin 188 of packing nut 182. Retainer means 186 includes inner and outer races in counterbore 190 and pin 188 housing retainer roller cones or balls 196. Retainer means 186 does not carry any load and is not used for transmittini torque orthrustf rom packing nut 182 to stationary member 184. Bearing means 205 is pro- vided above sealing means 210 and includes bearing rings 206,208 disposed between the bottom of counterbore 190 and the lowerterminal end of pin 188. Bearing rings 206,208 have a low coefficient of friction to permit sliding engagement therebetween upon the actuation of holdclown actuator means 212 and sealing means 210. Thus, bearing means 205 is utilized to transmitthrust from packing nut 182 to stationary member 184. Retainer balls 196 merely rotatively retain stationary member 184 on packing nut182.

Holdclown actuator means 212 includes lower cam portion 222 having a downwardly and outwardly facing cam surface 224 (shown in Figure 2A) adapted for camming engagementwith camming head 156 of latch ring 144, and upper drive portion 218 and intermediate Z portion 220 for transmission of thrust from packing nut 182 to lower cam portion 222.

Sealing means 210 includes Z portion 220 and elastomeric back-up seals 330,332 which will be described in detail with respect to Figure 4 hereinafter, 100 and upper drive portion 218 and lower cam portion 222 for compressing intermediate Z portion 220. Sealing means 210 is a combination primary metal-tometal seal and secondary elastomeric seal. Having a rnetal-to-metal seal be the primary seal has the advantage that it will not tend to deteriorate as does an elastomeric seal.

Holddown and sealing assembly 180 is lowered into the well on casing hanger 50 by a running tool 200.

Running tool 200 includes a mandrel 230, which is the main body of tool 200, a connector body or sleeve 240, a skirt or outer sleeve 250, and an assembly nut 260. Mandrel 230 includes an upper pin end 232 with internal threads 234for connection with the lower- most pipe section of drill pipe 236 extending to the surface 18 and a lower box end 238 also having internal threads. Above box end 238 is located an annular reduced diameter groove portion 242. Another reduced diameter portion 248 is disposed above groove portion 242 forming an annular ridge 252. Below upper pin end 232 and above reduced diameter portion 248 is a third threaded reduced diameter portion 254 (shown in Figure 2A) having a diameter smaller than that of portions 242 and 248.

Connector body orsleeve 240 includes a bore 246 dimensioned to betelescopically received overannu lar ridge 252 and box end 238. Connector body 240 is telescopingly received in the annulusformed by mandrel 230 and skirt 250. Ridge 252 includes annular seal grooves 258,262 housing O-rings264,266, 130 GB 2 156 881 A 7 respectively, for sealing engagementwith the inner diametersurface of bore 246.Thetop end of connector body240 includes an internally directed radial annular flange 268 having a sliding fitwith the surface of reduced diameter portion 248. The lower end of connector body 240 has a reduced diameter portion 270 which is sized to be slidingly received by bore 272 of casing hanger 50. Reduced diameter portion 270 forms downwardly facing annular shoulder 274which engages the upperterminal end 276 of casing hanger 50 upon landing running tool 200, holdclown and sealing assembly 180 on casing hanger5O within wellhead 24. Reduced diameter portion 270 has a plurality of circumferential ly spaced slots orwindows 278which slidingly house segments or dogs 280 having a plurality of teeth 282 adapted to be received bygrooves 120 of casing hanger 50for connection of running tool 200with casing hanger5O. Dogs 280 have an upper projection 284 received within an annular groove 286 around the upper inner periphery of windows 278. Above windows 278 are a plurality of sea[ grooves 288,290 housing O-rings 292,294 for sealingly engaging the seal bore 272 of casing hanger 50. Adjacentto the upper exterior end of connector body 240 is a snap ring groove 296 housing snap ring 298 used in the assembly of running tool 200 as hereinafter described. Dogs 280 collapse back into groove portion 242 after lower box end 238 is moved to the lower position, as shown, uptn the application of torque on too[ 200 to set holdclown and sealing assembly 180.

Skirt or outersleeve 250 includes a generally tubular body having an upper inwardly directed radial portion 300, a medial portion 302, a transition portion 304, and a lower actuator portion 306. Portions 300, "02,304 and 306 are contiguous and have dimensions to telescopically receive the upper terminal end 276 of casing hanger 50, connector body 240 and mandrel 230. Lower actuator portion 306 has a castilated lower end 308 engaging the upper castilated end 198 of packing nut 182 wherebytorque may be transmitted from running too[ 200 to holddown and sealing assembly 180. The inner diameter of actuator portion 306 is suff iciently large to clearthe outside diameter of threads 118 of casing hanger 50.

Medial portion 302 slidingly receives connector body 240. Portion 302 includes an internal annular groove 310 adaptedto receive snap ring 298 mounted on connector body 240 upon disengagement of running tool 200 from holdclown and sealing assembly 180 and casing hanger 50, as hereinafter described. Portion 302 has a plurality of threaded bores 312 extending from its outer periphery to groove 310 whereby bolts (not shown) may be threaded into groove 310 to prevent snap ring 298 from engaging groove 310 during the resetting of running tool 200 on another casing hanger. Snap ring 298 has an upper cam surface 316 for engaging the ends of the bolts. Once connector body 240 is received into the upper portion of the annular area formed by outer sleeve 250 and mandrel 230 whereby snap ring 298 is above annular groove 310, connector body 240 cannot be removed without snap ring 298 engaging groove 310. Thus, to remove connector body 240 upon the resetting of running tool 200, bolts are threaded into 8 GB 2 156 881 A 8 bores312to close groove310 and preventgrooves 310from receiving and engaging snap ring 298.This permits connector body 240 to move downwardly on mandrel 230 until shoulder269 engages projection 252 for connection to anothercasing hanger.

Transition portion 304 adjoins actuator portion 306 and medial portion 302to compensate forthe change in diameters. Flow ports 318 are provided in transition portion 304to permit cement returns to passthrough outersleeve 250 and into annulus 134.

The upper radial portion 300 has its interior annular surface castelated to form a splined connection 320 with mandrel 230 forthe transmission of torque.

Referring nowto Figures 2A and 213, assembly nut 260 has internal threads 324for a threaded connection at322 with threads 235 of reduced diameter portion 254 of mandrel 230. The lowerterminal face of assembly nut 260 bears againstthe upperterminal end of outersleeve 250 to retain outer sleeve 250 on mandrel 230.

In operation,the packing nut 182 is only partially threadedto threads 118 atthetop of casing hanger5O sothat mandrel 230 is mounted in the running position on casing hanger5O. In the running position, annular ridge 252 abuts shoulder269 formed by radial 90 annularflange 268 on connector body 240. The outer tubularsurface of box end 238 is adjacentto and in engagementwith the internal side of dogs 280 wherebyteeth 282 are biased into grooves 120 of casing hanger 50 preventing the disengagement of running tool 200 and casing hanger 50 as they are lowered into the well on drill pipe 236. The running position of running tool 200 is not illustrated in the figures.

Upon landing face 132 of shoulder ring 128 of casing 100 hanger 50 on support shoulder 80 of housing seat 70 in wellhead 24, surface casing 44 is cemented into place within borehole 42. Afterthe cementing opera tion is completed, running tool 200 is rotated and torque is transmitted to holdclown and sealing assem- 105 bly 180 to actuate holdclown and sealing assembly 180 into the holddown position shown in Figures 2B and 2C. Rotation of drill pipe 236 at the surface 18 causes mandrel 230 to rotate which rotates outer sleeve 250 by means of splined connection 320. The torque from110 outer sleeve 250 is then transmitted to packing nut 182 atthe castelated connection of stops 202 of nut 182 and lower end 308 of sleeve 250. Packing nut 182 places an axial load on holddown and sealing assembly 180 causing cam portion 222 of holdclown actuator means 212to move into camming engagementwith camming head 156 of latch ring 144. Such camming expands latch ring 144 into wellhead groove 68 for engagement with wellhead housing 46to hold and lock down casing hanger 50 within wellhead 24 as shown in Figure 2. Sealing means 210 has notyet been actuated to seal between upper annulus 134 and lower annulus 130. Latch ring 144 requires only a predetermined camming load for actuation and therefore has a predetermined contractual tension. Sealing means 210 is designed in cross section to insure that sealing means 210 will not be prematurely compressed upon the actuation and camming of latch ring 144 by holddown actuator means 212. The load required to compress sealing means 210 is substantially greater than that required to expand and actuate latch ring 144. Mandrel 230 moves downwardly with skirt 250 upon the actuation of holdclown and sealing assembly 180. This downward movement of mandrel 230 releases dogs 280.

Fora description of sealing means 210, reference will now be made to Figures 4 and 4Ashowing sealing means 210 in the running and holdclown positions and the sealing position, respectively. Sealing means 210 includes metal Z portion 220, upper and lower elastomeric members 330,332, respectively, and upperdrive portion 218 and lowercam portion 222 for compressing Z portion 220 and elastomeric members 330,332. Metal annularZ portion 220 includes a plurality of annular links 334,336,338 connected together by annular metal connector rings 340,342 and connected to upper drive portion 218 by upper metal connector ring 344 and to lowercam portion 222 by lower metal connector ring 346.

Links 334,336,338, togetherwith connector rings 340,342,344, and 346, provide a positive connective linkfrom bottom to top between lower cam portion 222 and upper drive portion 218. This positive connective link causes links 334,336, and 338to move into a more angled disengaged position from well head 24 and casing hanger 50 upon the retrieval and disengagement of sealing means 210 and actuator means 212from wellhead 24. Furtherthis positive connective link provides a metal connection extend ing from drive portion 218to lower cam portion 222 to permitthe application of a positive upward load on lowercam portion 222 upon disengagement. Were it not for the advantage ofthis retrieval, connector rings 340,342,344, and 346 may not be required.

Connector rings 344,346 adjacent drive portion 218 and cam portion 222, respectively, must have a minimum length to ensure the sealing engagement of annular links 334 and 338. If connector rings 344,346 are too short, there will be insufficient bending to allow links 334 and 338 to contactsurfaces 61 r 140f respectively. Because drive portion 218 and cam portion 222 are massive in size when compared to connector rings 344,346, the comparative massive body of portions 218,222 will not bend so as to permit the sealing engagement of links 334,338. Thus, it is essential thatconnector rings 344,346 permit such bending. Connector rings 340,342,344, and 346 provide a local high stress contact pointthroughout metal Z portion 220.

The metal Z portion 220 is made of a very soft ductile steel such as 316 stainless. Such metal would have a yield of approximately 40,000 psi. This yield is less than half the yield of approximately 85,000 psi of the material forwellhead 24 and hanger 50. Upon sealing engagement of metal Z portion 220, metal Z portion 220 plastically deforms while surface 61 of wellhead 24 and surface 140 of hanger 50 tends to elastically deform. Should there be any imperfection in surfaces 61,140, the ductility of the material of annular Z portion 220 will permit such material to deform orflow into the peaks and valleys of the imperfections of surfaces 61,140 to achieve a high compression metal-to-metal seaL Thus, metal Z portion 220 is adapted for coining into sealing contactwith walls 61 140 of wel [head 24 and casing hanger 50 respectively, 9 GB 2 156 881 A 9 upon actuation.

Upper, intermediate, and lowerannular links334, 336,338 respectively, each have a diamond-shaped cross-section. Sincethe cross-section of links 334, 336,338 is substantially the same, a description of link

336 shall serve as a description of links 334,338.

Annular link 336 includes substantially parallel upper and lower annular sides 348,350 respectively, with upper side 348 facing generally upward and lower side 350 facing generally downward, substantially parallel inner and outer annular sides 352,354 respectively, with outerside 352 facing radially outward and inner side 354facing radially inward, and parallel inner and outer annular sealing contact rims 356,358 respective ly. Annular links 334,338 have comparable upper and lower sides, inner and outersides and inner and outer sealing contact rims.

In the holddown position, the sealing contact rims of links 334,336,338 are deformed substantially parallel with the bore wall 61 of wellhead housing 46 and the 85 outerwall 140 of casing hanger 50. Upper connector ring 344 extends from the lower end 364 of upper drive portion 218 to the upper side 335 of upper link 334 to form an annular channel 366. Metal connector ring 340 extends from the lower side 337 of upper link 334 to 90 upper side 348 of intermediate link 336 to form annular channel 368 and metal connector ring 342 extends from lower side 350 of intermediate link336to the upper side 339 of lower link338to form annular channel 370. Lowerconnector ring 346 extends from 95 the lower side 341 of lower link338 to the upper end 372 of lowercam portion 222 to form annularchannel 374. Annular channels 366,368,370 and 372 between adjacent ridges assist in achieving the bending of Z portion 220 at predetermined locations, namely at 100 connector rings 340,342,344, and 346. Lower end 364 of drive portion 218 is substantially parallel with the upper side 335 of upper I ink 334 and upper end 372 of cam portion 222 is substantially parallel with the lower side 341 of lower link 338. In the running and holdclown positions, the outer and innersealing contact rims have the same diameter as the outer and inner diameters of upper drive portion 218 and lower cam portion 222 respectively.

Upper and lower elastomeric members 330,332 are 110 molded to conform to the shapes of annular grooves 376,378formed by links 334,336,338 and are bonded to links 334,336,338. Upper and lower elastomeric members 330,332 have outer and inner annular vertical sealing surfaces 380,382 respectively, 115 adapted for sealingly engaging bore wall 61 and outer wall 140 in the sealing position. The upper and lower annular ridges formed by sealing surfaces 380,382 are chamfered to permit deformation into sealing position of members 330,332 upon compression. Elastomeric 120 members 330,332 are also chamfered to permit a predetermined deformation of members 330,332 between links 334,336,338. Although the cross sections of elastomeric members 330,332 are sub stantial ly the same, inner elastomeric member 332 125 maybe chamfered or trimmed more than outer elastomeric member 330 to avoid any premature extrusion of members 330, 332 prior to links 334,336, 338 establishing an anti-extrustion seal with bore wall 61 of wellhead 24 and outer sealing surface 140 of casing hanger 50.

It is preferred that sealing means 210 include at least three links. This number is preferred since it provides an anti-extrusion link for each side of elastomeric members 330,332. Also, the three links 334,336,338 achieve a symmetry of design. However, sealing means 210 could include one or more links and might well include a series of links capturing a plurality of elastomeric members. Surfaces 364 and 372 of drive portion 218 and lower cam portion 222, respectively, would preferably have tapers tapering 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 links 334,336, 338 permits the mid-portion of links 334,336,338 to be very rigid. By having a thick mid-portion, the reduced areas at the ends of links 334, 336,338 will become the area which will yield or bend such as that area adjacentto connector rings 340,342,344,346. It is not desirable that links 334,336,338 bend oryiefd attheir mid-portion. However, the particular diamondshaped cross section shown occurs only because of the ease of manufacture of that shape. Links 334,336 and 338 could have a continuous convex or ellipsoidal shape. This shape might be termed frusto- conoidic. This provides a protuberant center portion. If the cross section of links 334,336,338were of the same thickness, links 334,336,338 mighttend to bend or bow attheir mid-section. Although it is preferred to have a thickened center portion for links 334,336,338 to control the point of bending atthe rimsfor a predetermined plastic deformation and to insure there is no distortion atthe center of links 334,336,338, links 334,336,338 may befrustoconical metal rings with a cross section of even thickness ratherthan frustoconoidic rings.

Referring nowto Figures 4 and 4A, Figure 4A illustrates sealing means 210 in the sealing position. Sealing means 210 is compressed as holddownactuator means 212 reaches the limit of its travel against latch ring 144 and packing nut 182 continues its downward movement on threads 118 of casing hanger 50 as shown in Figures 2B and 2C.

Metal-to-metal sealing means 210 is series actuated from bottom to top. In otherwords, the lowest annular link 338 bends and deforms first upon compression of sealing means 210 and is thefirst linkto initiate sealing contactwith surface 61 and surface 140. This series actuation is preferred to limitthe drag of upper annular links 334,336 down surfaces 61,140 upon actuation if the upper links 334,336 were to make sealing engagement priorto lower link 338. It is preferred that there be a balanced force applied to upper annular link 334.

Elastomeric members 330,332 providethe initial seal. Elastomeric seals 330,332 engage surfaces 61, 140 priorto the rims of annular links 334,336, 338 contacting surfaces 61, 140. No extrusion of elastomericseals 330,332 is to occur pastthe rims upon the initial compression set of a fewthousand psi, i.e., 3,000 psi, of sealing means 210. Links 334,336,338 provide a backup for members 330 and 332, an anti-extrusion means forsuch members and are a retainerfor such members. Therefore, it is desired that the rims of links 334,336,338 engage surfaces 61,140 priorto the elastomeric members 330 and 332 extruding past the adjacent rims. It is undesirable for such extrusion pastthe rims to occur priorto the sealing contact of the rims since any elastomeric material between the rims and surfaces 60,140 may be detrimental to the sealing engagement of links 334, 336,338. Thus, as shown and described, the volume of elastomeric material in members 330 and 332 has been calculated and predetermined so thatthe rims contactsurfaces 60,141 priorto any extrusion of 75 members330,332.

Links 334,336,338 are designed to be thin enough to deform into sealing engagement upon a compression set of a fewthousand psi. Connector rings 340,342, 346form stress points orweak areas around annularZ 80 portion 220 locating the bending of Z portion 220 at predetermined pointsto causethe innerand outer rims of Z Portion 220to properly sealing ly engage borewall 61 and outerwall 140. Upon actuation,the rims coin onto borewall 61 and outerwall 140toform a metal-to-metal seal between wellhead 24and casing hanger 50 thereby sealing upperannulus 134from lowerannulus 130 ofthewell. Sealing means210 is designedto ensure that there is nofluid channel or leak path between surfaces 61 and 140.

Inthesealing position lowerlink338 bends at connectorring 346 causing the outer side 343 of lower link338to move downwardlyand engage upperend 372of lowercarn portion 222.Thetaperof surface372 of lower cam portion 222 provides an initial starting deformation angle for lower annular link 338. Surface 372 also ensuresthat link 338will not become horizontal so as to preveritthe disengagement of link 338 upon the removal of sealing means 210. Asthe lower end 364 of drive portion 218 moves downward ly, upper link 334 bends at connector ring 344 causing the inner side 333 of upper link 334to engage lower end 364 as lower end 364 compressors Z portion 220.

Intermediate link 336 moves from its angled position to a more horizontal position. Elastomeric members 330,332 are compressed between links 334,336,338 and sealingly engage bore wall 61 and outerwall 140.

The inner rims of links 334,336,338 make annular sealing contactswith outerwall 140 of casing hanger 50 at380,382 and 384 and the outer rims of links 334, 336,338 make annular sealing contactwith bore wall 61 of wellhead 24 at386,388, and 390. The seal means 210thus achieves a six point annular metal-to-metal sealing contact. The sealing contact of the inner and outer rims causes links 334,336,338to become antiextrusion rings for elastomeric members 330,332.

Elastomeric members 330,332 serve as backup seals to the metal seals.

As links 334,336,338 movefrom their angled position to a more horizontal position upon actuation, 120 each end or each inner and outer rim of links 334,336, 338 move into engagement with bore walls 61 and 140. It is not intended that links 334,336,338 become horizontal. It is essential thatthe inner and outer rims of links 334,336, and 338 become biased between 125 bore wall 61 of wellhead 24 and outerwal 1140 of casing hanger 50. The inner and outer rims of each link reactfrom the bearing load of the other. For example, as inner rim 356 of link 336 bears against casing hanger wall 140, this contact places a reaction load on 130 GB 2 156 881 A 10 outer rim 358 moving outer rim 358 toward wellhead bore wall 61. If each link did not have an opposing rim, the link would continue to move downwardly until its side engaged an adjacent link ratherthan move into sealing engagementwith eitherwall 61 or 140. This bearing againstthe inner and outer rims necessitates the prevention of any buckling or bending in the mid-portion of the link. Hence, the diamond-shaped cross section requiresthatthe mid-portion of the link be rigid so that it cannot buckle or relieve itself. Further, if links 334,336,338were permitted to become horizontal, thetolerances between the inside diameter of wellhead 24 and the outside diameter of casing hanger 50 would become critical. Also, where links 334,336,338 are not horizontal but at an angle, it is easierto disengage Z portion 220 upon extraction of sealing means 210. Surface 364 of drive portion 218 and surface 372 of lowercam portion 222 aretapered to prevent links 334 and 338 respectively, from becoming horizontal.

Itshould be understood that elastomeric seals 330, 332 may notbe required where the rimsof links334, 336,338 sufficiently engage surfaces 66ofwellhead 24 and 140 of casing hanger50to permit hydraulic pressureto beapplied in annulus 134.Thus, members 330 and 332 may be eliminated in certain applications wherethere would be a void between links 334,336 and 338. Also, it should be understood that members 330 and 332 may be replaced by a spacerwhich would permit a predetermined amountof collapse or deformation of links 334,336, 338. As disclosed in the present embodiment, elastomeric members 330 and 332 become such a spacer means. Also, the present invention is not limited to an elastomeric material.

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

Itshould also be understood that should a metal-tometal seal not be desired, that channels 368,370 and 374 might be used to carry elastomeric material to surfaces 61 and 140 to provide a primary elastomeric seal ratherthan a primary metal-to-metal sea[ as described in the preferred embodiment. Should the elastomeric seals 330,332 bethe primary seals, annular links 334,336,338 becomethe primary backup for elastomeric seals 330,332. These links would become energized backup rings for members 330,332. In such a case, the backup seals would not drag down into position.

The present invention is designed for 15,000 psi working pressures and therefore it is the objective of the present invention to achieve a 20, 000 psi compression set on seal means 210 whereby seal means 210 is preenergized in excess of the anticipated working pressure.

In achieving a 20,000 psi compression set, sealing means 210 is actuated by a combination of torque and 11 GB 2 156 881 A 11 hydraulic pressure. Initially, an initialtorque of appro ximately 10,000ft.-lbs. isappliedto drill pipe 236 atthe surface 18. Tongs are used to rotate drill pipe236so as to transmit the torque to running too[ 200 and then thrustto seal means 210. Particularly, drill pipe 236 70 rotates mandrel 230which in turn rotates outersleeve 250 by meansof spline connection 320. Cutersleeve 250 drives packing nut 182 by means of the castellated connection of lugs 198,308. Packing nut 182 bears against drive portion 28 bytransmitting thrust 75 through bearing means 205. Since holddown actuator means 212 has previously reachedthe limit of its downward travel against latch ring 144 in moving to tne holddown position, seal means 210 and specifical ly, Z portion 220 are compressed between drive 80 portion 218 and lowercam portion 222. This torque applies an axial force of approximately 150,000 lbs.

As Z portion 220 is compressed between drive portion 218 and lower cam portion 222, elastomeric members 330,332 become compressed between links 85 334,336,338 as links 334,336,338 move into a more horizontal position. As such compression occurs, elastomeric members 330,332 begin to completelyfill the grooves formed between links 334,336,338 housing elastomeric members 330,332. The amount 90 of elastomeric material of elastomeric members 330, 332 is predetermined such that as links 334,336,338 move into a more horizontal position, links 334,336, 338 achieve sufficient contact with bore wall 61 of wellhead 24 and outer bore wall 140 of casing hanger 95 to function as metal anti-extrusion means for preventing the extrusion of elastomeric seals 330,332.

Particularly, the inside annular contactareas 382,384 preventthe extrusion of inside elastomeric member 332 and annular contact areas 386,388 prevent the 100 axtrusion of outside elastomeric member 330. Thus, an initia! anti-extrusion seal is achieved by links 334, 336,31', before elastomeric members 330,332 can extrude past their arijacent annular sealing contact areas. It Is essential that elastomeric members 331).

33 2 have the right volume of elastomeric material and the proper configuration so that upon compression of sealing means 210, metal anti-extrusion contact is achieved before the extrusion of elastomeric mem bers 330,332 past contact areas 382,384,386, and 388. 110 The particular objective of the initial torque isto set elastomeric back-up seals 330,332 and it is not to establish a metal-to-metal seal between surfaces 61, of wellhead 24 and casing hanger 50 respectively.

The initial torque is unable to completely actuate the metal-to-metal seal means 210 because of friction losses in the riser pipe, the blowout preventer stack, the drill pipe itself, and more particularly, because of variousthread loads such as atthreads 118. Such friction losses limitthe compression load which may 120 be applied to sealing means 210 by drill pipe 236.

To achievethe desired compression set of sealing means 210, hydraulic pressure is combined with the torqueto setthe metal-to-metal seals of sealing means 210. Referring nowto Figures 2A and 213, blowout preventer40 is shown schematically and includes rams 34with kill line 38 communicating with annulus 134 below blowout preventer rams 34.

Convention locates kill line 38 belowthe lowermost lowermost line in blowout preventer40, hydraulic pressure would be applied through choke line 36.

In applying pressure through kill line 38 and into annulus 134, it is necessaryto seal off annulus 134. Note in Figure 2Athat kill line 38 is shown in phase with rams 34, but in actuality is manufactured 905 out of phase. In doing so, pipe rams 34 are closed to seal around drill pipe 236, O-ring seals 264,266 seal between mandrel 230 and sleeve 240, O-ring seals 292,294seal between sleeve 240 and the interior surface 272 of hanger 50 and as discussed above, sealing means 210 provide the initial seal across annulus 134. Thus, hydraulic pressure may be applied through kill line 38 and into annulus 134.

Because of the corkscrew effect caused by the application of torqueto a drill string such as drill pipe 236, 10,000ft-lbs of torque is generally considered to bethe mosttorquethat can betransmitted through a drill pipe string in an underwater situation. In the present invention, a 10,000ftlb torque on drill pipe 236will establish a seal across annulus 134which would withstand a fewthousand psi of hydraulic pressure. This relatively low pressure seal would then permitthe pressurization of annulus 134to further compress sealing means 210 which in turn increases the sealing engagement in annulus 134to withstand additional hydraulic pressure. Metal annularZ portion 220with annular links 334,336,338, is designed so thatannular rings 334,336,338 arethin enough to establish a metal-tometal seal in cooperation with elastomeric seals 330,332 to withstand a hydraulic pressure of a fewthousand psi upon the application of a 10,000 ft-lb torque.

In applying pressureon seal means210,une effective pressure areas are the diameter of running tool sea[ 264 less the diameter of drill pipe-236and in addition thereto, the annular seal area of sealing means210. Since the annular sea[ area isfixedfora particular sized wellhead and casing hanger, the principal variable in determining the pfe,2sure setting force is the difference in pressure area between the running too[ seal 264 and drill pipe 236. Thus, this difference may be varied to permit a predetermined compression setting force on sealing means 210. The difference in diameter mayvary, for example, from between 5 inches and 10 inches.

The particularfunction of the hydraulic pressure is to provide an axial force capable of inducing 20,000 psi into the sealing means 210 without exceeding the pressure design limits of the apparatus in the wellhead system. The function of the torque on nut 182 after hydraulic pressure is applied is to cause nut 182 to followthe travel of sealing means 210 as it moves down underforce and prevent its relaxing when the hydraulicforce is relieved. It is essential that a high torque, i.e. 10,000 ft-lbs, be maintained in drill pipe 236 so that packing nut 182 follows seal means 210 since otherwise nut 182 might prevent the downward movement of sealing means 210. This procedure is repeated by gradually and continuously increasing the hydraulic pressure until packing nut 182 has been rotated a sufficient number of rotations to insure that a 20,000 psi compression set has been achieved by sealing means 210.

ram. Should the choke line 36, for some reason, be the 130 Running tool 200 is a combination tool for applying 12 GB 2 156 881 A 12 torqueto hoiddown and sealing assembly 180 andfor assisting in the application of hydraulic pressure to hoiddown andsealing assembly 18O.The rotation of drill pipe 236 for the transmission oftorquevia runningtool 200to hoiddown and sealing means 180 permitsan initial sealing engagementof sealing means210 in annulus 134 between wellhead 24and hanger 50 whereby hydraulic pressure maythen be applied to annulus 134to further set sealing means 21O.As hydraulic pressure is gradually and con tinuously increased in annulus 134through kill line38, sealing means210 is further compressed into a greaterseaiing engagement against surface 61 of wellhead 24 and surface 140of hanger50. Asthis sealing engagement increases, sealing means 210 will 80 seal against an even greater annulus pressure. Thus, pressurethrough kill line 38 may be gradually increased until sealing means 210 has a compression setof approximately 20,000 psi. The hydraulic press ure applied through kill line 38 and annulus 134does not exceed the design limits of the system. All systems have a standard working pressurewhich an operator may not exceed. The system of the present invention is designed for 15,000 psi working pressures andthus the hydraulic pressure in annulus 134tofully actuate sealing means 210 cannot exceed 15,000 psi although a 20,000 psi compression set is desired.The pressure invention achieves a 20,000 psi compression set of sealing means 210 without applying a hydraulic pressure exceeding 15,000 psi.

As hydraulic pressure is gradually increased in annulus 134to achieve a 20,000 psi compression set on sealing means 210, packing nut 182, dueto the continuous application of the 1 0,00Oft-1b torque on drill pipe 236 which is transmitted to skirt 250, follows 100 sealing means 210 downwardly in annulus 134 on threads 204. Upon the release of the hydraulic pressure through kill line 38 and annulus 134, packing nut 182 prevents the release of the 20,000 psi compression set on sealing means 210 due to the engagement of threads 204 with casing hanger 50.

It is essential that elastomeric seals 330,332 are energized into sealing engagement afterthe applica tion of the initial torque by drill pipe 236. Unless elastomeric members 330,332 are engaged, the 110 application of hydraulic pressure through kill line 38 will be lost past sealing means 210 into lower annulus 130. However, the seal of elastomeric members 330, 332 need only be sufficient to seal against an incremental amount of hydraulic pressure through kill 115 line 38 such as 500 psi. Afterthe initial seal is achieved, the application of increasing amounts of hydraulic pressurewill further compress Z portion 220 and elastomeric members 330,332 to increase the metal- to-m etal and elastomeric sealing contact with wal Is 120 61,140. Such increased sealing contactwill permitthe continued increase in hydraulic pressurethrough kill line 38forthe further actuation of sealing means 210.

Theseal actuation means just described is a simplification of prior art actuator arrangements. Prior 125 art actuators pressure down through drill pipe to actuate an internal porting piston system. A dart seals - off the end of the drill pipe bore forthe application of pressure through the piston system which in turn applies pressure to the seal. Although such a prior art 130 actuator system could be adapted to the present invention, the arrangement of the present invention has substantial advantages overthe prior art.

It maybe necessary to increase the initial torque applied to drill string 236 after blowout preventer rams 34 have been closed. Although the rubber contact of rams 34 with drill pipe 236 does not create the friction loss as would a metal-to-metal contact, some additional friction loss will occur. Thus, additional torque, if possible, maybe applied to drill string 236 above the initial torque to overcome such friction loss. However, drill pipe 236will rotate with rams 34 in the closed position. The annulus between the riser and drill pipe 236 contains well fluids which will cause well fluids to be disposed between pipe rams 34 and drill pipe 236 upon closure of blowout preventer40. Thus, it is believed thatthe 1 0,00Oft-1b torque will not be substantially reduced. If, due to the particuiarapplication,the friction between pipe rams 34 and drill pipe 236 must be reduced, a special pipe joint, notshown, may be series connected in drill pipe 236 whereby pipe rams 34 engage a stationary tubular member having a rotating member passing therethrough to transmit torque past rams 34. Such a special pipejointwould include rotating seals between the stationary member and rotating inner memberto preventthe passage of fluid.

Referring nowto Figures 5A, 5B, and 5C, there is shown the complete assembly of wellhead 24 with 16 inch casing hanger 420,13-318 inch casing hanger50, 9-518inchcasing hanger400,and7 inch casing hanger 410. Casing hanger50isshown in Figure5Binthe hoiddown and sealing position described in Figures 1-4 with hoiddown and sealing assembly 180 actuated in the hoiddown and sealing position. 9-518 inch casing hanger400 is shown supported at402 on top of casing hanger 50. Casing hanger400 also includes a hoiddown and sealing assembly 404comparableto assembly 180 of casing hanger 50.7 inch casing hanger 410 is shown supported at 412 on top of 9-518 inch casing hanger 400. Casing hanger41 0 includes a hoiddown and sealing assembly 414 comparable to that of assembly 180. Figures 5A and 5B show the hoiddown grooves of wellhead 24, namely holddown groove 68forcasing hanger 50, hoiddown groove 406 for casing hanger400, and hoiddown groove 416 for casing hanger 410.

Casing hangers 400 and 410 do not require a shoulder ring such as shoulder ring 128forcasing hanger 50. Since casing hangers 400,410 support a smaller load, the amount of contact support area required for casing hanger 50 is not needed for casing hangers 400,410. Hanger 50 requires a 100 percent contact area which is not required for hangers 400, 410. Further, the shoulders on hangers 400,410 are square and shoulder out evenly on top of the supporting hanger.

Figure 5C discloses an alternative embodimentfor removable casing hangersupport seat meansor breech block housing seat70 shown in Figure 2C. Referring nowto Figure 5C, a modified breech block housing seat420 is shown adaptedfor lowering into bore 60 and connecting to breech blockteeth 66 of wellhead 24.

In certain areasthere areformations belowthe 20 13 GB 2 156 881 A 13 inch casing which cannottakethe pressureofthe weightofthe mud used to contain the bottom hole pressure.To preventthe rupture of this formation by theweightofthe mud, it becomes necessary to run a 16 inch casing string down through that formation before drilling the boreforthe 13-318inch casing.The modified breech blockhousing seat 420 suspends the 16 inch casing. Thus, breech block housing seat 420 doubles both as a support shoulderfor casing hanger 50 and as a casing hangerforthe 16 inch casing 422.

Housing seat420 includes a solid annuiartubular ring 424 and a packoff ring 426. Solid annulartubuiar ring 424 includes exterior breech blockteeth 428 substantially the same as breech blockteeth 76 described with respectto housing seat 70. Ring 424 also has an upwardlyfacing and tapering conical seat or support shoulder430 adapted for engagement with packoff ring 426. Ring 424 also includes a plurality of keys 432, substantiallythe same as keys 92 shown in Figure 2C, for locking housing seat 420 within wellhead housing 46. Ring 424 is provided with a box end 434forthreaded engagementtothe upper pipe section of 16 inch casing string 422.

The upper portion of ring 424 includes a counter bore 438 for receiving the pin end 440 of packing ring 90 426. Packing ring 426 includes external threads for threaded engagementwith the internal threads in counterbore 438 of ring 424forthreaded connection at 442. Packing ring 426 includes an upwardly facing support shoulder450 for engagementwith the downwardly facing shoulder 132 of casing hanger 50.

0-ring seals 444 and 446 are housed in annular 0-ring grooves around the upper end of packing ring 426 for sealing engagementwith bore wall 61 of wellhead 24.

Packing ring 426 also includes C-rings 452,454 housed in annular 0-ring grooves above thread 442 on pin 440 forsealing engagementwith the wall of counterbore 438 of ring 424. Atest port456 is provided between 0-rings 452,454testing the packoff ring 426.

Since the 16 inch casing string 422 must be cemented, housing seat 420 has flutes or passage ways 435 shown in dotted lines on Figure 5C.

Passageways 435 include the natural flow-by of the breech block slots, such as slots 86,87 of housing seat 70 and wellhead 24 shown in Figure 3, and a series of 110 circumferentially spaced slots through continuous annularflange 85 aligned above breechblock slots 86, 87. The slots of flange 85 are more narrow than breech block slots 86,87 to prevent seat 420 from passing through wellhead 24. Packing ring 426 is provided, 115 afterthe cementing,to packoff annulus 134. To test packing ring 426,the rams of the blowout preventer are closed and the running tool is sealed beiowthetest port456 and annulus 134 is pressurized. If there is a leak between wellhead housing 46 and packing ring 426 orthe packing ring and counterbore 438, itwill be impossibleto pressure up annulus 134. Also there will be an increased volume of hydrauiicfiow into annulus 134from kill line 38. It is not necessarythat packing ring 426 establish a high pressure seal since atthis 125 stage of the completion of theweil, most pressures will be in the range of lessthan 5,000 psi.

Itshould be understood that one varying embodi mentwould include making housing seat70 and casing hanger 50 one piece whereby seat 70 and hanger 50 could be lowered and disposed in wellhead 24 on one trip into the well. Hanger 50, for example, could include breech block teeth for direct engagement with wellhead breech block teeth 66.

Another varying embodiment would include extending the longitudinal length of the tubular ring 424 of housing seat 420 whereby sealing means 210 and/or actuator holdclown means 212 could be disposed directly on housing seat 420 and between seat 420 and wellhead 24for sealing and/or holdclown engagementwith wellhead 24. In such a case, packing ring 426would no longer be required.

Because manyvarying and different embodiments may be madewithin the scope of the inventor's concepttaught herein and because many modifications may be made in the embodiments herein detailed in accordance with the descriptive requirements of the law, it should be understood thatthe details herein are to be interpreted as illustrative and

Claims (44)

not in a limiting sense. Thus, itshould be understood thatthe invention is not restricted to the illustrated and described embodiment, but can be modified within the scope of the following claims. CLAIMS

1. A seat for supporting a plurality of pipe hangers within a wellhead which suspend pipe within a well, comprising:

a tubular body received within the wellhead; connection means disposed on said tubular body for releasably connecting said tubular bodyto the wellhead;and shoulder means on said tubular body adapted for engagingly supporting the lowermost pipe hanger.

2. The seat as defined by claim 1 wherein said shoulder means includes a bearing area capable of supporting the load of the pipe hangers and pipe suspended within the wellhead and a 15,000 psi working pressure.

3. The seat as defined by claim 1 wherein said shoulder means includes a bearing area capable of supporting the load of the pipe hangers and suspencled pipe togetherwith the working pressure of the well without substantially exceeding the material yield strength in vertical compression of said tubular body.

4. The seat as defined by claim 1 wherein said shoulder means includes a bearing area capable of supporting a vertical compressive load in excess of six million pounds.

5. The seat as defined by claim 1 wherein said shoulder means includes an annular support shoulder having an effective horizontal thickness of at least 1.3 inches.

6. The seat as defined by claim 1 wherein said shoulder means includes a tapered annular shoulder having a taper angle greater than 30'.

7. The seat as defined by claim land further including lock means for locking said tubular body within the wellhead.

8. The seat as defined by claim land including means for releasably connecting a running too[ to said tubular body.

9. The seat as defined by claim 1 wherein said connection means includes threads on each of said head and support members for threaded engagement 14 of said members upon rotation of said support member.

10. The seat as defined by claim 1 wherein said connection means is actuated upon a 30' rotation of said tubular body.

11. The seat as defined by claim 1 wherein said connection means includes breech blockteeth.

12. The seat as defined by claim 1 wherein said connection means includes teeth having a profile equalizing the stresses overall of said teeth.

13. An apparatus for supporting a hanger sus pending pipe within a boreho[e, comprising:

a head member; a support membertelescopically received within said head member and adapted to engage the hanger; 80 a plurality of circumferentially spaced-apart no-iead threads on the inner circumference of said head member and on the outer circumference of said supportmember; the threads on each being in alignment with the 85 spaces between the threads on the other member, said threads being engaged with each otherto prevent said members from moving axially apart upon the application of an axial force thereon; wherebysaid support member maybe engaged 90 with said head member and provide support means for supporting the hanger and pipe with the borehole.

14. An apparatus for supporting a pipe hanger suspending pipe within a well, comprising:

a head member; a support member adapted to engage the pipe hanger; said support member being insertable into said head member; tooth means provided on each of said head and support members for releasably connecting said members together on said support member being rotated; said tooth means comprising a plurality of spaced groupings of teeth, said groupings of said support member being adapted to pass intermediate said groupings of said head member during insertion of said support member into said head member.

15. The apparatus as defined by claim 14wherein said teeth are fully engaged upon rotation of said support memberless than one revolution.

16. The apparatus as defined by claim 14 wherein said teeth are tapered with a zero lead angle for increasing the shear area of said teeth.

17. The apparatus as defined by claim 14 wherein said teeth on said support member do not interferingiy engage said teeth on said head member.

18. The apparatus as defined by claim 14 wherein said teeth have a nonsquare shoulder profile for preventing the accumulatiom of well debris on said teeth.

19. The apparatus as defined by claim 14wherein said groupings of teeth include tooth segments whereby upon rotation into engagement, the rotating tooth segments of said support member clean said tooth segments on said head member.

20. The apparatus as defined by claim 14 wherein said teeth have a tooth profile for equalizing the stresses overall of said teeth.

21. The apparatus as defined by claim 14 wherein 130 GB 2 156 881 A 14 saidteeth all have an equal length,the numberof groupings on said head memberequalthe numberof groupings on said support member, and each of said members has an even number of said groupings, whereby upon engagement, the stresses and loads are evenly distributed between the teeth.

22. The apparatus as defined by claim 14wherein each of said members include six groupings and six spaces.

23. The apparatus as defined by claim 14wherein said groupings each includes six rows of teeth.

24. The apparatus as defined by claim 14 and including a tooth on said support member having an axial width greaterthan the other support member teeth for preventing a premature threaded engagement between said members.

25. The apparatus as defined by claim 14 and including telescoped unthreaded areas of cylindrical configuration on each of said members.

26. The apparatus as defined by claim 14 wherein said groups of teeth on said head member have substantially the same circumferential extent as said groups of teeth on said support member.

27. The apparatus as defined by claim 14 and including antirotation meansfor preventing relative rotation of said members.

28. The apparatus as defined by claim 27 wherein said antirotation means includes a stop on one of said members in engagementwith the other said member.

29. The apparatus as defined by claim 27 wherein said antirotation means is effected upon rotation of said support member less than one revolution.

30. The apparatus as defined by claim 27 wherein said antirotation means includes a moveable element on one of said members positioned within a cavity in the other said member.

31. The apparatus as defined by claim 30 wherein said moveable element may be moved to allow disengagement of said members by relative rotation of said members without relative axial movement, followed by relative axial movement of said support member awayfrom said head memeber in the absence of relative rotation.

32. The apparatus as defined by claim 31 wherein said support member includes means for moving said moveable element into disengagement.

33. The well apparatus of claim 14wherein the passage of said groupings of teeth on said support member intermediate said groupings of teeth on said head member provide indication that said tooth means is engaged upon rotation of said support member.

34. AweH apparatus for supporting a plurality of stacked pipe hangers suspending pipe within a wellbore, comprising:

a head member; a support member having afirst bearing area adapted to engage the lowermost stacked pipe hanger; tooth means provided on each of said head and support members for releasably connecting said members together, said tooth means having a second bearing area for supporting said support member on said head member; said first and second bearing areas each having sufficient area whereby the load of the pipe hangers and suspended pipe together with the working pressure of the well does not substantially exceed the material yield strength in vertical compression of said support and head members.

35. The well apparatus as defined by claim 34 wherein said head member has a minimum bore of 17-9116 inches adapted for receiving a standard 17-112 inch drill bitto drill the wellboreforthe pipe suspended bythe lowermost stacked pipe hanger. 75

36. The well apparatus of claim 34wherein said head and support member are made of a high strength yield material having a 85,000 psi minimum yield.

37. The well apparatus of claim 34 wherein said bearing areas are capable of supporting a load in excess of six million pounds.

38. The well apparatus as defined by claim 34 wherein said first bearing area includes a tapered annular shoulder on said support member having a taper angle greater than 300.

39. The well apparatus as defined by claim 34 wherein said tooth means includes a plurality of segmented circular grooves on each of said members, said segmented grooves of said support member being adapted to pass intermediate said segmented 90 grooves of said head member.

40. Aseal assembly disposed on a tubular mem berslidingly received within a bore of another memberfor providing a metal-to-metal seal between the tubular member and the internal wall of the bore, 95 comprising:

a plurality of frustoconical-shaped metal rings stacked in series, each ring alternating in frustoconical taper; an annular shoulder mounted on the tubular 100 member; an actuator member reciprocally mounted on the tubular member, said annular shoulder and said actuator member having correlative, oppositely dis posed surfaces engaging the end rings of said stack upon sealing engagement; said metal rings, annular shoulder, and actuator member having an outer diameter smaller than the diameter of the bore; actuation means for applying an axial force on said actuator member causing said actuator memberto engage said stack of metal rings and move the inner and outer edges of said rings into metal-to-metal sealing engagementwith the tubular member and the internal wall of the bore.

41. The seal assembly as defined by claim 25 wherein said metal rings have a sufficient radial width forthe inner and outer edges of said metal ringsto interferingly and sealingly engage the tubular mem- berandthe internal wall of the bore andto deform to a 120 smaller cone angle.

42. The seal assembly as defined by claim 25 wherein said metal rings are compressed beyond their yield point between said annular shoulder and 60 actuatormember.

43. Awell apparatus for suspending pipe within a borehole, as claimed in claim 28 substantially as described with reference to the accompanying drawings.

Printed in the United Kingdom for Her Majesty's Stationery Office, 8818935, 10185, 18996. Published at the Patent Office, 25 Southampton Buildings, London WC2A lAY, from which copies may be obtained.

43. The seal assembly as defined by claim 40 and including annular links between said metal rings, annular shoulder, and actuator memberforming a positive connective link between said annular mem65 ber and said actuator member.

GB 2 156 881 A 15

44. The seal assembly as defined by claim 41 wherein said adjacent metal rings form an annular grove for housing an elastomeric seal.

45. The sea[ assembly as defined by claim 40 and including spacer means disposed between adjacent metal rings.

46. A seal assembly disposed on a tubular mem ber sliding ly received within a bore of another memberfor providing a metal-to-metal seal between the tubular member and the wall of the bore, comprising:

an integral annular body having an upper annular portion, a medial portion, and a lower annular portion; said medial portion having afrustoconical shape with an upper edge integrally connected to a lower peripheral edge of said upper annular portion and a lower edge integrally connected to an upper peripheral edge of said lower annular portion; actuation means for applying a compressive force on said body causing said upper and lower annular portions to move towards each other thereby deform ing said medial portion to a smaller cone angle such that said upper and lower edges of said media[ portion move into metal-to-metal sealing engage ment with thetubular member and the wall of the bore.

47. The seal assembly as defined by claim 46 wherein said medial portion has a Z shaped cross section with an upper frustoconical link, an intermedi atefrustroconical link, and a lower f rustoconical link.

48. The seal assembly as defined by claim 46 wherein said medial portion includes a series of frustoconical links alternating in direction of frustoco nical taper.

49. The seal assembly as defined by claim 48 wherein there are an odd number of said frustoconic a[ links.

50. A seal assembly for establishing a seal between a casing hanger and a wellhead, com prising:

a pluralitytf frustoconical-shaped metal rings stacked in a series, each metal ring having a frustoconical taper in a direction opposite thefrusto conical taper of any said metal rings adjacent thereto and having inner and outer rims; an annular memberfor disposal on the casing hanger; an actuator member adapted for reciprocal move ment on the casing hanger; said metal rings, annular member, and actuator member having an outer dimension smallerthan the diameter of thewellhead bore; said stackof metal rings being disposed between said annular member and said actuator member whereby upon the movement of said actuator mem bertoward said annular member, said inner and outer rims of said metal rings move radially inward and outward, respectively, for establishing sealing contactwith the casing hanger and wellhead.

51. The seal assembly as defined by claim 50 wherein said metal rings forma Z shape and include an upper frustocon ical ring, an intermediate frustoco nical ring, and a lower f rustoconical ring.

52.The seal assembly as defined by claim 50 16 wherein there are an odd number of said frustoconical metal rings.

53. The seal assembly as defined by claim 50 wherein said metal rings have a thickness permitting at least a 3,000 psi metal-to-metal seal between the casing hanger and wellhead upon the application of 10,000 ft-lbs oftorque to said actuator member.

54. The seal assembly as defined by claim 50 wherein said metal rings are made of a metal having a yield less than one-half the yield of the casing hanger and wellhead materials.

55. The seal assembly as defined by claim 50 wherein said metal rings are made of a ductile material which plastically deforms upon sealing engagement.

56. The seal assembly as defined by claim 50 wherein said metal rings are made of a ductile material permitting the plastic deformation of said rims into the imperfections in thewalls of the casing hanger and wellhead.

57. The seal assembly as defined by claim 50 and including annular links connecting adjacent metal rings.

58. The seal assembly as defined by claim 57 and including other annular links connecting the end metal rings of said stackto the adjacent annular member and actuator memberwhereby said annular links provide a positive connective link between said annular memberand said actuator member.

59. The seal assembly as defined by claim 58 wherein said other annular links have a width allowing said other annular links to bend and permit said rim of said attached adjacent metal ring to contactthe adjacent casing hanger and wellhead.

60. The seal assembly as defined by claim 59 wherein each said annular link and adjacent metal ring forma means for housing an annular resilient memberfor establishing an elastomeric seal between the casing hanger and wellhead.

61. The seal assembly as defined by claim 50 and including spacer means disposed between adjacent metal rings for determining the amount of movement of adjacent metal rings toward each other.

62. The seal assembly as defined by claim 61 wherein said spacer means includes annular resilient members.

63. The seal assembly as defined by claim 62 wherein said annular resilient members are made of an elastomeric material.

64. The seal assembly as defined by claim 62 wherein said annular resilient members are made of grafoil.

65. The seal assembly as defined by claim 50 and including annular elastomeric members disposed between adjacent metal rings.

66. The seal assembly as defined by claim 65 wherein said metal rings retain the extrusion of said elastomeric members.

67. The sea[ assembly as defined by claim 65 wherein the volume of said annular elastomeric members is sized in relation to the annular space between the c3sing hanger and wellhead to permit said rims to contact the casing hanger and wellhead before said elastomeric members can extrude past 6_5 said rims.

GB 2 156 881 A 16 68. The seal assembly as defined by claim 65 wherein said annular elastomeric members have a generally V-shaped cross section with the legs opposite the apex chamfered to control the volume of said elastomeric member between adjacent metal rings.

69. The seal assembly as defined by claim 65 wherein said elastomeric members are bonded to the adjacent metal rings.

70. Apparatus for actuating an elastomeric and metal-to-metal seal disposed within the annulus formed by a wellhead and a casing hanger, comprising:

an actuator member having a portion thereof extending into the annulus and engaging the seal; torque transmission means engaging said actuator memberto transmittorque and rotate said actuator member; said actuator mem berth reading ly engaging the casing hangerwhereby as torque istransmitted to said actuator member in one direction, said actuator membertravels downwardly on the casing hanger a sufficient distance to energizethe seal and seal the annulus againstfluid flow; hydraulic means for applying hydraulic pressureto the seal wherebythe metal-to-metal portion of the seal is energized into metal-to-metal sealing engagementwith thewellhead and casing hanger; said actuator memberfollowing the actuation of the seal downward on the casing hangerto prevent the release of the seal upon the removal of the hydraulic pressure.

71. The apparatus as defined by claim 70 wherein said hydraulic means includes a condiut communi- cating with the annulus above the seal and a pump connected to the conduitto apply hydraulic pressure in the annulus.

72. The apparatus as defined by claim 70 wherein said torque transmission means applies a 10,000 ft-Ib of torque to said actuator memberto establish a 3,000 psi seal in the annulus.

73. The apparatus as defined by claim 70 wherein said hydraulic means applies a gradually increasing pressure to achieve a 20,000 psi compression set of the seal.

74. The apparatus as defined by claim 70 wherein said torque transmission means includes a pipe connected to said actuator member and means for rotating said pipe.

75. The apparatus as defined by claim 74 and including meansforsealing between said pipe and thewellhead.

76. The apparatus as defined by claim 74 and including means for sealing between said pipe and the casing hanger.

77. Atool on a pipe string for lowering a casing hanger and casing into a subsea wellhead and actuating a seal and hoiddown assembly on the casing hanger, comprising:

a mandrel having one end connected to the pipe string and the other end received within the casing hanger; a skirt member disposed on said mandrel; torque transmission means on said skirt member disposed and in engagementwith the seal and holdclown assembly a sleeve membertelescopingly received within the annular chamberformed between said skirt member and mandrel, a portion of said sleeve member extending between said mandrel and the casing hanger; and latch means disposed on said sleeve member and actuated by said mandrel for releasably connecting said mandrel to the casing hanger.

78. The too] as defined by claim 77 wherein said skirt member and mandrel are connected by cooperating splines for the transmission of torque.

79. The tool as defined by claim 78 wherein said splines have opposing shoulders on their lower end and are retained by a retainer member th readingly engaging said mandrel.

80. The tool as defined by claim 77 wherein said skirt member includes port means for the passage of wel I fluids thereth rough.

81. A tool for lowering a casing hanger into an underwater wellhead, comprising:

a mandrel adapted forthreaded engagement at its upper endwith a pipe string and dimensioned at its lower end to be received in the casing hanger; a sleeve member reciprocably mounted on said mandrel and having a portion thereof disposed between said mandrel and the casing hanger; latch means disposed on said sleeve member portion for engaging the casing hanger and connect- ing said mandrel to the casing hanger; said sleeve memberand mandrel having a first position where said latch means is engaged and a second position where said latch means is released.

82. The tool as defined by claim 81 wherein said sleeve member and mandrel having opposing shoulders for retaining said sleeve member on said mandrel.

83. The tool as defined by claim 81 and including seal means for sealing between said sleeve member and said mandrel and for sealing between said sleeve member and the casing hanger.

84. The tool as defined by claim 81 wherein said latch means includes latch segments mounted in apertures through said sleeve member portion, said latch segments being radially movable outwardly through said apertures and into latching engagement with the casing hanger.

85. The tool as defined by claim 84 wherein said latch means includes retainer means for retaining said latch segments in said apertures.

86. The tool as defined by claim 84wherein said manel includes biasing means for biasing said latch segments into engagement with the casing hanger in said first position and relief means for permitting the inward radial movement of said latch segments for disengagement with the casing hanger in said second position.

87. The too[ as defined by claim 86 wherein said biasing means includes a radial annular projection on said mandrel for outwardly biasing said latch segments.

88. The tool as defined by claim 86 wherein said relief means includes an annular groove in said mandrel for receiving said latch segments.

89. The too[ as defined by claim 84 wherein said GB 2 156 881 A 17 latch means includescam meansforcamming said latch segmentsoutof engagementwith thecasing hangerwhen said sleeve memberand mandrel are in a third position.

90. The tool as defined by claim 84 and including release means for preventing said mandrel from moving into said first position aftersaid sleeve member and mandrel have moved into said second position.

91. The tool as defined by claim 90 wherein said release means includes a snap ring housed in said sleeve memberfor engagement with said mandrel as said mandrel and skirt member are moved into said second position.

92. A seal and holdclown assembly disposed on a casing hanger landed within a wellhead, comprising:

a rotating member threading ly engaged with the casing hanger; a stationary memberdisposed on said rotating member, said members being received in the annulus formed bythe casing hangerand wellhead; a latch member disposed on the casing hanger below said stationary member; said stationary member having an upper actuator portion, a medial seal portion, and a lower cam portion; said upper, medial, and lower portions being an integral metal member, said upper actuator portion being rotatably mounted on said rotating member; and torque transmission means for threading said rotating memberonthe casing hangercausing said rotating membertotravel downwardly in the annulus wherebysaid lowercam portion cams said latch memberinto hoiddown engagementwith the well- head and then said medial seal portion sealingly engages the casing hanger and wellhead.

93. The seal and hoiddown assembly as defined by claim 92 wherein said lower cam portion includes a downwardly facing tapered surface opposing an upwardlyfacing tapered surface on said latch member, said surfaces having a camming engagement upon the downward movement of said lower cam portion.

94. The seal and holdclown assembly as defined by claim 92 wherein said latch member includes means engaging the casing hangerfor preventing said latch memberfrom sliding upthe casing hanger.

95. The seal and hoiddown assembly as defined by claim 92 wherein said medial seal portion has a Z shaped cross section composed of a series of integrally connected frustoconical links alternating in frustoconical taper.

96. The seal and holdclown assembly as defined by claim 94 wherein the lower end of said upper actuator portion and the upper end of said lower cam portion havefrustoconical surfaces with a taper in the same direction as the taper of the adjacent frustoconical links.

97. The seal and hoiddown assembly as defined by claim 92 and including bearing means between said rotating member and stationary memberto facilitate the rotation of said rotating member on said stationary member.

98. The seal and hoiddown assembly as defined by claim 92 and including thrust bearing means 18 GB 2 156 881 A 18 between said members for transfering the torque from said rotating memberto said stationary member.

99. The seal and holddown assembly as defined by claim 98 wherein said stationary member includes a first bearing area opposite a second bearing area on said rotating member; said thrust bearing means including bearing rings disposed between said first and second bearing areas.

100. A pipe hangerfor suspending pipe from a wellhead and for sealingly engaging the cylindrical wall of the wellhead bore, comprising:

an annular body suspending pipe within a well, said body having a reduced diameter portion at one end; an annular shoulder disposed on said reduced diameter portion; an annular ring slidably disposed around said reduced diameter portion, said ring and shoulder having frustoconical surfaces; a plurality of frustoconical metal rings disposed on said reduced diameter portion between said frustoconical surfaces and stacked in series, each of said frustoconical ring alternating in frustoconical taper, the end rings of said stack of metal rings having frustoconical taperstapering in the same direction as the adjacent surfaces of said annular ring and annular shoulder but having a smallercone anglethan said surfaces of said annular ring and shoulder; said annular ring being moveablefrom a nonseaiing position to a sealing position, said annular ring In said sealing position deforming said stack of meW rings compressing said metal rings to sealingiy engage the wellhead bore wall and said reduced diameter portion.

101. The pipe hanger as defined by claim 100 wherein said metal rings forma Z shaped cros3 section which deforms upon the application ol a compressive load.

102. The pipe hanger as defined by claim 100 wherein said metal rings are made of a ductile material which plastically deforms upon sealing engagement.

103. The pipe hanger as defined by claim IGO and including annular links connecting adjacent metal 110 rings.

104. The pipe hanger as defined by claim 103 and including other annular links connecting the end metal rings of said stack to the adjacent annular shoulder and annular ring whereby said annular links 115 provide a positive connective link between said annular shoulder and said annular ring.

105. The pipe hanger as defined by claim 104 wherein each said annular link and adjacent metal ring forma means for housing a resilient memberfor 120 establishing an elastomeric seal between said annular body and the wellhead. 106. A pipe hanger for suspending pipe within a well from a wellhead, comprising:

an annular bodyconnected to the upper end of the pipe suspended within the well, said body having an annularshoulder landed on the wellhead; a latch member disposed on said shoulder; a rotating member threading ly engaged to said annularbody; a stationary member having an upper actuator portion, a medial seal portion, and a lower cam portion; said upper, medial, and lower portions being an integral metal member, said upper actuator portion being rotatably mounted on said rotating member; said stationary member being received in the annulusformed bysaid annular body and the wellhead and being disposed above said latch memberwhereby upon rotation of said rotating member causing said stationary memberto travel downwardly in the annulus, said lower cam portion cams said latch member into hoiddownengagement with thewellhead and then said medial seal portion sealingly engages said annular body and the well- head.

107. The pipe hanger as defined by claim 106 wherein said medial seal portion has a Z shaped cross section composed of a series of integrally connected frustoconical links alternating in frustoconical taper.

108. The pipe hanger as defined by claim 106 wherein said annularshoulder includes an annular removable portion, said annular removable portion having a 3600 downwardly facing frustoconical bear ing surfacefor engagement with thowellhead.

109. The pipe hanger as defined by claim 108 i.,,hc,rein the remaining portion of said annular shoulder includes flow ports therethrough forthe passage of we',1 fluids.

110. Awe!! apparatus for sealing and locking 955 dowri a cas,ng hanger landed within awellhead, comprising:

a rotating member threadinghl engaging the cashig hanger; a stationar-1 member having an actuator portion, a rnedial sc-al portion, and a lower cam portion; said upper, madial, and portions being an integral rristal membe,-, ssid upper actuator portion being rotatabh., wounted on said rotat,,ng rnember; said stati c n a ry rn. e r, ber being received..n the annulus 10-5 forrined, bythecasing hanger and wellhead; a latemi nic-i-iiLare-'JJisposed onthecasing hanger belowsaid stationary member; ^.crquetra,nsr-,ission meansengaging said rotating mam bar to transm it torque and rotatesaid rotating mer-ibz-r iierey causing said rotating memberto move dovjn.,iardly on the casing hangerwhereby saidllower cam portion cams said latch member into holddown engagement with the wellhead and said medial seal portion sealingly engages the easing hanger and wellhead to preventfluid flowthrough theannulus; hydraulic means for applying hydraulic pssure to said stationary memberto futherenergize said medial seal portion into sealing engagement with the casing hanger and wellhead; and said rotating memberfollowing thefurther actuation of said medial seal portion downward on the casing hangerto preventthe release of said medial seal portion upon the removal of said hydraulic pressure.

111. The well apparatus as defined by claim 110 wherein said torque transmission means applies a 10,000 ft-1 b of torque to said rotating memberto establish a seal in the annulus.

112. The well apparatus as defined by claim 110 19 wherein said hydraulic means applies a gradually increasing pressureto achieve a 20,000 psi compression set of said medial seal portion.

113. A well apparatus for suspending pipe within a well, comprising:

a wellhead having a bore therethough, said wellhead having an annular shoulderwith an annular lockdown groove disposed thereabove; a casing hanger having an annular bearing surface for landing on said annular shoulder and a latch member disposed on said casing hanger above said bearing surface and adjacent said lockdown groove in the landed position; a seal and hoiddown assembly disposed on said casing hanger above said latch member, said seal and holdclown assembly including a rotating member and a stationary member; said rotating memberthreadingly engaging said casing hanger and said stationary member being 20._ rotatably mounted on said rotating member, said stationary member being received in the annulus formed by said casing hanger and wellhead; said stationary member having a seal portion and a cam portion, said cam portion engaging said latch member; torque transmission means for rotating said rotating member on said casing hanger and causing said rotating member and stationary memberto travel downwardly into the annulus; said cam portion camming said latch member into said lockdown groove forthe holdclown of said casing hangerwithin said wellhead; said seal portion being compressed bythe downward movement of said rotating memberwhereby said seal portion sealingly engages said casing hanger and said wellhead; hydraulic means for applying hydraulic pressure to said stationary portion whereby said seal portion is further energized into sealing engagementwith said wellhead and casing hanger; and said rotating member moving downward on said casing hanger upon the further actuation of said seal portion whereby said rotating member prevents the release of said seal portion upon the removal of hydraulic pressure by said hydraulic means.

114. The well apparatus as defined by claim 113 wherein said torque transmission means applies 10,000 ft-l b of torque to said rotating memberto establish a 3,000 psi seal in the annulus.

115. The apparatus as defined by claim 113 wherein said hydraulic means applies a gradually increasing pressure to a maximum of 15,000 psi to achieve a 20,000 psi compression set of said seal portion.

116. The well apparatus as defined by claim 113 wherein said seal portion includes metal seals for establishing a metal-to-metal seal between said casing hanger and said wellhead.

117. The well apparatus as defined by claim 116 wherein said seal portion further includes resilient seals between said metal seals to create an elastomeric seal between said casing hanger and said wellhead priorto the application of the hydraulic pressure by said hydraulic means.

118. A casing hanger comprising:

GB 2 156 881 A 19 a body having a landing shoulder for landing on a wellhead; holddown means disposed on said bodyfor holddown engagementwith thewellhead; metal seal means disposed on said body above said holddown means for metal-to-metal sealing engagement with the wellhead; and an actuator positioned above said metal seal means whereby upon a longitudinal downward movement of said actuator, said holddown means engages the wellhead and upon further downward movement of said actuator said metal seal means sealingly engagesthe wellhead.

119. The casing hanger as defined by claim 118 and including:

torque means for transmitting a torqueto said actuator; and hydraulic means for applying fluid pressure on said metal seal means.

120. The casing hanger as defined by claim 118 wherein said holddown means includes:

a longitudinally movable sleeve having a down wardlyfacing shoulder; a movable locking ring having an upwardly facing shoulder engaging said downwardly facing shoulder; said bodyincluding a locking recessfor receiving said locking ring whereby upon downward movement of said actuator said sleeve moves downward causing said downwardly facing shoulderto cam said locking ring into holdclown engagement with the wellhead.

121. The casing hanger as defined by claim 120 wherein the bottom of said locking ring and the bottom of said recess include tapering coacting faces.

122. The casing hanger as defined by claim 120 wherein said shoulders include tapering coacting faces.

123. A well apparatus for suspending pipe within a borehole, comprising:

a wellhead member; a seat member telescopingly received within said wellhead member, said seat member having an upwardlyfacing annular frustoconical shoulder; tooth means provided on said wellhead member and seat memberfor releasably connecting said seat memberwithin said wellhead member upon said seat member being rotated less than 3600; a hanger member attached to the top of the string of pipe, said hanger member having a downwardly facing bearing surface engaging said shoulder of said seat member; port means extending through said hanger member and around said bearing surface whereby said bearing surface and said shoulder have full 360o circumferential contact.

124. The well apparatus as defined by claim 123 wherein said bearing surface includes a releasable annular support th readingly engaged to said hanger member.

125. The well apparatus as defined by claim 123 wherein said tooth means comprises a plurality of space groupings of teeth, said groupings of said seat member being adapted to pass intermediate said groupings of said wellhead member during insertion GB 2 156 881 A 20 of said seat member into said wellhead member.

126. The well apparatus as defined by claim 125 wherein said teeth are spaced-apart no-lead threads which do not interferingly engage upon rotation of said seat memberwithin said wellhead member.

127. The well apparatus as defined by claim 123 and including a latch member disposed on said hanger memberfor expansion into a lockdown groove in said wellhead member above said bearing surface whereby said casing hanger is locked down within said wellhead.

128. The well apparatus as defined by claim 12 and including a sea[ assembly disposed on said hanger member, said seal assembly including a plurality of frustoconical shaped metal rings stacked in series with each ring alternating in frustoconical taper, said metal rings having an outer diameter smallerthan the inner diameter of said wellhead; and acutation meansfor applying an axial force on said stackof metal rings whereby said metal rings are compressed into metal-to- metal sealing engagement with said hanger member and said wellhead member.

129. The well apparatus as defined by claim 128 and including an annular shoulder on said hanger member and an actuator member reciprocally mounted on said hanger member, said stack of metal rings being disposed between said annularshoulder and said actuator member.

130. The well apparatus as defined by claim 129 95 and including annular links between said metal rings, annular shoulder, and actuator memberforming a positive connective link between said annular mem berand said actuator member.

131. The well apparatus as defined by claim 130 wherein said adjacent metal rings form annular grooves for housing elastomeric seals.

132. The well apparatus as defined by claim 130 and including spacer means disposed between adja- cent meta I rings.

133. The well apparatus as defined by claim 123 and including a holdclown and seal assembly disposed on said hanger memberand received within the annulus formed between said hanger member and said wellhead member; said holdclown and sea[ assembly being actuated upon the application of a vertical compressive force thereon; an actuator mem berth reading ly engaged to said hanger memberand having a portionthereof engag- ing said holdclown and seal assembly; torque transmission means engaging said actuator member to transmit torque and to rotate said actuator memberwhereby said actuator membertravels downwardly as said actuator mem berth readingly engages said hanger member whereby a vertical compressive force is applied to said holddown and seal assembly; hydraulic means for applying hydraulic pressureto said holdclown and seal assembly wherebysaid hydraulic pressure applies an additional vertical compressive forceto said holdclown and seal assemblyto further energize and actuate said holdclown and seal assembly.

134. The well apparatus as defined by claim 123 and including a first metal-to-metal seal assembly disposed in the annulus between said wellhead member and said hanger memberfor establishing a metal-to-metal seal therebetween; a second hanger member landed on said hanger member and second metal-to-metal seal means for establishing a metal-to- metal seal between said second hanger memberand said wellhead member; a third hanger member landed on said second hanger member and third metal- to-metal seal means forestablishing a metal-to-metal seal between said third hangermemberand saidwelfhead member.

135. The well apparatus as defined by claim 134 and including torque transmission means for successively engaging said first metal-to-metal seal assem- bly, said second metal-to-metal seal assembly, and said third metal-to- metal seal assembly for applying a vertical compressive force to actuate said assemblies; and hydraulic means for successively applying hyd- raulic pressureto said first metal-to-metal seal assembly, said second metal-to-metal seal assembly, and saidthird metal-to-metal seal assembly to further actuatesaid seal assemblies into sealing engagement.

136. A method of completing an underwaterwell comprising the steps of:

(a) locating drilling means at an underwaterwell site; (b) installing conductor casing in the floor of a body of waterwith a wellhead, blowout preventer stack, and riser attached thereto at a point nearthe f loor, the riserextending upwardlyto said drilling means; (c) running a drill string and standard 17-112 inch drill bitthrough the wellhead and conductor casing; (d) drilling a hole for suspending another casing within theweilhead and conductor casing; (e) lowering a hanger seat into the well until the seat lands in the wellhead; (f) rotating the hangerseat less than 360'to connect the hanger seat within the well head; (g) latching the hanger seat within the wellhead; (h) running a casing hangerwith the other casing through the riser and into the wellhead; and (i) landing the casing hanger on the hanger seat.

137. A method for completing an underwater well comprising the steps of:

(a) locating drilling means at an underwaterweli site; (b) installing conductorcasing in the floor of a body of waterwith a wellhead, blowout preventer stack, and riser attached thereto at a point near the floor, the riser extending upwardly to the drilling means; (c) running a drill string and standard 17-112 inch drill bitthrough the wellhead and conductor casing; (d) drilling a hole for suspending anothercasing string within thewellhead and conductor casing; (e) lowering a hangerseatwith breech block threads intothewell until the breech blockthreads of the hangerseat engagethetop of the breech block threads on the wellhead; (f) rotating the hangerseat lessthan one revolution until the breech blockthreads on the hanger seat pass intermediate the breech blockthreads on the wellhead wherebythe hanger seat moves downwardly several inches with respect to the wellhead; 21 GB 2 156 881 A 21 (9) rotating the hanger seat less than one revolution to connect the hanger seat within the wellhead; (h) running a casing hangerwith casing string through the riser and into thewellhead; and (i) landing the casing hanger on the hangerseat.

138. A method of completing an underwater well comprising the steps of:

(a) installing a conductor casing in thefloor of a body of waterwith a wellhead, blowout preventer stack, and riser attached thereto at a point near the floor, the riser extending upwardly to the surface; (b) running a casing hangerwith casing string through the riser; (c) landing the casing hangerwithin the wellhead; (d) rotating an actuator ring threadingly engaged to 80 the casing hanger and disposed above a seal assembly; (e) compressing the seal assembly bythe downward travel of the actuator ring on the casing hanger; (f) reducing the cone angle of the frustoconical metal rings disposed on the seal assembly; (g) compressing resilient members housed between the frustoconical metal rings as the cone angles are reduced; (h) sealing the wellhead and casing hangerfrom fluid flow bythe compression of the resilient members; (i) applying hydraulic pressure to the seal assembly; (j) contacting the wellhead and casing hangerwith the inner and outer edges of the frustoconical metal rings as the seal assembly is further compressed by the hydraulic pressure; (k) moving the actuator ring downward on the casing hanger as the seal assembly is further compressed bythe hydraulic pressure; (1) removing the hydraulic pressurefrorn the seal assembly.

139. The method asset forth in claim 138 further including the steps of:

(m) lowering a second casing hangerwith casing string through the riser and into the wellhead; (n) landing the second casing hanger onto the first casing hanger; (o) repeating steps (d) through (e) to actuate a seal assembly for sealing the second casing hangerwith thewellhead; (p) running a third casing hangerwith casing string through the riser into the wellhead; (q) landing thethird casing hanger ontothe second casing hanger; (r) repeating steps (d) through (e) aboveto actuate the seal assemblyfor sealing thethird casing hanger with the wellhead.

140. A method of completing an underwater well 120 comprising the steps of:

(a) connecting a running tool on the end of a drill string; (b) connecting the running tool to a casing hanger; (c) sealing the casing hangerwith the running tool; (d) running the casing hangerwith casing string through a riser, blowout preventer stack, and into a wellhead; (e) landing the casing hanger on a shoulder in the wellhead; (f) rotating the drill string and a portion of the runningtool; (g) applying torque to an actuator nut using the portion of the running tool; (h) threading the actuator nut onto the casing hanger as torque is applied thereto; (i) compressing a seal assembly below the actuator nut; (j) creating an elastomeric seal of the seal assembly between the wellhead and casing hanger; (k) applying 10,000 ft-Ibs of torque on the drill string until no furthertorque is transmitted to the seal assembly; (1) closing the blowout preventer rams of the blowout preventerstack; (m) applying pressure to a line communicating with the annulus between the drill pipe and the wellhead and belowthe blowout preventer; (n) applying hydraulic pressure to the seal assembly; (o) compressing frustoconicai metal gaskets in the seal assembly; (p) creating a metal-to-metal seal between the wellhead and casing hanger; (q) rotating the actuator memberfurther down wardly on the casing hanger as the hydraulic pressure further compresses the sealing assembly; (r) removing the hydraulic pressure through the line; (s) disengaging the running tool from the casing hanger; and (t) removing the running tool from the well.

141. The method as defined byclaim140 including the step of raising the drill pipe to disen- gage the running tool from the casing hanger.

142. A method of releasably attaching a running tool, to a casing hanger comprising the steps of:

(a) inserting a sleeve of the running tool within the casing hanger; (b) moving a mandrel of the running tool downward within the sleeve; (c) biasing latches disposed in the sleeve into engagementwith the casing hanger; (d) holding the latches into engagement by the mandrel; (e) running the casing hanger with casing string intothewell; (f) landing the casing hanger onto the wellhead; (g) lowering the running tool mandrel further within the sleeve upon the actuation of a sealing assembly; (h) removing the biasing portion of the mandrel from the latches; (i) raising the mandrel; (j) connecting the sleeve to the mandrel before the mandrel is raised sufficiently to again bias the latches; (k) camming the latches out of engagement with the casing hanger; and (1) removing the running tool from the well.

143. A seat for supporting a plurality of pipe hangers within a wellhead as claimed in claim 1 substantially as described with reference to the accompanying drawings.

144. Apparatus for supporting a hanger suspend- 22 ing pipewithin a borehole as claimed in claim 13 substantially as described with reference to the accompanying drawings.

145. A well apparatus for supporting a plurality of stacked pipe hangers suspending pipe within a borehole as claimed in claim 34 substantially as described with reference to the accompanying draw ings.

146. A seal assembly as claimed in claim 40 substantially as described with reference to the 75 accompanying drawings.

147. Apparatus for actuating an elastomeric and metal-to-metal seal disposed within the annulus formed bya wellhead and a casing hanger, as claimed in claim 70, substantially as described with reference to the accompanying drawings.

148. Atool on a pipe string for lowering a casing hanger and casing into a subsea wellhead as claimed in claim 77 substantially as described with reference to the accompanying drawings.

149. A seal and holdclown assembly as claimed in claim 92 substantially as described with reference to the accompanying drawings.

150. A pipe hangerfor suspending pipe from a wellhead as claimed in claim 100 or claim 106 substantially as described with reference to the accompanying drawings.

151. Awell apparatus for sealing and locking down a casing hanger landed within a wellhead as claimed in claim 110 substantially as described with reference to the accompanying drawings.

152. A well apparatus for suspending pipe within a well as claimed in claim 113 substantially as described with reference to the accompanying draw ings.

153. A casing hanger as claimed in claim 118 substantially as described with reference to the accompanying drawings.

154. A well apparatus for suspending pipe within a borehole, as claimed in claim 123 substantially as described with reference to the accompanying draw ings.

155. A method of completing an underwaterwell as claimed in claim 136,137,138 or 140 substantially as described with reference to the accompanying drawings.

156. A method of releasably attaching a running tool to a casing hanger as claimed in claim 142 substantiallyas disclosed herein.

Superseded claims 1 to 156.

New or amended claims:CLAIMS 1. An apparatus for supporting a hanger suspending pipe within a borehole, comprising:

a head member; a support member tel escopically receivedwithin said head member and adapted to engage the hanger; a plurality of circumferentially spaced-apart no- lead threads on the inner circumference of said head member and on the outer circumference of said supportmember; the threads on each being in alignment with the spaces between the threads on the other member, said threads being engaged apart from upon the GB 2 156 881 A 22 application of an axial forcethereon; whereby said support member may be engaged with said head member and provide support means for supporting the hanger and pipe with the borehole.

2. An apparatus for supporting a pipe hanger suspending pipe within awefl, comprising:

a head member; a support memberadapted to engagethe pipe hanger; said support member being insertable into said head member; tooth means provided on each of said head and support membersfor releasably connecting said memberstogether on said support member being rotated; said tooth means comprising a plurality of spaced groupings of teeth, said groupings of said support member being adapted to pass intermediate said groupings of said head member during insertion of said support member into said head member.

3. The apparatus as defined by claim 2, wherein said teeth are fully engaged upon rotation of said support memberless than one revolution.

4. The apparatus as defined by claim 2, wherein said teeth are tapered with a zero lead angle for increasing the shear area of said teeth.

5. The apparatus as defined by claim 2, wherein said teeth on said support member do not interferingly engage said teeth on said head member.

6. The apparatus as defined by claim 2, wherein said teeth have a nonsquare shoulder profile for preventing the accumulation of well debris on said teeth.

7. The apparatus as defined by claim 2, wherein said groupings of teeth include tooth segments whereby upon rotation into engagement, the rotating tooth segments of said support member clean said tooth segments on said head member.

8. The apparatus as defined by claim 2, wherein said teeth have a tooth profile for equalizing the stresses overall of said teeth.

9. The apparatus as defined by claim 2, wherein said teeth all have an equal length, the number of groupings on said head member equal the number of groupings on said support member, and each of said members has an even number of said groupings, whereby upon engagement, the stresses and loads are evenly distributed between theteeth.

10. The apparatus as defined by claim 2, wherein each of said members includes six groupings and six spaces.

11. The apparatus as defined by claim 2, wherein said groupings each includes six rows of teeth.

12. The apparatus as defined by claim 2 and including a tooth on said support member having an axial width greaterthan the other support member teeth for preventing a premature threaded engagement between said members.

13. The apparatus as defined by claim 2 and including telescoped unthreaded areas of cylindrical configuration on each of said members.

14. The apparatus as defined by claim 2 wherein said groups of teeth on said head member have:substantially the same circumferential extent as said groups of teeth on said support member.

23 15. The apparatus as defined by claim 2 and including anti-rotation means for preventing relative rotation of said members.

16. The apparatus as defined by claim 2, wherein said anti-rotation means includes a stop on one of said members in engagement with the other said member.

17. The apparatus as defined by claim 2, wherein said anti-rotation means is effected upon rotation of said support member less than one revolution.

18. The apparatus as defined by claim 2, wherein said anti-rotation means includes a moveable element on one of said members positioned within a cavity in the other said member.

19. The apparatus as defined by claim 2, wherein said moveable element maybe moved to allow disengagement of said members by relative rotation of said members without relative axial movement, followed by relative axial movement of said support member awayfrom said head member in the 85 absence of relative rotation.

20. The apparatus as defined by claim 2, wherein said support member includes means for moving said moveable element into disengagement.

21. The well apparatus of claim 14 wherein the passage of said groupings of teeth on said support member intermediate said groupings of teeth on said head member provide indication that said tooth means is engaged upon rotation of said support member.

22. A well apparatus for supporting a plurality of stacked pipe hangers suspending pipe within a wellbore, comprising:

a head member; a support member having a first bearing area adapted to engage the lowermost stacked pipe hanger; tooth means provided on each of said head and support membersfor releasably connecting said members together, said tooth means having a second bearing area for supporting said support member on said head member; said first and second bearing areas each having sufficient area whereby the load of the pipe hangers and suspended pipe togetherwith the working pressure of the well does not substantially exceed the material yield strength in vertical compression of said support and head members.

23. The well apparatus as defined by claim 22, wherein said head member has a minimum bore of 17-9/16 inches adapted for receiving a standard 17-1/2 inch drill bitto drill the wellbore forthe pipe suspended bythe lowermost stacked pipe hanger.

24. The well apparatus of claim 22, wherein said head and support member are made of a high strength yield material having a 85,000 psi minimum yield.

25. The well apparatus of claim 22, wherein said bearing areas are capable of supporting a load in excess of six million pounds.

26. The well apparatus as defined by claim 22, wherein said first bearing area includes a tapered annular shoulder on said support member having a taper angle greaterthan 30 degrees.

27. The well apparatus as defined by claim 22, GB 2 156 881 A 23 wherein saidtooth means includes a plurality of segmented circular grooves on each of said members, said segmented grooves of said support member being adapted to pass intermediate said seg- mented grooves of said head member.

28. A well apparatus for suspending pipe within a borehole, comprising:

a wellhead member; a seat member telescoping ly received within said wellhead member, said seat member having an upwardlyfacing annularfrustoconical shoulder; tooth means provided on said wellhead member and seat memberfor releasably connecting said seat memberwithin said wellhead member upon said seat member being rotated less than 360 degrees; a hanger member attached to the top of the string of pipe, said hanger member having a downwardly facing bearing surface engaging said shoulder of said seat member; port means extending through said hanger member and around said bearing surface whereby said bearing surface andsaid shoulder have full 360 degrees circumferential contact.

29. The well apparatus as defined by claim 28, wherein said bearing surface includes a releasable annular support threadingly engaged to said hanger member.

30. The well apparatus as defined by claim 28, wherein said tooth means comprises a plurality of spaced groupings of teeth, said groupings of said seat member being adapted to pass intermediate said groupings of said wellhead member during insertion of said seat member into said wellhead member.

31. The well apparatus as defined by claim 30, wherein said teeth are spaced-apart no-lead threads which do not interferingly engage upon rotation of said seat member within said wellhead member.

32. The well apparatus as defined by claim 28, and including a latch member disposed on said hanger memberfor expansion into a lockdown groove in said wellhead member above said bearing surface whereby said casing hanger is locked down within said wellhead.

33. The well apparatus as defined by claim 28 and including a seal assembly disposed on said hanger member, said seal assembly including a plurality of frustoconical shaped metal rings stacked in series with each ring alternating in frustoconical taper, said metal rings having an outer diameter smallerthan the inner diameter of said wellhead; and actuation means for applying an axial force on said stack of metal rings whereby said metal rings are compressed into metal-to-metal sealing engagement with said hanger member and said wellhead member.

34. The well apparatus as defined by claim 33 and including an annular shoulder on said hanger mem ber and an actuator member reciprocally mounted on said hanger member, said stack of metal rings being disposed between said annular shoulder and said actuator member.

35. Thewell apparatus as defined by claim 34 and including annular links between said metal rings, annular shoulder, and actuator memberforming a positive connective link between said annular mem- ber and said actuator member.

24 GB 2 156 881 A 24 36. The well apparatus as defined by claim 35 wherein said adjacent metal rings form annular grooves for housing elastomeric seals.

37. The well apparatus as defined by claim 35 and including spacer means disposed between adjacent metal rings.

38. The well apparatus as defined by claim 28 and including a holddown and seal assembly disposed on said hanger member and received within the annulus formed between said hanger member and said wellhead member; said holddown and seal assembly being actuated upon the application of a vertical compressive forcethereon; an actuator memberthreadingly engaged to said hanger member and having a portion thereof engaging said holdclown and seal assembly; torquetransmission means engaging said actuator memberto transmittorque and to rotate said actuator memberwhereby said actuator membertravels downwardly as said actuator memberthreadingly engages said hanger memberwhereby a vertical compressive force is applied to said holdclown and seal assembly; hydraulic means for applying hydraulic pressureto said holddown and seal assembly whereby said hydraulic pressure applies an additional vertical compressive force to said holdclown and seal assemblyto further energize and actuate said holdclown and seal assembly.

39. The well apparatus as defined by claim 28 and including a first metalto-metal seal assembly disposed in the annulus between said wellhead member and said hanger memberfor establishing a metal-tometal seal therebetween; a second hanger mem ber landed on said hanger member and second metal-to- metal sea[ means for establishing a metal-to-metal sea[ between said second hanger memberand said wellhead member; athird hanger member landed on said second hangermemberand third metal-to-metal seal means forestablishing a metal- to-metal seal between said third hangermemberand said wellhead member.

40. The well apparatus as defined by claim 39 and including torquetransmission means for successive- ly engaging said first metal-to-metal seal assembly, said second metal-to- metal seal assembly, and third metal-to-metal seal assemblyfor applying a vertical compressive force to actuate said assemblies; and hydraulic means for successively applying hyd- raulic pressureto said first metal-to-metal seal assembly, said second metal-to-metal seal assembly, and said third metal-to-metal seal assemblyto further actuate said seal assemblies into sealing engagement.

41. Apparatus for supporting a hanger suspending pipe within a borehole as claimed in claim 1 substantially as described with reference to the accompanying drawings.

42. Awell apparatus for supporting a plurality of stacked pipe hangers suspending pipe within a borehole as claimed in claim 22 substantially as described with reference to the accompanying draw- ings.