CA1206091A - Breech block hanger support - Google Patents

Abstract

A B S T R A C T
The present invention relates to a breech block hanger support in a subsea wellhead assembly used in of offshore wells having a working pressure of up to approximately 15,000 psi.
The wellhead assembly includes a wellhead, the breech block hanger support, a packoff for sealing the breech block hanger support, and one or more other casing hangers supported by the breech block hanger support.
The breech block hanger support is landed and connected to the wellhead for suspending casing within the well, for supporting one or more of the other casing hangers and casing within the well, and for withstanding and containing the pressure load within the well. Breech block teeth are provided on the wellhead and the breech block hanger support to permit the hanger support to be stabbed into the wellhead and rotated less than 360° for completing the connection therebetween. The breech block teeth include groupings of spaced-apart no-lead teeth having slots provided therebetween. The breech block slots provide a natural flow way for the passage of well fluids.
The breech block hanger support further includes an upper annular flange for arresting the downward movement of the breech block hanger support within the wellhead. This annular flange includes flutes aligned with the breech block slots for the passage of well fluids.

The upper surface of the annular flange provides a bearing surface for supporting another casing hanger. The bearing surface of the hanger support will support all of the casing and tubing load and in addition thereto, withstand and contain the 15,000 psi working pressure. The bearing surface between the breech block teeth is greater than the bearing surface provided by the hanger support for the other casing hangers.
The packoff is provided for sealing the breech block hanger support with the wellhead and other casing hangers.
The packoff includes means for testing the integrity of the seals of the packoff.

Description

~ 611~-99 SUBSEA WELLHEAD SYSTEM
BACXGROUND OF THE INVENTION
This inven-tion relates to subsea wellhead systems and more particularly, to me-thods and appara-tus for supporting, holdiny down, and sealing casing hangers within a subsea well-head.
Increased activity in offshore drilling and comple-tion has caused an increase in working pressures such that it is anticipated that new wells will have a working pressure of as high as 1~,000 psi. To cope with the unique problems associ-ated 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 over 300 feet. These drilling operations generally include a ~loating vessel having a heave compensator for a riser and drill pipe extending to the blowout preventer and wellhead located at the mud line. The blowout preventer stack is generally mounted on 20 inch pipe with the riser extending to the surfaceO A quick disconnect is often located on top o~
the blowout preventer stackO ~n articulation joint is used to allow for vessel movement. Two major problems arise in 15,000 psi working pressure subsea wellhead systems operating in this environmentl namely, a support shoulder in the wellhead housing which will support the casing and pressure load, and a sealing means between the casing hangers and wellhead which will withstand and contain the working pressure.
In the past, prior art wellhead designs permitted adequate landing support for successive casing hangers. However, with the increase in pressure rating and the landing and support-ing of multiple casing strings and tubing strings within the wellhead, a small support shoulder will not suppor-t the loacl~

13~1-298-A - 1 -~ ~(3~

Althouyh an obvious answer to the problem would be to merely use a support shoulder large enough to support the casing and pressure load, ~ la -~ 6~

.
large support shoulder~ pro~ecting into the flow bore in ~he ~ellhead housing for restrïcted access to the casing below the wellhead housing for drilling. In the early d~ys o ~ffshore drilling, 16-3/4 inch bore subsea wellhead systems required underreaming. At that time, most floati~g drilling rigs were out~itted with a 16-3/4 inch blowout preventer system to eliminate the two stack (20 inch and 13-5/8 inçh) and the two riser system reguired up until that time. As wellhead systems moved from 5,0~0 psi to 10,000 psi working pressure, the 18 3/4 inch, 10,000 psi support shoulder was developed to carry casing and pressure loads and to provide full access into the casing below the well-head housing.
The second major problem is the sealing means. The sealing means must be capable of withstanding c~nd cont~ining 15,000 psi working pressures. Available energ~ sources for energizing the sealing means include weight, hydraulic pressure, and torque.
Each sealing means requi-res different amounts of energy to posi-. . .
tion and energize. Weight is the leas-t desirable because the 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 ne2d for wir~line ~uipment to run and recover dart~ from the hydraulic to-actuate~ seal ener-gization ~yst@m. If darts are not used, the handling o "wet ~trings" of drill pipe i5 very messy and u~popular with drilling crews. If the seal ener0ization means u~es the sin~le trip casing hanger technigue, the cementing fluid can cause problems in the hydraulic system used to energize the s~al. Maintenance is also a problem. Al~hough torque is the most desir~ble method to energize a seal, ~here are limitations on the amount of tor~ue which can be transmitted ~rom the surface due to friction lo~ses to riser pipe, the blowout preventer stack~ o~f location, various threads, and the dril~ pipe itself.
The subsea wellhead system of the present invention overoomes the deficiencies o~ the prior art and incluclPs many other adva~-ta~eou~ ~eature~. The ~ystem is slmple, has les~ than 5D par~s and is suitable for ~S service. The system has single trip capability but can still use multiple trip methods. All hangers are interchangeable with respect to t~e outer profile so that -~
they can be run in lower positions. The seal elements are inter changeable and are fully energized to a pressure in ~xcess of the anticipated wellbore pressure. Back-up seals are a~ail~ble. The seals are not pressure de-energized. The hangers can be run without lock downs and the seal elements will seal even if the hanger lands high.
The housing support seat supports in excess o 6,000,000 lbs. ~working pressure plus casing weight or test pressure) with~ut exceeding 150% of material yield in compression. The wellhead will pass a 17-1/2 inch diameter bit. The present inventi~n does not attempt to 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 durins~ drilling or to collecting trash during the running of a 13~3/8 inch casing. Further, the housing support seat does not require a separate trip nor does i-t dras snap rings down the bore.
The hanger hGld down will h~ld down 2,000,000 lbs. The hanger hold down is positively mechanically retracted when re--trieving the c~sin~ hanger body and is compatible with single trip operations. The hanger hold down is released ~r retrieval ~f the c2sing hanger when the ~eal eleme~t is retxieved. The hanger hold dow~ is compatible with multiple trip operations and permits the running of the hanger with or without the hold down.
I'he sealing means will work even if the hold down is not u ed.
The hanger hold down is reu~able and has a minimum number of tolerances to stack up between hold dowra grooves.
The sealing means of the present invention will reliably seal an 2nnular area o approximately 18-1/2 inch outside diameter by 17 inch :inside diameter and pro~ide a rubber pressure in excess of 15,000 psi (20,000 psi nominally) when the sealing means is energiæed and the sealing means sees a pressure ~rom ~f ~bove or below oI 15,000 psi. The pressure in excess of lStOOO
'psi is retained in khe seali-ng-means after the running tool is removed~ The sealing means is additionally self-energized to hold full pressure where full loading force was not applied or where full loading force was not retained. The sealing means il; not be ;oressure de-energized. The sealing mea~s provides a ~e'~atively long seal area to bridge housing defects and/or trash.
Furthe~, the sealing means provides primary metal-to-metal seals and uses the metal-to-metal seals as backups to prevent high pressure extrusion of secondary elastomeric seals. The sealing means of the present invention positively retracts the metal-to-metal seals fr~n the walls prior to retrieving the sealing means.
The elastomeric seals of the sealing means are allowed to relax durins retrieval of the packoff assembly and is completely re-trievable. The present sealing means provides a substantial metallic link between the top and the bottom of the packing seal area to insure that the-lower ring is retrievable. The design 2110~s for single trip operations. There are no intermittent metal parts in the se~l area to give irregular rubber pressures.
The sealing means provides a minimum nul~ber of seal areas in parallel to minimize leak pa~hs. The sealin~ mean~ is p~sitively attached to the packing element so that it cannot be washed off by flow during the running operations. The design also a~lows or multiple trip operations and is intercha~geable fox all casing ~angers within a nominal size.
The means to load the sealing means reliably provides ~
force to energize the sealin~ means t~ a nominal ~0,000 psi. It allows full circulation i used in a single trip. However,-the loading means is compatible with either a single trip operation or multiple trip operakion. Further, it is interchangeable ~or all casing hangers within the wellhead systesn. The loading means will cause the sealing means to seal even if the casing hanger is set high. Furth~r, it does not release any significant amount of the full pressure loacl aftex actuation. The loading means does ~2~

not require a remote engagement of hold down threacls. Further, it has no shear pins. The loading means is reusable and does not have to remotely engage hold down threads Oh packing nut replace-ment.
I'he casing hanger running tool includes a connection between the running too] and casing hanger which will support in excess of 700,000 lbs. of pipe load. The running tool is able to generate an axial force in excess of 900,000 lbs. to energize the sealing means. Further, the running tool is able to tie back into the casing hanger without a left hand torque. The running tool can be run on either casing or drill pipe.
Other objects and advantages of the invention will appear from the following description.
SUMMA~Y OF THE INVENTION
The present invention relates to a breech block hanger support in a subsea wellhead assembly particularly useful for ofEshore wells having a working pressure of up to approximately 15,000 psi. The wellhead assembly includes a wellhead, the breech block hanger support, a packoff for sealing the breech block hanger support with the wellhead and another casing hanger, and one or more other casing hangers supported by the breech block hanger support.
According to the present invention there is provided an apparatus including a hanger-support member for supporting at least one pipe hanger within a wellhead of a well, the pipe hanger having a first string of pipe attached there-to, and for suspending a second string of pipe within the well, the wellhead having a plurality of circumferen-tially spaced-apart groupings oE tooth segments projecting into the wellhead bore for engage-men-t with the hanger-support member, said support member including a tubular body received within -the wellhead, a plurality of circumferentially spaced-apart groupings of tooth segments _ 5 _ disposed on -the periphery of said tubular body and adapted for releasably engaging -the tooth segrnents of -the wellhead, shoulder means on said tubular body adapted for engagingly supporting the pipe hanger, and attachmen-ts means on said tubular body for a-ttaching the second string of pipe to said tubular body.
The wellhead has a bore of 17-9/16 inches to permit the passage of a standard 17-1/2 inch drill bit. The breech block hanger support with suspended casing is landed and connected to the wellhead for suppor-ting one or more of the other casing hangers within the wellhead and for withstanding and containing -the pressure load within the well. Breech block teeth are provided on the wellhead and the breech block hanger support to permit the hanger support to be s-tabbed into the wellhead and rotated less than 360 for comp:Leting the connection therebe-tween. The breech bloc~ teeth include six groupings of six teeth and are spaced-apar-t - 5a -~.2~3~

no-lead threads. Breech block slots are provided between adjacent ~roupings of teeth to provide a natural flow way for the passage of well fluids. The breech ~lock hanger support includes an upper annular flange for arresting the downward movement of the breech block hanger support within the wellhead. This annular ~la~ge includes flutes aligned with the ~reech block slots for the passage 4~ well fluids. The flutes are more narrow than the breech block slots to prevent the breech block hanger support from passing through the wellhead.
The upper surface of the annular flange provides a bearing surface for supporting one or more of the other casing hangers.
The bearing surface of the hanger support will support the casing and tubing load :in addition to a 15,003 psi working pressure.
The bearin~ surface of the breech block teeth is greater than the bearing surface provided by the annular flang~ of th~ hanger support for the next casing hanger.
The packoff is provided for sealing the breech block hanger support with the wellhead and with the next casing hanger. Th~
pac~off includes means for testing the integrity of the seals of the packoff.
~ fter landing, connecting, sealing, and testing the breech block hanger supp~rt, the next casing hanger with casiny is landed on top of the breech block hanger suppor~. A holddown and sealing assembly is disposed between the wellhead and the next casing hanger to h~lddown and seal the next casing hang~r.
Sec~nd and third casing hangers are subseguently run into th~
well one after another and those hangers are similarly sealed with the wellhead. The breech block hanger support supports the three casing hangers with suspended casing and at the same time, withstands and contains a 15,000 psi working pressure.

Another embodiment of the in~ention includes the extension of the body of the breech bloc){ hanger support where~y a holddown and sealing assembly may be disposed between the breech block .

hanger support an~ the wellhead. ~he~ holddown and sealing assembly ~includes a seal portion having a plurality of fustroconical metal links connected toyether by connector links to form a Z shape.
The adjacent metal links form annular grooves for housing resilient elastomeric members. A tGol is provided-for actuating by torque ~and hydraulic pressure the holddown and sealing assembly to establish a primary metal~to-metal seal and a secondary elastomeric seal between the breech block hanger support and the wellhQad.

BRIEF DESCRIPTION OF THE ~RAWINGS
For a detailed d~scription of the preferred embodiment of the inventio~, 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, 2B, and 2C are section views of the well-head, hanger support ring, casing hanger running tool, pack off and hold down assembly, and i~ schematic of a portion of the blowout preventer for the un~erwater well o Figure l;
Figure 3 is an exploded view of the breech block housing seat and a portion of the wellhead of Fi~ure 2;
Figur~ 3A is an enlarged elevation view of the key shown in Figure 3;
Figure 4 i5 a section view of the sealing element in the running position and ~igure 4A is a section vlew of th sealing element in the sealing position; and Figures 5A, 5B and 5C are section vi~ws 9f th wellhead with th~ casing hangers of the 16~inoh, 13 3/8 inch, 9-5/8 inch and 7 inch casing strings landed and in the hold down position and in the s~aling position.

a DESCRIPTION OF THE PREFERRED EMBODIMENT
The present .invention is a subsea wellhead system for running, supporting, sealing, holding, and testing a casing hanyer wlthin )6~

a wellhead in aIl oil or.gas well. All~ough the present inve~tion may be used in-a variety of-environments, Figure 1 is a diagram-matic illustration of a typical installation of a casing hanger and a casing string of the present invention in a wellhead dis-posed on the ocean floDr of an offsho-re well.
Reerrlng initially to Figure 1, there is shown a well bore 10 drilled into the sea floor 12 below a body of w~ter 14 from a drilling vessel 16 floating at th~ surface 18 of the water. A
base structure or guide base 20, a conductor casing 22, a well~
head 24, a blowout preventer stack 26 with pressure conkrol eauipment, and a marine riser 28 are lowered from floating drill-ing vessel 16 and installed into sea floor 12. Conductor casing 22 may be driven or jetted into the sea floor 12 until wellhead 24 rests near sea floor 12, or as shown ln Figure 1, ~ bore hole 30 may be drilled for the insertion of c~nductor casing 22 Guide base 20 is secured about the upper end of conductor casing 22 on sea floor 12, and conductor casing ~2 is anchored within bore hole 3~ by a column 32 of cement about a substantial portion o its length. Blowout preventer stack 26 is releasahly connected through a suitable connection to wellhead 24 disposed on ~uide base 20 mounted on sea floor 12 and includes one or more blowout preventers such as blowout preventer 40. Such blvwout preventers include a nu~ber of sealing pipe rams, such as pipe rams 34 on blowout prev~nter ~0, adapted to be actuated to and from Whe blowout preventer housing into and from sealing engagement wi~h a tubular member, such as drill pipe, extending through blowout preventer 40, as is well known. Marine riser pipe 28 extends from the top of blowout preventer stack 26 to floating vess~l 16.
Blowout preventer stack .26 includes "choke and kill" lines 3~, 33, respectively, extending t~ the surface 18. Choke and kill lines are used, for among other things, to test pipe rams 34 of blowout preventer 40. In testin~ rams 34, a test plug is run into the well through riser 28 to seal o~.E the well at ~he wellc )60~3~

head 24. The rams 34 are activated .md closed, and pressure is - then applied through kill line 38 with- a valve on choke line 36 closed to test pipe ram 34.
Drilling apparatus, including drill pipe wi~h a sta~dard 17-1/2 inch drill bit, is lowered th~ough riser 28 and conductor ~casing 22 to drill a deeper bore hole 42 in the ocean bottom for surface cas-ing 44. A surfaoe casing hanger 50, shown in Figure 2C
suspending surface casing 44, is lowered through conductor casing 22 until surface casing hanger 50 lands and is connected to wellhead 24 as hereinafter described. Other interior casing and tubing strings are subseguently landed and suspended in wellhead 24 as will be described later with respect to Figures ~A, 5B and 5C.
Referring now to Figure 2C, wellh~3d 24 includes a housing ~6 having a reduced diameter lower end 48 forming a downwardly facing, inwardly tapering conical shoulder 52. Reduced diameter lower end 48 has a reduced tubular po:rtion 54 at its terminus ~orming an~ther smaller downwardly facing, inwardly tapering c~nical sh~ulder 56. Conductor casing 22 is 20 inch (outside diameter) pipe and is welded to reduc~ed tubular portion 54 on the b~ttom of wellhead 24. Conductor casing 22 ha~ a thickness of 1/2 inch and a 19 inch inner diameter internal bore 62 to ini-tially receive the drill string and bit to drill bore hole 4~ and later to receive sur~ace casing string 4~ as shown in Figure 1.
Wellhead housing 46 includes a bor~ 60 having a diameter of approximately 18-11/16 inches, slightly smaller than internal bore 62 of conductor ca~ing 22.
Disposed on the interior of wellhead bore 60 are a plurality of stop notche~ 64, ~reech block teeth 66, a~d four annu~ar yrooves (shvwn in Figure 5B~ such a~ groo~e 68, spaced along bore 60 above breech block teeth 66. Breech block teeth 66 have approximately a 17-9/16 inch internal diameter to permit tne pass through of the standard 17~1/2 inch drill hit to drill bore hole 42.

Wellhead 24 includes a remova~le casing han~er support seat means or breech block housing seat 70 adapted for lowering into bore 60 and connecting to breech bloçk teeth 66. Housing seat 70 includes a solid annular tubular ring 72 having a smooth interior bore 74, exterior bre~ch block teeth-76 adapted for engagement .with interior breech block teeth 66 of wellhead housing 46, an upwardly facing, downwardly tapering conical seat or support shoulder B0 for engaging surfa~e casing hanger 50, and a key assembly 7~ for locking housing seat 70 within wellhead housing 46.
Bore 74 of solid ring 72 has an internal diameter of 16.060 inches providing conical support shoulder 80 with an effective horizontal thickness of approximately 1.3 inches ~o support casing hanger 5~. Housing seat 70 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 well-head 24, because of its 5ize, weight and thickness, i5 a rigid member as compared to housing seat 70 which is a relatively flexible member.
,~s shown in Figure 3, hou~ing seat 70 includes a plurality ~f groupings 82 of segmented teet~ 75 with breech bl~ck slots or spases 86 therebetween for receiving corresponding groupin~s 88 of segmented teeth 66 in wellhead hou~ing 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 70 for connection with wellhead ~4.
Wellhead teeth 66 are taperPd inwardly downward to ~acilitate th~
passage of the bit. If threads 66 were s~uare ~hculder~d or of the buttress type, ~hey might engage the bit as it is lowered through wellhead 24 to drill bore 42 for surface casing 44. .
Shoulder teeth 76 have corresponding tapers to matingly eng~ge wellhead te~th 66. Groupings 82, 8~ each include six rows of sç~me~ted teeth approximately l/2 inch thick from base to .face.

D~

The thread area of ~he six rows of segmented teeth 66, 76 e~ceeds ~he shoulder area of support sht~ulder ~0. A eontinuous upper annular flange 85 on seat 70 dispose~ above teeth 75 limits the insertion of tooth groupings ~2 into spaces 87. Continuous upper annular flange 85 prevents seat 70 from passing through wellhead ~24. Lowermost tooth segmen~ 84 is oversized to prevent a premature rotation of seat 70 within wellhead 24 until seat 70 has landed on annular flange 85.
The six rows or groupings 82, 88 of segmented teeth 66, 76 provide an even mlmber of rows to evenly support and distribute the load. Such design evens out the stresses placed on segmentPd - teeth 66, 76. By having six groupings of teeth, segmented teeth 66, 76 may be connected by rotating housing seat 70 30D, i.e.;
1~0 divided by the number of ~roupin~s. 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 ~6, 76 be equal in length so that a maximum amount of contact will be available to support the loads.
Se~mented teeth 66, 76 may merely be circular grc)oves having slots or spaces 86, 87 for connection. Segmented teet~ 66, 76 have a zero lead ang1e and are tapered to increase the ~hread area so that threads 66, 76 will withstand a greater ~mount of shear stress. The taper of segmented teeth 66, 76 is greater than 30 and preferably is about 55~ whereby the thread area is substantially increased or shear. Thi~ tooth profile attempts to egualize the stresses over all o the segmented teeth 6~, 76 so that teeth 66, 76 do not yield one at a time.
Teeth 6~, 76 may be of the buttress type. A sguarD shoulder on tee~h 66, 76 would catc:h debris and other junk flowing ~hrough the well. An added advantage of the breech block cDnnection between wellhead 24 and housing seat 70 is that ~e~nented teeth 76 clean segmented teeth 66 as housing se~t 70 i5 rotated within wellhead 24. ~eeth 76 kn~ck any debris off teeth 66 so that the debris drops into the breech block slot.s or spaces 86, 87.

~2~ 3~1 ~

Co~tinuous threads have several disadvantages. Ihread~
require multip~e rotations for connection and must be backed up until they drop a fraction of an inch prior to the leads of the threads making initinl engagement. Further, threads ride on a point as they are rot~ted for conneetion. The breech block ^con~ection between housing seat 70 and wellhead 24 avoids these disadvantages. As housing seat 70 is lowered into wellhead 24 on an appropriate running tool, the lowermost tooth segment 84 on seat 70 will engage the uppermost tooth segment of tootn segments 66 on wellhead housing 24. Seat 70 is then rotated less than 30 to permit groupings 82 on seat 70 to be received withi~ slot 87 between groupings 88 on wellhead 24. This drop is substantial, as much as 12 inches, and can easily be se~sed at the surface to insure that housing seat 70 has engage~d wellhead ~4 and can be rota~ed into breech block engagement. Using the breech block connection of the present invention provides a clear indication when housing seat 70 is ~ully engaged with wellhead 24. The breech block connection o~ the presenl: invention has the added advantage of permitting housing seat 70 to b~ stabbed into well-head 24 and made up upon a 30~ rotation of housing seat 70 to accomplish full en~agement between housing seat 7~ and wellhead

2~ .
Referring now to Figures 2C, 3 and 3A, key assembly 78 includes a plurality o outwardly biased do~s 92 each slidingly housed in an vutwardly facing cavity 94 in every other lowermost tooth segme:nt ~34 o:E solid ring 72. Dog 92 has :flat sides 90, upper and lower tapered ~icles 91, and a bore 95 in it~; inner side to receive one end of spring 98. Washers 93 are mounted by screws 95 in cavity 94 on eaeh side of dog 9~ leavin~ a slot for dog 92. Th2 other e~d of spring 98 en~ages the bottom o~ çavity 94 to bias doy 92 outwardly. Stop notch 64 is located beneath all six groupinys ~8 so that dog 92 is positioned on solid ring 72 whereby dog 92 will be adjacent a stop notch 6~ in w~llhead housing 46 upon the complete engagement of interior and exterior ~eeth 66, 76 of wellhead 24 and housing seat ~0. Dog 92 will be biased into notch 64 upon the rotation of ring 72 within threads 66 to thereby stop rotation of ring 7~. An aperture 102 is provided through rin~ 72 and into cavity 94 to permit the release ~of dog 92.
In the-prior art, the support shoulder for the surface casing hanger was integral with the wellhead housing and was large enou~h to support the casing and pressure load. However, this prior art integral support shoulder restricted the bore in the wellhead housing for full bore access to casing below the - wellh~ad housing for drilling. To use a sufficiently large integral shoulder for 15,000 psi working pressures, the bore of the integral shoulder would not pass a standard 17-1/2 inch bit.
Such subsea wellhead system~ required underreaming.
ln the present invention, breech block housing seat 70 is an.
installable support shoulder which n2ed not be installed in wellhead housin~ 46 until greater working pressures are encount-ered. Housing seat 70 is not installed until the drilling opera-tion or surface casing 44 is complete, permitting full bore access. Since only nominal working pressures are encountered during the drilling for t~e surface casing 44, the larger support shoulder is not needed. After completion of the drilling for the surface casing 44, breech block housing seat 70 is installed to handle casing and pressure loads of up to 15,000 psi. Thus, su~ficient clearance is provided prior to installation of housing seat 70 to pass a 17~1/2 inch bit.
To install breeeh block housi~g seat 70, housing seat 70 is connected to a running tool ~not shown) by shear pins~ a port~o~
o~ which are shown a~ 104. The runnin~ tool on a drill string then lowers housing seat 70 into bore 60 of wellhead 24 until lowermost tooth segment 8~ lands on the uppermost tooth se~ment of tooth segments 66. Seat 70 is then rotated until teeth group-in~s B8 on wellh~ad 24 drop into breech block ~lots E~6 and teeth ~ Z~6~

groupings 82 on ring 72 are received :in correspondin~ slots 87 on ~ellhead teeth~66.. Continuous annual 1ange 85 lands on ~he uppermost tooth segment of segments 66 in wellhead 24. ~ousing seat 70 is ~hen rotated by th~ drill string and running tool until keys 78 are engaged in stop notches 64 to stop rotation. A
.~res~sure test may be performed to be sure housing seat 70 is do~. Then shear pins holding housing seat 70 to the running tool are sheared at 104 to release and remove the running tool.
Figure 2C illustrates the landing of surface casing hanger 50 on breech block housing seat 70 within wellhead 24. Casing hanger 50 has a generally tubular body 110 which includes a lower threaded box 112 threadingly engaging the upper joint of casing stri~g 44 for suspending string 44 within borehole 42, a thlcke~ed upper-section 114 having an ~utwardly projecting radial annular shoulder 116; and a plurality of annular groGves 120 (shown in Eigure 2B) in the inner periphery of body 110 adapted for connec-.
tion wi~h a running tool-200, hereinafter described.
Referring now to Figures 2A and 2~, threads 118 are provided from the top down al~ng a substantial length of the exterior of tubular body 110 for engagement with holddown and sealin~ assembly -180, hereinafter described.
The cementing operation for cementing surrace casi~g ~tring 44 into borehole 42 requires a passa~eway from lower annulus 130, between ~urface casing string 44 and conductor casi.ng 22, to upper annulus 134, between wellhead 24 and the drill string 236, tG flow the returns to the ~urfaee. A plurality of upper and lowex flute~ or circulation ports 1~2, 124 are provided thr~u~h upper section 114 to permit fluid flow, such as for the cementing operation, around casi~g hanger 50. Lower flutes 122 provide fluid passageways through radi31 annular shoulder 116 and upper flutes 124 provide fluid passageways through the upper threaded end of tubular body 110 to pass fluids around holddown and sealing assembly 180.

Threads 126 are pr.ovided on the external periphery ~f upper ~ection 114 below annular ~hou~der 116-to threadingly receive and engage threaded ~houlder ring 128 around hanger 50. Shoulder ring 128 has a downwardly facing, upwardly tapering conical face 132 to matingly rest and engage upwardly facing, downwardly ~tapering conical support shoulder 80 on bre~ch block housing seat 70. Casing hanger 50 thus lands on housing seat 79 upon engage-ment of conical face 132 of hanger shoulder ring 128 and housing seat support shoulder 80 whereby housing seat 70 must withstand the resulting casing and pres~ure load.
Wells, having a workins pressure in the range of 15,000 psi, create uni~ue loads on the wellhead supports. Not only must the wellhead support the weight of the çasing hangers with their suspended casing and one or more tubing~hangers with their sus-pended tubing, bu~ the wellhead must withstand and contain the 15,000 psi working pressure. Thus, the wellhead must support both the casing and tubing weight and the pressure load. A
15,000 psi.working pressure wellhead must have sufficient support and bearing ~rea throughout the wellhead design such that the load does not substantially exc~ed the yield strength in vertical ~ompression of the material of the wellhead supports. Although at lower working pressures materials havi~g a 70,000 minimum yield are used, a higher strength yield material with an 85,000 minimum yield is n~rmally used for 15,000 psi wellheads. Con-servatively assuming a 90,000 vertical compressive stress on the wellhead, ~he wellhead of the present invention will support over 6,000,000 lbs. of lvad since the bearing area is in the range of 65 to 70 square inches. Such a bearing area must be consistent throughout the design so that the l~ad does not exceed over 25%
of the material yield strength in vertical compression. The bearing area between the lowermost casing hanger 50 and housing seat 7~, and between housing ~eat 70 and supporting breech block teeth 66 on wellhead 24 must be sufficient to support such loads ~L20~9~

without substantially exceeding their material yield strength i~
~ertical compression, i.e. o~er 25% of-yield strength. Such a design has be~n achieved in the wellhead system of the present invention.
To assure sufficient bearing ~rea between casing hanger 50 ~and~seat 70, hanger shoulder ring 128 has been threaded onto radial a~nular shoulder 116 projecting from upper section 114 of casing hanger body 110. Hanger shoulder ~ing 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 ports 122 through shoulder 116 prevent a 360 bearing area between hanger 50 and housing seat 70. The engage-ment between support shoulder 80 and conical face 132 provides an excess bearing area determined by the wellhead internal diameter of 17-9/16 inches and the internal diameter of housing seat 70 of 16.060 inehes. Thus, th~ bearing area ~etween shoulder 80 and face 132 is approximately 70 square inches permitting such bearing area to support in excess of 6,000,000 lbs. in load.
Interior and ext~rior breech block teeth 66, 76 of wellhead 2~ and housing seat 70 also have been desi~ned to provide su~fi-cient bearing area to support the anticipated load de~cribed abov~. As de~cribed previously, breech block teeth 66~ 76 include six gr~upings 82, 88 of tee~h provided on wellhead 24 and housing seat 70. Each grouping 82, ~8 includes six teeth 66, 76 to support the load. The bearing area of breech block teeth 66, 76 is great2r th~n the bearing area between shouldex ~0 and conical ~ace 132. The number of teeth i 5 determined by the loss of bear~
ing area due to the six spaces 86, 87 for receiving corresponding gr~upings 82, R8 during makeup.
Referring again to Figure 2C, radial annular shoulder 116 projecting from upper section 114 of hanger body 110 h~s an upwardly facing, downwardly and outwardly tapering conical cam ~ ~ .

surface 136 with 2n ann~lar relief sroove 138 extending upwardly ~t its ~ase. An annular chamber 142 extends from the upper side of groove 138 to an annular vertical sealing surface 140 extending from groove 138 to the lower end of threads 118. Radial annular shsulder 116 is positioned below annular - lock groove 68 in well-,head, housing 46 after h2nger 50 is landed within wellhead 24.
Cam surface'136 has its lower annular edge terminating just above the lower terminus of groove 68.
Casing hanger 50 includes a latch ring 144 disposed on radial annular shoulder 116. Latch ring 144 may be a split ring which is adapted to be expanded into wellhead groove 58 for engagement with wellhead ho-~sing 46 to hold and lock down hanger 50 within wellhead 24. Wellhead groove 68 has a base vertical wall 146 with an upwardly tapered wall and a downwardly tapered wall. Latch ring 144 has a base vertic~l ~urface 148 with a downwardly tapered surface of the extent of the upwardly tapered .
wall of groove 68 and an upwardly tape~red surface parallel to ~he downwardly-tapered wall of ~roove 68 whereby upon expansion of latch ring 144, the vertical surface 148 of ring ~44 engages thç
~ertical wall 146 of groove 68. Further, latch ring 144 includes a downwardly facing outwardly and downwardly tapering lower camming face 152 cammingly en~aging upwardly facing camming surface 136 of radial annular shoulder 116, an ir.wardly projecting : - annular ridge 154 received by annular relief gr~ove 13~ in the r~tracted position, and an upwardly and inwardly facing _amming head 156 adapted for camming engagement with holddown and sealing assembly 1~0, hereinafter described. Extending between camming head 156 and annular ridge 154 is ^tapered sur~ace 158 parallel t~
the wall of chamber 142.
Projecting annular ridge 154 is received within ~r~ove a38 of casing hanger 50 to prevent latch ring 144 from being pulled out of groove 138 as casing hanger 50 is run into the well. It is necessary duri.ng the lowerin~ of casin~ h2nger 50 that latch . ~ ~Q ~

ring 144 pa6s several narrow diameters such as in blowout pre-venter ~0. ~lowout preventer 40 often includes a ru~ber doughnut-t~e seal which does not fully retract thereby requirinc3 casin~
hanger 50 to press ~hrough that rubber seal. If annular ridge 154 was not housed in groove 138, latch ring 144 might catch at ~such a narrow diameter and drag along the exterior sur~ace. This mi~ht draw latch ring 144 .rom groove 138 and permit it to slide upwardly around casing hanger 50 until latch ring 144 engages seal. me2ns 210. This would not only prevent the actuation o holddown actuator means 212, but would also prevent the actuation of sealing means 210. Annular chamber 142 provides clearance so that groove 138 can receive annular ridg 154. This profile also provides a step which keeps latch ring 144 from having such an upward load ~s the load is placed on latch ring 144.
-Holddown assembly and ~ealing 180 is shown in Figures 2B and 2C, engaged with running tool 200 and actuated in the holddown p~sition. ~olddown and -sealing assemk~ly 180 include~ a stationary member 184 rotatably mounted on a rotating me~ber or packing nut 182 by retainer means 186. Packing nut 182 has a ring-like body with a lower pin 188 and a castelated upper end 198 with upwardly projecting stops 202. ~he inner diameter surface of nut 182 includes threads 204 threadingly engaging the external threads 118 ~f casing hanger bod~ 110.
Stationary member 184 has a ring liXe body 216 and includes a seal means 210 ~or sealing b tween the internal b~re wall 61 of wellhead ~4 a~d external ~ealing surface 140 of casing hanger 50, and a holddown actuator means 212 for actuati~g latch ring 144 into holddown engagement within groov~ 68 o~ wellhead 24. Ring-like body 216 is a continu~us and inte~ral metal m2mber and i~cludes an upper drive portion 218~ an i~termediate Z porti~n 220, and a lower ~am portion 222.
Vpper drive portion 218 includes an upper counterbore 190 that rotatably receives lower pin 188 of packing nut le,2 . Re~
tainer means lB6 includes inner and outer race~ in counterbose 190 ant~ pin 188 housing-retainer roller cone~ or balls 196.
Retainer means~l~6 oes not ~a-rry any load and is not used for transmitting torgue or thrust rom packing nut 182 to stationary member 184. Bearin~ mea~s 205 is provided above ~ealing means 210 and includes bearing rings 206, ~08 disposed between the .~ot~om of counterbore 190 and the lower terminal enti of pin 188.
Bearing rings 206, 208 have a low coefficient of friction to permit sliding engagement therebetween upon the actuation of holddown actuator means 212 and sealing means 210. Thus, bearing means 205 is utilized to transmit thrust from packing nut 182 to stationary member 184. Retainer balls 196 merely rotatively retain stationary member 184 on packing nut 182.
Holddown actuator means 212 includes lower cam portion 222 having a downwardly and outwardly facing cam suxface 224 (shown in Figure ~) adapteti for camming engagement with camming head 156 of latch ring 144, and upper drive portion 218 and interme-diate Z portion 220 for transmission of thrust from packing nut . .
~82 to lower cam portion 222.
Sealing means ~10 i~cludes Z portion 220 and elastomeric back-up seals 330, 332 which will be described in detail with respec~ ~o Figure 4 hereinafter, ~nd upper drive portion 218 and lower cam portion 2~2 for compressing intermediate Z portion 220.
5ealint3 means 210 is a combination primary metal-to-metal seal and secondary elastomeric seal. ~aving a metal-to-metal seal be the primary seal has the advantage that it will not tend to deteriorate as does an elastomeric seal.
~ olddown and sealing assembly 180 is lowered into the well on casin~ hanger 50 by a runnin~ tool 200. Runnin~ tool 20~
includes a mandrel 230, which is the main ~ody of tool 200, a con~ector body or sleeve 240, a skirt or outer sleeve 250, and an b~,x assen~ly nut 260. Mandrel 230 includes an upper ~ end 232 with internal threads 234 for connection with the lowermost pipe section ~f drill pipe 236 extending to the surface 18 and a lower _ 1 a _ box end 238 also.having internal thre~ds. Above box end 238 is located an annular reduced diameter groove portion 242. Another reduced diameter portion 248 is disposed above groove portion 242 orming an annular ridge 252. ~elow upper ~ end 232 and above i~ ~ . ~ , reduced diameter portion 248 i-s a-third threaded reduced diameter portion 25~ (shown in Figure 2A) having a diameter smaller than that of portions 242 and 248.
Connector body or sleeve 240 includes a bore 246 dimensioned to be telescopically received over annular ridg~ 252 and box end 238. Connector body 240 is telescopingly receiv~d in the annulus formed by mandrel 230 and skirt 250. Ridge 252 includes annular seal groo~es 258, 262 housing 0-rings 264, 266, respectively, for sealing engagement with the inner diameter surface of bore 246.
The t~p end of connector body .240 includes an internally directed radial annular flange 268 havi:ng a sliding fit with the surface ~f reduced diameter p~rtion 248. The lower end ~f 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 274 which engages the upper terminal en~ 276 of casing hanger 50 upon landing running tool ~00, holddown and sealing asse~bly 1~9 on casing hanger 50 withi~ wellhead 2~. Reduced diameter portion 270 has a plurality of circumferentially spaced slots or wind~ws 278 which slidingly hou~e segments or d~gs 280 having a plurality of tee~h 282 adapted t~ be received by grooves 12~ of casing hanger 50 for co~nection of ru~ning tool 2~0 with casing hanger S0. Dogs 280 have an upper projection 284 received within an.
annular groove 286 around the upper inner periphery o~ windows 278. A~sve windows 278 are a plurality o seal ~r~oves 2~8, 2~0 housing ~ rings 292, 294 for sealingly engaging ~he seal bQre 272 of c~sing hanger 50. Adjacent to the upper exterior end of connector body 240 is a snap ring groove 29~ houslng snap ring 298 used in the assembly o~ runnin~ tool 2~0 ~s hereinaft2r )61~

~escribed. Dogs 280 collapse ~ack inko ~roove porti~n 24Z after lower box end 238 is moved to the lower position, as shown, upon the application of tor~ue on tool 200 to set holddown and sealing assembly 180.
SXirt or outer sleeve 250 includes a genPrally tu~ular body ~having an upper inwardly directe~ radial portion 300, a medial portion 302, a transition portion 304, and a lower actuat~r portion 306. Portions 300, 302, 30~ and 306 are contiguous and have dimensio~s to telescopically receive the upper terminal end 276 of casing hanger 50, connector body 240 and mandrel 230.
Lower actuator poxtion 306 has a castilated lower end 308 engaging the upper castilated end 198 of packing nut 182 whereby torgue may be transmitted from running tool 200 to hoiddown and sealing : assembly 1~0. The inner diameter of actuator portion 306 is sufficiently large to clear the outside diametex of threads 118 of casing hanger 50.
Medial portion 302 slidingly receives connector body 240.
Portion 302 includes an internal annular groove 310 ad~pted t~
receive snap rin~ 298 mounted on connector body 240 upo~ disen-gagement of running tool 200 from hol~down and seali~g assembly 180 and casing hanger 5~, 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 grGove 310 to prevent snap ring 298 from engaging groove 310 during the resetting of running tool 200 on another casing hanger.
Snap ring 29~ has an upper cam suxface 316 for engaging the snds of the bo].t~. Once connec:tor body 240 is received i~to the upper portion of the annular ~rea formed ~y outer sleeve 25G and mandrel 230 whereby snap ring 298 is above annular ~roove 310, connector body 24~ cannot be removed without snap ring 298 engaging yroove 310. Thus, to remove cor~ector body 240 upon the resett n~ o~

running tool 200, bolts are threaded lnto bores 312 to cl4Se groove 310 and preven-t grooves 310 from receivin~ and erlcJa~iny ~2~

snap ring 298. This permits connector body 240 to move down-wardly on mancLrel 230 until shouldex 269 engages projection 252 for connection to another casing hanger.
Transition portion 304 adjoins actuator portion 306 and medial portion 302 to compensate for the change in diameters.
Flow ports 318 are provided in transition portion 304 to permit cement returns to pass through outer sleeve 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 for th~ transmission of torque.
Referring now to Figures 2A and 2B, assembly nut 260 has internal threads 324 for a threaded connection at 322 with threads 235 of reduced diameter portion 254 of mandrel 230. The lower terminal face of assembly nut 260 bears against the upper terminal end of outer sleeve 250 to retain outer sleeve 250 on mandrel 230.
In operation, the packing nut 182 is only partially threaded to threads 118 at the top of casing hanger 50 so that mandrel 230 is m~unted in the running position on casing hanger 50. In the running position, annular ridge 252 abuts shoulder 269 formed by radial annular flange 268 on connector body 240.
The outer tubular surface of box end 238 is adjacent to and in engagement wi~h the internal side of dogs 280 whereb~ teeth 282 are biased into grooves 120 of casing hanger 50 preven~ing 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 o~ casing hanger 50 on support shoulder 80 of housing seat 70 in wellhead 24, surface casing 44 is cemented into place within borehole 42.

~2~6~

After the cementing operation is completed, running tool 200 is rotated and torque is transmitted to holddown and seallng assembly - 22a ~.

6g~

180 to actuate holddown and sealing assembly 18~ into the holddown position shown in Figures 2B ~nd 2C. Rotation of drill pipe 236 at the surface 18 caus~ mandrel 230 to rotate which rotates outer sleeve 250 by means of splined connection 320. The torque ~rom outer sleeve 250 is then transmitted to packing nut 182 at ~the~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 holddown actuator means 212 to move into camming engagement with camming head 156 of latch ring 144. Such camming expands latch ring 144 into wellhead groove 68 for engagement with wellhead housing 46 to hold and lock down casing hanger 50 within wellhead 2~ as shown in Figure 2. Sealing ~eans 2~ has not yet been actuated to seal between upper annulus 134 and lower annulus 130.
Latch ring 144 re~uires only a predetermined camming load for actuation and therefore has a predetermined contractual tension.
Sealins 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 1*4 by holddown actuator mea~s 212. I'he load re~uired to compress sealing means 210 is substantially greater than that reguired to expand and actuate latch ring 144. Mandrel 230 moves downwardly with skirt 250 upon the actu2tion of holddown and sealing assembly 1~0. This downward movement of mandrel 230 releases dGgs 280.
For a descripti~n of sealing means 210, reference will now be made to Figures 4 and 4A showing se~lin~ means 210 in the running and holddown positions and the sealing position, respec-- tively. Sealing means 210 includes metal Z portion 220, upper and lower elac~tomeric members 33~, 33~, respectively, and upper drive portion 218 and lower c~m portion 222 for compressing Z
portion 220 and ela~tom~ric members 330, 332. Metal ~nular Z
p~rtion 220 includes a plurality of annular links 334, 336, 338 connected together by annular metal connectox rings 3~.~0, 3~2 and conneçted to upper drivç portion 218 by upper metal connector ng 344 an~ to lower cam portion 222 by lower metal connector ring 346.
Links 334, 336, 338, together with connector rings 340, 342, 344, and 346, provide a posi.tive connective link from bottom to top between lower c~m portion 222 and upper drive portion 218.
This positi~e connective link causes links 334, 336, and 3~8 to move int~ a more angled disengaged position from wellhead 24 and casing hanger 50 upon the retrieval and disengagement of sealing means 210 and actuator means 212 from wellhead 24. Further this positive connective link provides a metal connection extending ~rom drive portion 218 to lower cam portion 22 to permit the application of a positive upward load on lower cam portion 222 upon disengagement. Were it not for ths advantage of ~his retrieval; connector rings 34~, 342, 344, and 346 may not be re~uired.
Connector ri~gs 344-, 346 adjace~t drive portion 218 and cam porti~n 22~, respectively, must have a minimum length tD ensure the sealiny engagement of annular link:s 334 and 338. If c~nnector rings 344, 346 are too short, there will be insufficie.nt bending to allow links 334 and 338 to contact surfaces 61, 140, respec-ti~ely. Because drive portion 218 and cam portion 222 ~re massive in size when compar~d to con~ector rings 3A4, 3a6, the comparati~e massive body of portions 21B, 22~ will not bend so as to permit the sealing engagement of link~ 334, 338. Thus, it is essential ~hat connector ring~ 344, 346 permit such bending. Connector rings 340, 342, 34~, and 346 provide a local high stress contact point ~hroughout metal 7. p~rtion ?20.
The metal 2 portion ~20 is made o a very soft ductile steel such as 316 stainless. Such metal would have a ~ield of approxi mately 40,000 psi. This yield is less than hal~ the yield of approximately 85,000 psi of the material for wellhead 24 and hanger 50. Vpon sealing engagement of metal ~ portion 220, metal Z portion ~20 plastically deforms while surface 61 of wellhead 24 ~2~ 3~

and surface 140 o hanger 50 tends to ela~tically deo~m. Sh~uld ere be any imperfection in surfaces 61, 140, the ductility of the material of annular Z portion 2~0 will permit such material to deform or flow 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 contact with walls 61, 140 of wellhead 24 and casing hanger 50 respectively, upon actuation.
~ pper, intermedlate, and lower annular links 334, 336, 338 respectively, each have a diamond-shaped cross-section. Since the cross-section cf links 334, 335, 338 is substantially the same, a description o~ link 336 shall serve as a description ~f links 334, 338. Annular link 336 includes su~stantially parallel upper and lower annular side~ 348, 35V respectively, with upper ~ide 348 facing generally upward and lower si~e 350 facing gener-ally downward, substantially parallel inner and outer annular sides 352, 35~ respectively, with outer side 352 facing radially outward and inner side 3S4 facing radially inward, and parallel inner and outer annular sealing contact rims 3~6, 358 respectively.
Annular links 334, 33~ have ~omparable upper and lower sides, inner and ~uter sides and inner and outer sealing contact rims.
In the holddown position, the sealing contact rims of link~
334, 336, 338 are deformed substantially parallel with the b~re wall 61 of wellhead housing 46 and the outer wall 140 of casing hanger 50. Upper connector ring 344 extends from the lower and 364 of upper driv~ portion 218 to the upper side 335 of upper link 334 ~o fo~n an annular cha~nel 366. Metal connector ring 340 extends from the lowex 5ide 337 of upper link 334 to upper side 348 of intermediate :Link 336 to form annular channel 368 and metal connector ring 342 extends from lower side 350 of interme-dlate link 336 to the upper side 339 o~ lower link 338 to form annular channel 370. Lower connec-tor rin~ 346 extPnds from the lower ~ide 341 of lower linX 338 t~ the upper end 372 of lower - . -cam portlon 222 to form annular channel 374. ~nnular channels ~66, 368, 370 and 372 betwee~ adjacent ridges assist in achieving ~he bending of Z portion 220 at predetermined locations, namely at connector rin~s 340, 342, 344, and 346. Lower end 364 of dri~e portion 21R is substantially pa~allel with the upper side ~335~o upper link ~34 and upper end 372 of c~l portion 222 is substantially parallel with the lower side 341 o~ lower link 338.
In the running and holddown positions, the outer and inner sealing contact rims have the same diameter as the outer and inner diame-- ters of upper drive portion 218 and lower cam portion 222 respec-tively.
Upper an~ ~vwer elastomeric me~bers 330, 332 are molded to conform to the shapes sf annular grooves 376, 373 formed by links 334, 336, 338 and are bonded to links 334, 33~, 3380 Upper and lowe~ elastomeric members 330, 332 have outer and inner annular vertical sealing surfaces 380, 38~ respectively, adapted for sealingly engaging bore ~all 61 and outer wall 140 in the sealing position. The upper and lower annular xidges formed by sealing surfaces 380, 382 are chamfered to permit deformation i~-to sealin~
position of members 330, 332 upon compression. Elastomeric members 330, 332 are also chamfered to permit a predetermined deformation of members 330, 332 between links 334) 336, 33B.
Although the cross secti~ns 9~ elastomeric memhers 330, 332 are substantially the same, inner elastomeric member 332 may b~
ohamfered or tril~med more ~han outer elastomeric membex 330 to avoid any premature extrusion cf members 330, 332 prior to links 334, 3~6, 338 establishing an anti-extrustion seal wi~h bore wall .
61 of wellhead 24 a~d outer sealing surface 14~ of casing hanger 50.
It is preferred that sealin~ means ~10 include at least three links. This numher is preferred since it provides an anti-extruslon link for each side o elastomeric me~bers 330, 332. Als~, the three links 334, 336, 33~ achieve a s~s~metry of a~
~esign. However, sealing means 210 could include one or more ~links and misht well include:a series of links capturing a plural~
ity of elaskomeric members. Surfaces 364 and 372 of drive portion 218 and lower cam portion 222, respec~ively, would preferably have tapers tapering in ~he same direction as the adjacent link8 such as links 334 and 338 shown in the preferred design.
~e diamond shaped cross section o links 334, 336, 338 permits the mid portion of ~inks 334, 336, 338 to be very rigid.
By having a thick mid-portion, the reduced areas at the ends of links 33a, 336, 338 will become the area which will yield or bend such as that area adjacent to connector rings 340, 342, 3~4, 346.
It is not desirable that links 334, 336, 338 bend or yield at their mid-portion. However, the particular diamond-shaped cross section shown occurs only because of the ease of ~anufacture of that shape. Links 334, 336 and 338 could have a continuous convex or ellipsoidal shape. This shaLpe might be termed frusto-conoidic. This provides a protuberant: center portion. If the cross section of li~ks 334, 33~, 338 were o~ the same thickness, links 334, 336, 338 might tend to bencl or bow at their mid section.
Although it is preferred to have a thi.ckened center portion for links 334, 336, 338 to cont~ol the point of bending at ~he rims for a predetermined plastic deformation and to insure there is no distortion at the center o~ links 334, 336, 338, links 334, 336, 338 may be frustoconical metal rin~s with a cross section of even thickness rather than frustoconoidic rings.
Referring now to Figure~ 4 and 4A, Figure aA illustrates sealing means 210 in the sealing position. Sealing means 210 is compressed as holddown actuator means ~12 reaches the limit of its travel against latch ring 144 and packing nut 1~2 continues its downward movement on t:hreads 118 of casing hanger 50 as shown in Figures 2B and 2C.
O Metal-to-metal sealing means 210 is series actuated from bottom to top. In other words, the lowest a~nular link 338 bends and deforms first upon compression of sealiny means 21C and i5 ~7- .

3iL2~

the first link to initiate sealing contact with surface 61 and surface 140. This series actuation is preferred to limit the drag of upper annular links 334, 336 down surfaces 61, 140 upon actuation if the upper links 334, 336 were to make sealing enga~e-ment prior to lower link 338. It is preferred that there be a ~alanced force applied to upper annular link 334.
Elastomeric members 330, 332 provide the initial seal.
Elastomeric seals 330, 332 engage surfaces 51, 140 prior to the rims of annular links 334, 336, 338 contacting surfaces 61, 140.
- No extrusion of elastomeric seals 330, 332 is to occur past the rims upon the in:itial compression set of a few thousand psi, i.e., 3,000 p~i, of seali~g means 210. Links 334, 336, 338 provide a backup for me~bers ~30 and 332, 2n anti-extrusion means for such members and are a retainer for such members. Therefore, it is desired that the rims o~ links 334, 336, 338 engage suraces 61, 140 prior to the elastomeric members 330 and 332 extruding past the adjacent rims. It is undesirable for such ex~rusion p~st the r.ims to occur prior to the sealing contact of the rims since ~ny elastomeric material between the rims and sur~aces 60, 140 may be detrimental to the sealing engagement o~ links 334, 336, 338. ~hus, as shown and described, the volume of elast~meric material in members 330 and 332 has been calculated and pre~eter-mined 50 that the rims contact surfaces 60, 1~1 prior to any extrusion of members 330, 332.
Link~ 334, 336, 338 are designed to be thin enough to deform into seal~ng engagement upon a compression set of a few thousand psi. Connector rin~s 340, 342, 346 form stress points or weak areas around annular Z portion 220 locating the bending o~ Z
portion 220 at predetermin~ed points to cause the inner and outer rims of Z portion 220 to properly sealingly engage bore wall 61 and outer wall 140. Upon actuation, the rims c~in onto bore wall 61 ~nd outer wall 140 to form ~ metal-to-metal seal between wellhead 24 and casing hanger 50 thereby sealing upper annulus .
~z~

13 from lower annulus ~30 of the well. Sealing means 210 is ~esigned to ensure that there is no fluid channel or leak path between surfaces 61 and 140.
In the sealing position lower link 338 bends at connector ring 346 causing the outer side 343 o~ lower link 338 to move ~down-~ardly and engage upper end 372 of lower cam portion 222.
The taper o~ surface 372 of lower cam portion 222 provides an initial starting deformation angle for lower annular link 338.
Surface 372 also ensures that link 33~ will not become horizontal so as to prevent the disengagement of link 338 upon the removal of sealing means 210. As the lower end 364 of drive portion 218 ~oves downwardly, upper link 334 bends at connector ring 344 causing the inner side 333 of upper link 334 to engage lower end 364 as lower end 364 compressors Z portion 220. Intermediate lir~ 336 moves from its angled position to a more horizontal posit~on. Elastomeric members 330, 332 are compressed between llnks 33~, 336, 338 and sealin~ly engage bore wall 61 and outer --wall 140. The inn~r rims of links 334, 336, 338 make annular sealing ccntacts with outer wall 140 of casing hanger 50 at 380, 382 and 384 and the outer rims Qf links 334, 336, 338 make annular sealing conta~t with bore wall 61 of wellhead ~4 at 386, 388, and 390. ~he seal means 210 thu~ achieves a six point annular metal- -tv-metal ~ealin~ contact: The seali~g contact of the inner and ou'er rims causes links 33~, 336, 338 to become antiextrusion rin~s for elastomeric members 330, 332. Elastomeric members 330, 332 serve a~ backup seals to the metal seals.
As links 334, 336~ 333 move rom their angled position to a r,ore horiæontal po6ition upon actuation, each end or each inner and outer rim of links 33g, 336, 338 move into engagement with bore wall~ 61 and 140. It is not intended that links 334, 336~
338 become horizontal. It i5 esser,tial th2t the inner and outer e rims of links 334, 336, and 338 become biased between ~ore wall 61 of wellhead 24 and outer wall 140 of casiny hang~r 50. The inner and outer rims of each link react from the bearin~ load of ~2~3~

the other. For example, as inner rim 356 of link 336 bears . .
~gainst casing hanger wall~140,- this con~act places a reaction load on outer rim 358 moving outer rim 358 toward wellhead bore wall 61. If each link did not have an opposing rim, the linX
would continue to move downwardly until its side engaged an .ædja,cent link rather than mov~ into sealing engagement with either wall 61 or 140. This bearing against the inner and outer rims necessitates the prevention of any b~ckling or bending in the mid-portion of the link. ~ence, the diamond-shaped cross section requires that the mid-portion of the link be rigid so that it oannot buckle or relieve itself. Further, if links 334, 336, 338 were permitted to become h~ri~ontal, the tolerances between the inside diameter of wellhead 24 and the outside dia-meter of casing hanger 50 would become critical. Also, where links 334, 336, 338 arP not horizontal but at an angle, it is ea~ier to dîsengage Z portion 220 upon extraction of seali~g means 210. Surface 364 ~f drive portion 218 and surface 372 of Lower cam portion 222 are tapered to prevent links 334 and 338 respectively, from becomin~ horizontal~
It should be understood that el~stomeric seals 330, 33~ may not be required where the rims of links 334, 336, 333 suffici~ntly en~aye surfaces 61 of wellhead 24 and 140 of casing hanger 50 to permit hydraulic pressure to be applied in annulus 134. Thus, members 330 and 332 may be eliminated in certain applications where there would be a void between links 334, 336 and 338.
Also, i~ should be understood that members 330 and 332 mQy be replaced by a spacer which would permit a predeterminad ~mount o collapse or def~mation of links 334, 336, 338. As disclosed in the present embodiment, ela~tomeric me~bers 330 ~nd 332 become such a spacer means. Also, the present invention is not limited tG an elastvmeric material. Members 33~ and 332 may be made of other resilient materials such as Grafoil, an all-graphite packin~
material manufactured by DuPont. Grafoil, in partic~tlar~ may be used where fire resistance i5 d~si.red. "Grafoil" is descrlbe~

in the publications "Grafoil - Ribbon-Pack, Universal Flexible Graphite Packing for Pumps and Valves" by F. W. Russell (Precision Produc-ts) Ltd. of Great Runmow, Essex, Enyland, and "Grafoil srand Packing" by Crane Packing Company of Morton Grove, Illinoi~.
It should also be understood that should a metal-to-metal seal not be desired, that channels 368, 370 and 374 might be used to carry eiastomeric material to surfaces 61 and 140 to provide a primary elastcmeric seal rather than a primary metal-to-metal seal as described in the preferred embodiment. Should the elastomeric seals 330, 332 be the primary seals, annular links 334, 336, 338 become the primary backup for elastomeric seals 330/ 332. These links would become energized backup rin~s 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 pre-energized 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 hydraulic pressure. Initially, an initial torque of approximately 10,000 ft.-lbs. is applied to drill pipe 236 at the surface 18. Tongs are used to rotate drill pipe 236 so as to transmit the torque to running tool 200 and then thrust to seal means 210. Parti-cularly, drill pipe 236 rotates mandrel 230 which in turn rotates outer sleeve 250 by means of spline connection 320.
Outer sleeve 250 drives packing nut 182 by means of the castel-lated connection of lugs 198, 308. Packing nut 182 bears ~ -31-against drive portion 28 by transmitting thrust through bearing means 205. Since holddown actuator means 212 has previously reached the limit of lts downward travel against latch ring 144 in moving to the holddown position, seal means 210 and specifi-cally, Z portion 220 are -31a-compressed between drive portion 218 and lower cam portion 22~
-~his torque applies an axial force of approximately 150,000 lbs.
As Z porti~n 220 is compressed between drive portion 218 and lower cam portion 222, elastomeric members 330, 332 become com-pressed be~ween links 334, 336, 338 ~s links 334, 336, 338 move ._intQ a more horizontal p~sition. As such ccmpressio~ occurs, elastomeric members 330, 332 begin to completely fill the groove~
formed betwee~ links 334, 336, 338 housing elastom~ric members 30, 332. The am~unt of elastomeric material of elastomeric members 330, 332 is predetermined such that as links 33~) 336, 338 move into a m~re horizontal p~sition, ~lnks 334, 336, 338 achieve sufficient contact with bore wall 61 of wellhead 24 and outer bore wall 14C of casing.hanger 50 to function as metal anti-extrusion means for preventing the extrusion of elastomeric seals 330, 332. Particularly, the inside annular c~ntact areas 382, 384 prevent the extr~sion of inside elastomeric member 332 and annular contact area-s 386, 3~8 prevent the extrusion of out.side elastomeric member 330. Thus, an initial anti-extrusion seal is achieved by links 334, 336, 338 before elast~meric members 330, 33~ can extrude past their adjac~nt annular sealing c~ntact areas. It is essential that elas.omeric members 330, 332 have the right volume o~ elastomeric material and the proper c~nisu-ration ~o that up~n compression of sealing means 210, metal anti-extrusion contact is achieved before the extrusion of elas-tomeric me~bers 330, 332 past contact areas 382, 3~4, 386, and 38~.
The particular objective of the initial torque is to set elastomeric back up seals 330, 332 and it is not to establish a metal-to-metal seal between surfaces 61, 1~0 of wellhead 24 and casing hanger 50 r~spectively The initial tor~ue is unable to completely actuate the metal~to-metal seal means 210 because of friction los~es in the riser pipe, the blowout prevPnter stack, the drill pipe itsel~, and more particularly, because of various ~%~

thread loads such as at ~hreads 118. Such friction l~sses limit ~he compression load which may be applied to sealing means 210 by drill pipe 236.
~ o achieve the desired compression set of sealing means 210, hydraulic pressure is combined with the tor~ue to set the metal-to-metal seals o sealing means 210. Referring now to Figures 2A
and 2B, blowout preventer 40 is shown schematically and includes rams 34 wi~h kill line 3B communicating with annulus 134 below biowout preventer rams 34. Convention locates kill line 38 below the lowermost ram. Should the choke line 36, for some reason, be the lowermost line in blowout preventer 40, hydraulic pressure would be applied through choke line 36.
In applying pressure through kill line 38 and into annulus 134, it is necPssary t~ seal of annulus 134. Note in Fi~ure 2A
that kill line 38 i5 shown in phase with rams 34, but in actuality is manufactured 9oD out of phase. In doing so, pipe r~ms 34 ar~.
closed to seal around drill pipe 236, O~ring seals 26~, 266 seal between ma~drel 230 and sleev 240, 0-ring seals 292, 294 seal between sleeve 240 and the interior surface 272 of hanger 50 and as discussed above, sealing means 210 provide the initial seal acro~s annulus 134. Thus, hydraulic pressure may be applied : thrDugh Xill line ~8 and into annulus 134.
Because of the corkscrew e~fect caused b~ the application o~
torgue to a drill stri~g such as drill pipe 236, lO,OOD ft-lbs of torque is generally considered to be the most torque that can be transmitted through a drill pipe strin~ in an underwater situation.
In the present invention, a 10,000 ~t-lb tor~ue on drill pipe 236 will establish a seal ~cros~ annulus 134 which would withstand a few thousand psi of hydraulic pressure. This relatively low pressure seal would then permit the pxessurization o annulus 134 to ~urther compress sealing means 210 which in turn increases the O sealing engagement in annulus 134 to withstand additional hydrau-lic pressure. Metal annular Z portion 220 wlth annular links 334, 336, 338, is designed so that annular rin~s 334, 33~, 338 6(;P~

are thin e.nough to establish a metal~to-metal seal in cooperation ~ith elastomeric seals 330, 332 to withstand a hydraulic pressure of a few thousan~ psi upon the applicatisn of a lO,000 ft-lb tor~ue.
In applying pressure on seal means 210, the effective pxes-sure, areas are the diameter of running tool seal 264 l~ss the diameter of-drill pipe 236 and in addition thereto, the a~nular seal area of sealing means 210. Since the annular seal area is fixed for a particular sized wellhead and casing hanger, the principal variable in determining the pressure setting force is the dif~erence in pres~ure area between the running tool seal 264 and drill pipe 236. Thus, this difference may be varied to permit a predetermined compression setting force on seali~g means 210. The difference in diameter may vary, for example, from between 5 inches and 10 inches.
The particular unction of the hydraulic pressure is to provide an axial force capable cf inducing 20,000 psi into the sealing means 210 without exceeding the pressure desi~n limits of the ~pparatus in the wellhead system. The function of the torque on ~ut 182 after hydraulic pressure is applied is to cause nut 182 to follow the travel of sealing means 210 as it moves down under ~orce and prevent its relaxin~ when the hydraulic force is relieved. It is essential that a hi~h torque, i.e. lO,0~0 ft-lbs, be maintained in drill pipe ~36 so that pac~ing nut 182 follows seal means 210 since othe~ise nut 182 mi~t pr~vent the downward movement of sealing means 210. This procedure is repe~ed by gradually and continuously increasing the hydraulic pressure until packing nut 182 has be~n rotated a sufficient number of rotations to insure that a 2Q,OQ0 psi c~mpression set has bee~
achieved by ~ealing means 210.
Runni~g tool 2Q0 is a com~ination tool for applying torque to holddown and sealillg assembly 180 and for assisting in the application of hydraulic pressure to holddown and sealing asse~bly ~.

180. The rotation of drill pipe 236 for the transmission of ~orque via rul~ning tool 200 t~ holddown and sealing mea~s 180 permits an initial sealing engagement of sealing mean~ 210 in annulus 134 between wellhead 24 and hanger 50 whereby hydr~ulic pressure may then be applied to annulus 134 t~ further set sealing mea~s 210. As hydraulic pressure is gradually and continuously increased in annulus 134 through kill line 38~ sealing means 210 is further compressed ints a greater sealing engagement against surface 61 of wellhead 24 and surface 140 of hanger 50. As this sealing engagement increases, sealing means ~10 will seal agai.nst an even greater a~nulus pressure. Thus, pressure through ki~l line 38 may be gradually increased until sealing means 210 has a compression set of approximately 20,000 psi. The hydraulic pressure applied through ~ill line 38 a~d annulus 134 does not exceed the desi~n limits of the system. All systems have a standard working pressure which an operator may not exceed. The .
system of ~he present invention is designed for 15, 000 psi working pressures and thus the hydraulic pressure in annulus 134 to fully actuate sealing means 210 cannot exceed 15,000 psi alth~ugh a 20, 000 psi compression ~et is desired . The pressure invention achiev~s a 20,000 psi compression set of sealing means 210 without applyln~ a hydraulic pressure exceeding 15,000 psi.
As hydraulic pressu~e is gradually increased in annulus 134 t4 achieve a 20,000 psi compression set on sealing means 210, packing nut 182, due to the continuous application ~f the 10,000 ft~lb tor~ue on dri].l pipe 236 which is transmitted to skirt 25~, follows sealing means 210 downwardly in annulus 134 on thread~
20~. Upon the release of the hydraulic pressur~ throu~h kill line 38 and annulus 134, packing nut 182 prevents the release of the 20,000 psi compre~sion set on sealing means 210 due to the engagem2nt of threads 204 with casing hanger 50.
0 It is essential that elastomeric seals 330, 332 are ener-gized into sealing engagement ~ter the application of the initial torque by drill pipe 236. Unless elastomeric members 330, 33~

~16C~

a~e engaged, the applic~tion of hydraulic pressure through kill line 3~ 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 line 38 such as 500 psi. After the initial ~seal is achieved, the application of increasing amounts of hy-draulic pressure will further compress Z portion 220 and elasto-meric mem~ers 330, 332 to increase the metal-to-metal and elasto-meric sealing contact with walls 61, 140. Such increased sealin~
contact will permit the co~tinued increase in hydraulic pressure through kill line 38 for the further actuation of sealing means 210.
The seal actuation means just d~scribed is a simplification of prior art actuator arrangements. Prior art actuatQrs pressure down through drill pipe to actuate an internal porting piston system. A dart seals off the end of the drill pipe bore for the application of pressure through the piston system which in turn applies pressure to the seal. Although such a prior a.rt actuator system could be adapted to the present invention, the arrangement of the present inventi~n has substantial advantages over the prior art.
It may be neces~ary to increase the initial tor~ue applied to drill string 236 after blowout preventer rams 34 have been closed. Although the rubber co~tact of rams 34 with drill pip~
236 does not create the friction loss as would a metal~to metal contact, some additional friction loss will occur. Thus, addi tional torque, i~ possible, may be applied to drill string 236 above the initial torque to overcome such friction loss. However, drill pipe 236 will rotate with rams 34 in the closed position.
The annulus between the riser and drill pipe 236 contains weil fluids which will cause well fluids to be disposed between pipe rams 34 and drill pipe 236 upon closure of b1DWOUt preventer 40.
Thus, it is believed that the 10,000 ft-lb torque will not be substantially reduced. If, due to the particular application, `the friction between pipe rams 34 and drill pipe 236 must be reduGed, a special pipe joint, not shown, may be series connec~d in drill pipe 236 whereby pipe rams 34 en~age a stationary tubular member having a rotating member passi-ng therethrough to transmit ~tor~ue past rams 34. Such a special pipe joint would include ~otating seals between the stationary member and rotating inner member to prevent the passage of fluid.
Referring now to Figur~s 5A, 5B, and 5~, there is shown the complete assembly of wellhead 24 with 16 inch casing hanger 420, 13-3/8 inch casing hanger 50, 9-5/3 inch casing hanger 400, and 7 inch casing hanger 410. Casing hanger 50 is shown in Figure 5B
in the holddown and sealing ~osition described in Figures 1-4 with holddcwn and sealing assembly 180 actuated iIl the holddown and sealing position. 9-5/8 inch casing hanger 400 is shown supported at 402 on top of casing hanger 50. Casing hanger 400 also includes a holddown and sealing assembly 404 comparable to assembly 180 of casing ha~ger 50. 7 inch casing hanger 410 is shown supported at 412 on top of 9-~8 inch casing han~er 400.
Casin~ han~er 410 includes a holddown and sealing assembly 414 comparable t~ that of assembly 180. Figures 5A and 5B show the holddown grooves of wellhead 24, namely holddown gr~ov~ 68 for casing hanger 50, holddown groove 406 or casing hanger 400, and holddown groove 416 for casing hanger 410.
Casing hangers 400 and 410 do not require a shoulder ring such as shoulder ring 128 for casing hanger 50. Since casing hangers 400, 410 ~upport a 5maller load, the amount o~ contact support ~rea required for casing ha~ger 50 is not needed for casing hangers ~00, 410. Hanger 50 requires a 100 per~ent con-tact area which is not re9uired ~or hangers 400, 410. Further, the shoulders on hangers 400, 410 are square a~d shoulder out evenly on top of the supporting hanger.
Fi~ure 5C discloses an alternative embodiment for removable cas:ing hanger support seat means or br~ech block hous1n~ seat 70 ~ho~ in Figure 2C. Referring now to Figure SC, a modified ~reech ~loc;k housing se&t ~20 is shown adapted for lowering into bore 60 and connecting to breech block teeth 66 of wPllhead 24.
In certain areas there are formations below the 2C inch casing which cannot take the pressure of the weight of ~he ~ud usec~ to contain the bottom hole pressure. To prevent the rupture of this formation by the weight of the mud, it becomes necessary to run a 16 inch casing string down through that formation before drilling the bore for the 13-3/8 inch casing. The modified breech block housing seat 420 suspends the 16 inch casing. Thus, breech block housing seat 420 doubles both as a support shoulder for casing hanger 50 and as a casinq hanger fox the 16 inch casing 422.
~ ousing seat 420 includes a solid annular tubular ring 424 an~ a packoff ring 426. Solid annular. tubular ring 424 includes exterior breech block teeth 428 substantially the same as breech block teeth 76 ~escribed with respect to housing seat 70. Ring 424 also has an upwardly facing and tapering conical seat or suppor~ shoulder 430 adapted ~or engagement with packoff ring 426. Ri~g 424 also includes a plurality of keys 432, substan-tially the same as keys 92 shown in Fi~ure 2C, for locking hous-ing seat 420 within wellhead housing 46. Ring 424 is provided with a box end 434 for threaded engagement to the upper pipe section of 16 inch casing string ~22.
The upper portion of ring 424 includes a counterbore 438 for receiving the pin end 440 of packing ring 426. Packing ring 426 includes external threads for threaded engagement with the inter~
nal threads in counterbore 438 o~ ring 424 for threaded connec-tion at ~42. Packing rin~ 426 includes an upwardly facing sup port ~houlder 450 for engagement with the downwardly facinc~ , .houlder 132 of casing han~er 50. 0-ring seals 444 2nd ~46 are housed in annular 0-ring grooves around the upper end o~ packing ring 426 ~or sealing en~agement with bore wall 61 o~ wellhead 24.

36~

Packing ring 426 also includes 0-rings 452, 454 housed in annular ~-ring grooves-above thread ~42 on pin 440 for sealing engagement . with ~he wall of counterbore 438 of ring 424. A test port 456 is provided between 0-rings 452, 454 testing the packoff ring 426.
Since the 16 inch casing strin~-422-must be cemented, hsus ~ing seat 420 has flutes or passageways 435 shown in dotted lines on Figure 5C. Passageways 435 include the natural flow-by of the breech blocX slots, such as slots 86, 87 of housing seat 70 and wellhead 24 shown in Figure 3, and a series of circumfPrentially spaced slots through continuous annular flange 85 aligned above breech ~lock slots ~36, 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, after the cementing, to packoff annulus 134. To test packing ring 426, the rams of the blowout preventer are closed and the running tool is sealed ~elow the test port 456 and annulus 134 is pressuri~-ed..
If there is a leak between wellhead housing 46 and packing ring 4~6 or the packing ring and counterbore 438, it will be impossibla to pressure up annulus 134. Also there will be an increased volume of hydraulic flow into annulus 134 from kill line 38. It is not necessary that packing ring 426 establish a hi~h pressure seal since at this ~tage of the completion of the well, most pressures will be in the range of less than 5,000 psi.
It should be under~tsod that one varying embodiment would include making housing seat 70 and casing hanger 5~ one piece whereby seat 70 and hanger S0 could be lowered and disposed in wellhead 24 on one trip intv the well. Hanger 50, for example, could include breech block teeth for direct engagement with wellhead breech block teeth 66.
~ nother varying embodiment would include extendiTlg the longitudinal length o~ the tubulax ring 424 of housing s~at 4~0 whereby sealing means 210 and/or actuator holddown means 212 could be disposed directly on housinc~ seat 420 and between seat ~;~V6~

~20 and wellhead 24 for.sealing and/or holddown engagement with ~ellhead 24; In such a case, packing rin~ ~26 would no longer be reguired.
Because many varying and different embodiments may be made wi~hln the scope ~f the inventor's concept taught 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 that the details herein are to be interpreted as illustrative and not in a limiting sense. Thus, it should be understood that the invention is not restricted t~
the illustrated and described embodim~nt, but can be modiied within the SGope cf the following claims.

e/1883/A
a

Claims (52)

1. Apparatus including a hanger-support member for supporting at least one pipe hanger within a wellhead of a well, the pipe hanger having a first string of pipe attached thereto, and for suspending a second string of pipe within the well, the wellhead having a plurality of circumferentially spaced-apart groupings of tooth segments projecting into the wellhead bore for engagement with the hanger-support member, said support member including a tubular body received within the wellhead, a plurality of circum-ferentially spaced-apart groupings of tooth segments disposed on the periphery of said tubular body and adapted for releasably engaging the tooth segments of the wellhead, shoulder means on said tubular body adapted for engagingly supporting the pipe hanger, and attachments means on said tubular body for attaching the second string of pipe to said tubular body.

2. Apparatus 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. Apparatus as defined by claim 1 wherein said shoulder means includes a bearing area capable of supporting the load of the pipe hangers and suspended pipe together with the working pres-sure of the well without substantially exceeding the material yield strength in vertical compression of said tubular body.

4. Apparatus as defined by claim 1 wherein said shoulder means includes a bearing area capable of supporting a vertical compres-sive load in excess of six million pounds.

5. Apparatus as defined by claim 1 wherein said shoulder means includes an annular support shoulder having an effective horizon-tal thickness of at least 1.3 inches.

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

7. Apparatus as defined by claim 1 and further including lock means for locking said tubular body within the wellhead.

8. Apparatus as defined by claim 1 and including means for releasably connecting a running tool to said tubular body.

9. The apparatus as defined by claim 1 wherein said groupings of tooth segments on each of said wellhead and tubular body are adapted for threaded engagement with each other upon rotation of said tubular body less than one revolution.

10. The apparatus as defined by claim 1 wherein said releasable engagement between said tooth segments of said wellhead and tubular body is actuated upon a 30° rotation of said tubular body.

11. The apparatus as defined by claim 1 wherein said tooth segments of said tubular body and said tooth segments of said wellhead include breech block teeth.

12. The apparatus as defined by claim 1 wherein said tooth segments of said tubular body and said tooth segments of said wellhead have a profile equalizing the stresses over all of said tooth segments.

13. Apparatus as defined by claim 1 wherein said attachment means includes threads for threadingly engaging the second string of pipe.

14. An apparatus for supporting a hanger suspending a first string of pipe and for suspending a second string of pipe within a borehole, comprising:
a head member;
a hanger-support member telescopically received within said head member and having a bearing area adapted to supportingly engage the hanger, said hanger-support member further having means for threadingly engaging the second pipe string for sus-pending the second pipe string within the borehole;
a plurality of circumferentially spaced-apart groupings of no-lead threads on the inner circumference of said head member and on the outer circumference of said hanger-support member;
the threads on each member being in alignment with the spaces between the threads on the other member upon telescopic insertion of said hanger-support member into said head member, said threads being engaged with each other upon rotation of said hanger-support member to prevent said members from moving axially apart upon the application of an axial force thereon;
whereby said hanger-support member may be engaged with said head member for supporting the hanger and first string of pipe and for suspending the second string of pipe within the borehole.

15. An apparatus for suspending a string of pipe within a well, comprising:
a head member;
a support member having means for attaching said support member to the pipe string for suspending the pipe string within the well;
said support member being insertable into said head member;

tooth means provided on each of said head and support members for engaging one another and releasably connecting said members together on said support member being rotated;
said tooth means comprising a plurality of circumferentially spaced groupings of teeth on the inner periphery of said head member and the outer periphery of said support member, said groupings of said support member being adapted to pass intermedi-ate said groupings of said head member during insertion of said support member into said head member, said teeth of said group-ings of said support member being adapted to engage said teeth of said groupings of said head member upon such rotation of said support member.

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

17. The apparatus as defined by claim 15 wherein said teeth have a zero lead angle and are tapered for increasing the shear area of said teeth.

18. The apparatus as defined by claim 15 wherein said teeth on said support member are spaced so as not to interferingly engage said teeth on said head member upon the rotation of said support member.

19. The apparatus as defined by claim 15 wherein said teeth have a non-square shoulder profile for preventing the accumulation of well debris on said teeth.

20. The apparatus as defined by claim 15 wherein said groupings of teeth include tooth segments whereby upon rotation of said tooth segments into engagement with each other, the rotating tooth segments of said support member clean said tooth segments on said head member.

21. The apparatus as defined by claim 15 wherein said teeth have a tooth profile for equalizing the stresses over all of said teeth.

22. The apparatus as defined by claim 15 wherein said teeth all have an equal length, the number of groupings on said head member equals the number of groupings on said support member, and each of said head and support members has an even number of said groupings, whereby upon engagement, the stresses and loads are evenly distributed between the teeth.

23. The apparatus as defined by claim 15 wherein each of said head and support members includes six groupings of teeth and six spaces between said groupings.

24. The apparatus as defined by claim 15 wherein each of said groupings includes six rows of teeth.

25. The apparatus as defined by claim 15 and including a tooth on said support member having an axial width greater than the other teeth of said support member for preventing a premature threaded engagement of said support member with said head member.

26. The apparatus as defined by claim 15 and including tele-scoped unthreaded areas of cylindrical configuration on each of said head and support members.

27. The apparatus as defined by claim 15 wherein said groupings of teeth on said head member have substantially the same circumferential extent as said groupings of teeth on said support member.

28. The apparatus as defined by claim 15 and including anti-rotation means for preventing relative rotation of said head member and support member upon complete engagement of said teeth on said support member with said teeth on said head member.

29. The apparatus as defined by claim 28 wherein said anti rotation means includes a stop on one of said head member and support member in engagement with the other of said head member and support member.

30. The apparatus as defined by claim 28 wherein said anti-rotation means is effected upon rotation of said support member less than one revolution.

31. The apparatus as defined by claim 28 wherein said anti-rotation means includes a moveable element on one of said head member and support member positioned within a cavity in the other of said head member and support member.

32. The apparatus as defined by claim 31 wherein said support member includes an aperture whereby said moveable element may be moved to allow disengagement of said head member and support member by relative rotation of said head member and support member without relative axial movement, followed by relative axial movement of said support member away from said head member in the absence of relative rotation.

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

34. The apparatus as defined by claim 15 wherein said teeth in each of said groupings are spaced apart axially so that the tooth segments on one of said head member and support member receive said teeth on the other of said head member and support member upon rotation whereby passage of said groupings of teeth on said support member intermediate said groupings of teeth on said head member provides an indication that said teeth are engaged upon rotation of said support member.

35. The apparatus as defined by claim 15 and including a sealing assembly for sealing between said head member and said support member comprising:
a plurality of frustoconical-shaped metal rings stacked in series, each ring alternating in frustoconical taper;
an annular shoulder mounted on said support member;
an actuator member reciprocally mounted on said support member, said annular shoulder and said actuator member having correlative, oppositely disposed 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 of said head member;
actuation means for applying an axial force on said actuator member causing said actuator member to engage said stack of metal rings and move the inner and outer edges of said rings into metal-to-metal sealing engagement with said support member and said head member.

36. The seal assembly as defined by claim 35 wherein said metal rings have a sufficient radial width for the inner and outer edges of said metal rings to interferingly and sealingly engage said support member and said head member and to deform to a larger cone angle.

37. The seal assembly as defined by claim 35 wherein said metal rings are compressed beyond their yield point between said annular shoulder and actuator member.

38. The seal assembly as defined by claim 35 and including annular links between said metal rings, annular shoulder, and actuator member forming a positive connective link between said annular member and said actuator member.

39. The seal assembly as defined by claim 38 wherein said adjacent metal rings form an annular groove for housing an elastomeric seal.

40. The seal assembly as defined by claim 35 and including spacer means disposed between adjacent metal rings.

41. The apparatus as defined by claim 35 and including:
torque transmission means engaging said actuator member to transmit torque and rotate said actuator member;
said actuator member threadingly engaging said support member whereby as torque is transmitted to said actuator member in one direction, said actuator member travels downwardly on said support member a sufficient distance to energize said seal assembly into sealing engagement;
hydraulic means for applying hydraulic pressure to said seal assembly whereby said metal rings of said seal assembly are energized into metal-to-metal sealing engagement with said head member and said support member;
said actuator member following the actuation of said sealing assembly downward on said support member to prevent the release of said sealing assembly upon the removal of the hydraulic pressure.

42. A well apparatus for suspending pipe within a well and for supporting a plurality of stacked pipe hangers suspending pipe within the well, comprising:
a head member;
a support member having a first bearing area adapted to engage the lowermost stacked pipe hanger, said support member being attached to the top pipe section of a pipe string;
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 substan-tially exceed the material yield strength in vertical compression of said support and head members.

43. The well apparatus as defined by claim 42 wherein said head member has a minimum bore of 17-9/16 inches adapted for receiving A standard 17-1/2 inch drill bit to drill the wellbore for the pipe suspended by the lowermost stacked pipe hanger.

44. The well apparatus of claim 42 wherein said head member and support member are made of a high yield strength material having an 85,000 psi minimum yield.

45. The well apparatus of claim 42 wherein said hearing areas are capable of supporting a load in excess of six million pounds.

46. The well apparatus as defined by claim 42 wherein said first bearing area includes a tapered annular shoulder on said support member having a taper angle greater than 30°.

47. The well apparatus as defined by claim 42 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 grooves of said head member.

48. An apparatus for suspending a first pipe string within a well and for supporting a pipe hanger suspending a second pipe string within the well, comprising:
a wellhead member;
a hanger-support member telescopingly received within said wellhead member, said hanger-support member threadingly engaging the upper pipe section of the first pipe string for suspending the first pipe string within the well;
a plurality of circumferentially spaced-apart groupings of no-lead threads on the inner circumference of said wellhead member and on the outer circumference of said hanger-support member;
said groupings of threads on said wellhead member being engaged with said groupings of threads on said hanger-support member upon rotation of the hanger-support member less than 360°, thereby connecting said hanger-support member to said wellhead member;
said hanger-support member having an upwardly facing conical seat;
a packing ring having a lower cylindrical portion and an upper annular shoulder flange, said shoulder flange having a downwardly facing surface for engaging the upwardly facing conical seat;
said cylindrical portion of said packing ring having extern-al threads for threaded engagement with interior threads on said hanger-support member;

seal means for sealing between said hanger-support member and said packing ring;
other seal means for sealing said shoulder flange with said wellhead member;
said packing ring having an upper bearing surface adapted for engagement with the pipe hanger.

49. The apparatus as defined by claim 48 and including means for testing said seal means and said other seal means.

50. The apparatus as defined by claim 49 wherein said seal means includes upper and lower O-rings housed in said cylindrical portion of said packing ring and said testing means includes a test port extending between said upper and lower O-rings.

51. The apparatus as defined by claim 47 and further including flutes extending longitudinally through said tooth means.

52. A method for completing an underwater well comprising the steps of:
(a) locating drilling means at an underwater well site;
(b) installing conductor casing in the floor of a body of water with a wellhead, blowout preventer stack, and riser at-tached thereto at a point near the floor, the riser extending upwardly to the drilling means;
(c) running a drill string and standard 17-1/2 inch drill bit through the wellhead and conductor casing;
(d) drilling a hole for suspending a 16 inch casing within said wellhead and conductor casing;
(e) lowering a hanger seat having a casing string attached thereto into the well until the hanger seat lands in the well-head;

(f) rotating the hanger seat less than 360° to connect the hanger seat within the wellhead;
(g) latching the hanger seat within the wellhead;
(h) drilling a hole for suspending another casing within the wellhead;
(i) running a casing hanger with casing string through the riser and into the wellhead; and (j) landing the casing hanger on the hanger seat.