Note: Descriptions are shown in the official language in which they were submitted.
~ 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.
- 22 -
~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
-32
~%~
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
-33-
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
