Note: Descriptions are shown in the official language in which they were submitted.
12~ S
SUBSEA WELLHEAD SYST-`~
~ BACKGROUND OF THE INVENTION
This invention relates to subsea wellhead systems and more
particularly, to methods and apparatus for supporting, holding
down, and sealing casing hangers within a subsea welLhead.
Increased activity in offshore drilling ~nd completion has
caused an increase in working pressures such that it is antici-
pated that new wells will have a working pressure of as high as
15,000 psi. To cope with the unigue problems associated with
underwater drilling and completion at such increased working
pressures, new subsea wellhead systems are required. Wells
having a working pressure of up to 15,000 psi are presently being
drilled off the coast of Canada and in the North Sea in depths of
over 300 feet. These drilling operations generally include a
floating 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 surface. A quick
disconnect is often located on top of the blowout preventer
stack. An articulation joint is used to allow for vessel move-
ment. Two major pr~blems arise in 15,000 psi workins pressure
subsea wellhead systems cperating in this environment, 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. ~owever, with the
increase in pressure rating and the landing and supporting of
multiple casing strings and tubing strings within the wellhead, a
small support shoulder will not support the load. Althou~h an
obvious answer to the problem would be to merely use a support
shoulder large enough to support the casing and pressure load,
large support shoulders-projecting into the flow ~ore in the
.
wellhead housing for restricted access-to the casing below the ~_
wellhead housing for drilling. In the early days of offshore
drilling, 16-3/4 inch bore subsea wellhead systems required
underreaming. At that time, most floating 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 inch) and the two riser system
reouired up until that time. As wellhead systems moved from
5,000 psi to lO,0~0 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 and containing 15,000 psi
working pressures. Available energy sources for energizing the
sealing means include weight, hydraulic pressure, and torque.
Each sealing means requires different amounts of energy to posi-
tion and energize. Weight is the least 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 need for wireline eouipment to
run and recover darts from ~he hydraulic-to-actuated seal ener-
gization system. If darts are not used, the handling of "wet
strings" of drill pipe is very messy and unpopular with drilling
crews. If the seal energization means uses the single trip
casing hanger technique, the cementing fluid can cause problems
in the hydraulic system used to energize the seal. Maintenance
is also a problem. Although torgue is the most desirable method
to energize a seal, there are limitations on the amvunt of torque
which can be transmitted from the surface due to friction losses
to riser pipe, the blowout preventer stack, off location, various
threads, and the drill pipe itself.
The subsea wellhead system of the present invention overcomes
the deficiencies of the prior art and includes many other advan-
tageous features. The system is simple, has less than 50 parts
2~S
and is ~uitable for ~2S se,rvice. The system has sing~e trip
capability bu~ can still use multiple trip methods. All hangers
are interchangeable with respect to the outer profile so that
they can be run in lo~er positions. The seal elements are inter-
changeable'and are fully energized to a pressure in excess of the
anticipated wellbore pressure. Back-up seals are available. The
seals are not pressure de-energized. The hangers can be run
without lock downs and the seal elements will seal even if the
hange~ lands high.
The housing support seat supports in excess of 6,000,000
lbs. (working pressure plus casing weight or test pressure)
without exceeding 150% of material yield in compression. The
wellhead will pass a 17~ inch diameter bit. The present
invention d~es 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 during 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 it
drag snap rings down the bore.
The hanger hold down will hold down 2,000,000 lbs. The
hanger hold down is positively mechanically retracted when re-
trieving the casing hanger body and is compatible with single
trip operations. ~he hanger hold down is released for retrieval
of the casing hanger when the seal element is retrieved. The
hanger hold down is compatible with multiple trip operations and
permits the running of the hanger with or without the hold down.
The sealing means will work even if the hold down is not used.
The hanger hold down is reusa~le and has a m; ni ml~m number of
tolerances to stack up between hold down grooves.
The sealing means of the present invention will reliably
seal an annular area of approximately 18-1/2 inch outside di~meter
by 17 inch inside di~meter and provide a rubber pressure in
excess' of 15,000 psi (20,000 psi nominally) when the sealing
means is energized and the sealing means sees a pressure from
-3-
s
above ~r below of 1~,000 psi. The pressure in excess of 15,000
~ . - . .
psi is retained in the sealing 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
wili not be pressure de-energized. The sealing means provides a
relatively long seal area to bridge housing defects and/or trash.
Further, 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 from the walls prior to retrieving the sealing means.
The elastomeric seals of the sealing means are allowed to relax
during 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
allows for single trip operations. There are no intermittent
metal parts in the seal area to give irregular rubber pressures.
The sealing means provides a minimum number of seal areas in
parallel to minimize leak paths. The sealing means is positively
attached to the packing element so that it cannot be washed off
by fl~w during the running operations. The design also allows
for multiple trip operations and is interchangeable for all
casing hangers within a nominal size.
The means to load the sealing means reliably provides a
force to energize the sealing means to a nominal 20,000 psi. It
allows full circulation if used in a single trip. H~wever, the
loading means is compatible with either a single trip operation
or multiple trip operation. Further, it is interc~.angeable for
all casing hangers within the wellhead system. The loading means
will cause the sealing means to seal even if the casi~g hanger is
set high. Further, it does not release any significant amount of
the full pressure load after actuation. The loading means does
not require a remote engagement of hold down threads. Fur~her,
.
it has no shear pins. The loading means is reusable and does not
have to remotely engage hold down threads on packing nut replace-
ment.
The casing hanger running tool includes a connection between
the running tool and casing hanger which will support in excess
if 700,000 lbs. of pipe load. The running tool is able to gene-
rate 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 tor~ue. The running
tool can be run on either casing or drill pipe.
Other object~ and advantages of the invention will appear
from the following description.
S~JMMARY OF THE INVENTION
The present invention relates to a subsea wellhead assembly
particularly useful for offshore wells having a working pressure -
in the range of lS,OOO psi. The wellhead assembly generally
includes a wellhead, a housing seat for supporting the casing and
pressure load, a casing hanger for suspending casing within the
well, a holddown an~ sealing assembly for locking the casing
hanger to the wellhead and for sealing the annulus created by th~
casing hanger and wellhead, a running tool for lowering the
casing hanger into the wellhead and for initially actuating the
holddown and sealing assembly, and other related apparatus for
applying hydraulic pressure to the holddown and sealing assembly
for achieving a compression set of the holddown and sealing
assembly in ~xcess of the working pressure of the well. ~he
wellhead is adapted to receive other casing hangers stacked one
on top of another, and to hold down and seal such other casing
hangers within the wellhead.
The wellhead has a through bore of 17-9/16 inches to permit
the passage of a standard 17-1/2 inch drill bit. To provide a
bearing surface for supporting a casing hanger and pressure load
_5_
within the wellhead~ the housing seat 15 landed and connected to
the wellhead. Breech block teeth are provided on the wellhead
and housin~ seat to permit the housing seat to be stabbed into
the wellhead and rotated less than 360 for completing the connec-
tion therebetween. The breech block teeth include six groupings
of six teeth. The teeth are spaced-apart no-lead threads. The
bearing surface of the breech block teeth is greater than the
bearing surface provided by the housing seat for the casing hanger.
The bearing surface of the housing seat will support the casing
and tubing load in addition to the 15,000 psi working pressure.
The casing hanger includes an annular shoulder having flutes
for the passage of well fluids. A releasable seat ring is threaded
to the casing hanger shoulder to provide a full 360~ circumferen-
tial engagement with the hanger seat to support the casing and
tubing weight and the pressure load. A latch member is disposed
above the casiny hanger shoulder and adapted fsr expansion into a
lockdown groove in the wellhead.
The holddown and sealing assembly is disposed around the
casing hanger and above the latch member and casing hanger shoul-
der. The holddown and s~aling assembly includes a rotating
member rotatably supporting a stationary member. The stationary
.. .. .
member includes an upper actuator portion rotatably mounted on
the rotating member, a medial seal portion having a primary
metal-to metal seal and a secondary elastomeric seal for sealing
the annulus, and a lower cam portion for actuating the latch
member.
The seal portion includes a plurality of frustoconical metal
links connected together by connector links so as to form a Z
shape. This Z-shaped portion is connected to the upper actuator
portion and lower cam portion by connector links so as to provide
a positive connective link between the upper actuator portion and
the lower cam portion. The adjacent metal links form annular
grooves for housing resilient elastomeric members.
-6-
The rotating member is threadingly engaged to the casing
hanger whereby as the rotating~member i-s rotated on the casing
hanger, the rotating member moves downwardly causing the station-
ary member to also move downwardly within the annulus. Initially,
the lower cam portion cams the latch member into the lockdown
- -~roove of the wellhead to lock the casing hanger within the
wellhead. Eurther rotation of the rotating member compresses the
medial seal portion of the stationary me~oer. Initially, as the
Z portion deforms, the metal links compress the elastomeric
members into sealing engagement with the wellhead and casing
hanger. Further compression of the Z portion causes the metal
links to bend and deform adjacent the connector links so as to
establish a metal-to-metal seal between the casing hanger and
wellhead. The metal links are made of a ductile material having
a yield of less than one-half the yield of the material of the
wellhead and casing hanger such that the ductile material of the
Z portion deforms filling the peaks and valleys of the imperfec-
tions in the surfaces of the wellhead and casing hanger.
The running tool for lowering and landing the casing hanger
includes a skirt engaging the rotating member of the holddown and
sealing assembly for the transmission of torgue thereto, a mandrel
connected to a string of drill pipe, and a sleeve telescopingly
received between the skirt and mandrel. The sleeve includes
latches biased into engagement with the casing hanger by the
mandrel in an upper position. After the holddown and sealing
assembly is actuated, the mandrel is moved downwardly to unbias
the latches and then lifted upwardly to engage the sleeve with
the skirt such that the latches are cammed out of engagement with
the casing hanger. Seals are provided between the running tool
and the casing han~er.
~he holddown and sealing assembly is initially actuated by
- rotation of the running tool via the drill pipe. To further
actuate the seal of the holddown and sealing assembly, blowout
preventor rams are actuated to seal with the drill pipe. Hydraulic
--7--
pressure is applied below the blowout preventer to apply hydraulic
pressure to the running tool and the halddown sealing assembly.
As the seal o~ the holddown and sealing assembly is further
compressed, the rotating member of the holddown and sealing
assembly travels further downwardly Oh the casing hanger as
~ -continued torque is applied to the drill pipe. Once the desired
compression set of the seal of the holddown and sealing assembly
is achieved, the hydraulic pressure is removed and the rotating
member of the holddown and sealing assembly prevPnts the seal of
the holddown and sealing assembly from releasing any of its
sealing engagement. It is one object of the present invention to
achieve a compression set of the seal of the holddown and sealing
assembly which is greater than the working pressure of the well.
Upon removing the running tool, a second casing hanger with
casing is landed on top of the first casing hanger. A like
holddown and sealing assembly, similarly actuated, is disposed
between the wellhead and the second casing hanger to holddown and
seal the second casing hanger. A ~hird casing hanger is then run
into the well on top of the second casing hanger and similarly, a
holddown and sealiDg assembly is actuated to holddown and seal
the third casing hanger. Thus, the hanger seat supports the
three casing hangers and suspended casing and at the same time,
withstands and contains the 15,000 psi working pressure.
BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed description of the preferred embodiment of
the invention, reference will now be made to the accompanying
drawings wherein:
Figure 1 is a schematic view of the environment of the
present invention;
Figures 2A, 2B, and 2C are ~ection views of the well-
head, hanger support ring, casing hanger running tool, pack
off and hold down assembly, and a schematic of a portion of
the blowout preventer for the underwater well of Figure 1;
- --8--
3S
Eigure 3 is an exploded view of the breech block housing
seat and a portion of the wellhead of Figure 2,
Figure 3A is an enlarged elevation view of the key
shown in Figure 3;
Tigure 4 is a section view of the sealing element in
the running position and Figure 4A is a section view of the
sealing element in the sealing position; and
Figures 5A, 5B and 5C are section views of the wellhead
with the casing hangers of the 16-inch, 13-3/8 inch, 9-5/8
inch and 7 inch casing strings landed and in the hold down
position and in the sealing position.
DESCRIPTION OF THE PREFERRED EMBODIMENT
The present invention is a subsea wellhead system for running,
suppoxting, sealing, holding, and testing a casing hanger within
a wellhead in an oil or gas well. Although the present invention
may be used in a variety o environments, Figure 1 is a diagram-
matic illustratlon of a typical installation of a casing hanger
and a casing string of the present invention in a wellhead dis-
~osed on the ocean floor of an offshore well.
Referring initially to Figure l, there is shown a well bore
10 drilled into the sea floor 12 below a body of water 14 from a
drilling vessel 16 floating at the 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 control
e~uipment, 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 in Figure l, a bore hole
30 may be drilled for the insertion of conductor casing 22.
Guide base 20 i5 secured about the upper end of conductor casing
22 on sea floor 12, and conductor casing 22 is anchored within
bore hole 30 by a column 32 of cement about a substantial portion
of its length. Blowout pre~enter stack 26 is releasably connected
~r
21~2~8S
through a ~uitaDle connection to wellhead 24 disposed on guide
base 20 mounted on sea fioor 12 and includes one or more blowout
preventers such as blowout preventer 40. Such blowout preventers .
include a nu~ber of sealing pipe rams, such as pipe rams 34 on
blowout preventer 40, adapted to be actuated to and from the
blowout preventer housing into and from sealing engagement with a
tubular member, such as drill pipe, extending through blowout
preventer 40, as is well known. Marine xiser pipe 28 extends
from the top of blowout preventer stack 26 to floating vessel 16.
Blowout preventer stack 26 includes "choke and kill" lines
36, 38, respecti~ely, extending to the surface lB. Choke and
kill lines are used, for among other things, to test pipe r~ms 34
of blowout preventer 40. In testing rams 34, a test plug is run
into the well through riser 28 to seal off the well at the well-
head 24. The rams 34 are activated and closed, and pressure is
then applied through kill line 38 with a valve on choke line 36
closed to test pipe rams 34.
Drilling apparatus, including drill pipe with a standard
17-l/2 inch drill bit, is lowered through riser 28 and conductor
casing 22 to drill a deeper bore hole 42 in the ocean bottom for
surface casing 44. A surface casing hanger 50, shown in Figure 2C
susp~n~ing surface casing 44, is lowered through conductor casing
22 until surface casing hanger 50 lands and is connected to
wellhead 2~ as hereinafter described. Other interior casing and
tubing strings are subsequently landed and suspended in wellhead
24 as will be described later with respect to ~igures SA, SB and
5C.
38~
bottom of wellhead 24. -~.onductor casing 22 has 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 42 and
later to receive surface casing string 44 as shown in Figure 1.
Wellhead housing 46 includes a bore 6~ having a diameter of
- -~ppr~ximately 18-11/16 inches, slightly smaller than internal bore
62 of conductor casing 22.
Disposed on the interior of wellhead bore 60 are a plurality
of stop notches 64, breech block teeth 66, and four annular
grooves (shown in Figure 5B) such as groove 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 the
pass through of the standard 17-1/2 inch drill bit to drill bore-
hole 42.
Wellhead 24 includes a removable casing hanger support seat
means or breerh block housing seat 70 adapted for lowering into
bore 60 and connecting t-o breech block teeth 66. ~ousing seat 70
includes a solid annular tubular ring 72 having a sm~oth interior
bore 74, exterior breech 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 80 for engaging surface casing hanger 50, and a key
assembly 78 for locking housing seat 70 within wellhead housing
46.
Bore 74 of solid ring 72 has an internal diameter of 16.060
inches providing coni~al support shoulder 80 with an effective
horizontal thickness of approximately 1.3 inches to support
casing hanger 50. 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 size, weight and thickness, is a rigid
member as compared to housing seat 70 which is a relatively
flexible member.
1;Z~;Z1~5
As shown in Figure 3, housiL~ seat 70 includes a~plurality
of groupings 82 of segmented teeth 76 with breech ~lock slots or
spaces 86 therebetween for receiving corresponding groupings 88 -
of segmented teeth 66 in wellhead housing 46 shown in Figure 2C.
Segmented teeth 66, 76 may or may not have leads, but preferably
~ -~are~no-lead teeth. Teeth 66, 76 are not designed to interferingly
ensage upon rotation of seat 70 for connection with wellhead 24.
Wellhead teeth 66 are tapered inwardly downward to facilitate the
passage of the bit. If threads 66 were square shouldered or of
the buttress type, they might engage the bit as it is lowered
through wellhead 24 to drill bore 42 for surface casing 44.
~houlder teeth 76 have corresponding tapers to matingly engage
wellhead teeth 66. Groupings 82, 88 each include six rows of
segmented teeth approximately 1/2 inch thick from base to face.
The thread area of the six rows of segmented teeth 66, 76 exceeds
the shoulder area of support shoulder 80. A continuous upper
annular flange 85 on seat 70 disposed above teeth 76 limits the
insertion of tooth groupings 82 into spaces 87. Continuous upper
annular flange 85 prevents seat 70 from passing through welihead
24. Lowermost tooth segment 84 is oversized to prevent a premature
rotation of seat 70 within wellhead 24 until seat 70 has landed
on annular flange 85.
The six rows or groupings 82, 88 of segmented teeth 66, 76
provide an even number of rows to evenly support and dlstribute
the load. Such desic~n evens out the stresses placed on segmented
teeth 66, 76. By having six groupings of teeth, segmented teeth
66, 76 may be connected by rotating housing seat 70 30, i.e.,
180~ divided by the number of groupings. Should segmented teeth
66, 76 be longer in length, a greater degree of rotation of
housing seat 70 would be required for connection. It is pre~erable
that segmented teeth 66, 76 be equal in length so that a maximum
amount of contact will be available to support the loads.
r
12(~
Segmented teeth 66, 76 may merely be circular grooves having
slots or spaces 86, 87 for connection. Segmented teeth 66, 76
have a zero lead angle and are tapered to increase the thread
area so that threads 66, 76 will withstand a greater amount of
shear str~ss. The taper of segmented teeth 66, 76 is greater
~than 30 and preferably is about 55 whereby the thread area is
substantially increased for shear. This tooth profile attempts
to equalize tha stresses over all of the segmented teeth 66, 76
so that teeth 66, 76 do not yield one at a time.
Teeth 66, 76 may be o~ the buttress kype. A square shoulder
on teeth 66, 76 would catch debris and other junk flowing through
the well. An added advantage of the breech block connection
between wellhead 24 and housing seat 70 i5 that segmented teeth
76 clean segmented teeth 66 as housing seat 70 is rotated within
wellhead 24. Teeth 76 knock any debris off teeth 66 so that the
debri 5 drops into the breech block slots or spaces B6, 87.
Continuous threads have several disadvantages. Threads
require multiple rotations for connection and must be backed up
until they drop a fraction of an inch prior to the leads of the
threads making initial engagement. Further, threads ride on a
point as they are rotated for connection. The breech block
connection 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 B4 on
seat 70 will engage the uppermost tooth segment of tooth segments
66 on wellhead housing 24. Seat 70 i5 then rotated less than 30
to permit groupings 82 on seat 70 to be received within slot 87
between groupings B8 on wellhead 24. This drop is substantial,
as much as 12 inches, and can easily be sensed at the surface to
insure that housing seat 70 has engaged wellhead 24 and can be
rotated into breech block engagement. Using the breech block
connection of the present invention provides a clear indication
when housing seat 70 is fully engaged with wellhead 24. The
breech block connection of the present invention has the added
120;~
advantage of permitting housing seat 70 to be stab~ed into well-
head 24 and made up upon a 30 rotation of housing seat 70 to
accomplish full engagement between ~ousing seat 70 and wellhead
24.
Referring now to Figures 2C, 3 and 3A, key assembly 78
includes a plurality of outwardly biased dogs 92 each slidingly
housed in an outwardly facing cavity 94 in every other lowermost
tooth segment 84 of solid ring 72. Dog 92 has flat sides 90,
upper and lower tapered sides 91, and a bore 96 in its inner side
to receive one end of spring 98. Washers 93 are mounted by
screws 95 in cavity 94 on each side of dog 92 leaving a slot for
dog 92. The other end of spring 98 engages the bottom of cavity
94 to bias dog 92 outwardly. Stop notch 64 is located beneath
all six groupings 88 so that dog 92 is positioned on solid ring
72 whereby dog 92 will be adjacent a stop notch 64 in wellhead
housing 46 upon the complete engagement of interior and exterior
teeth 66, 76 of wellhead 24 and housing seat 70. Dog 92 will be
biased into notch 64 upon the rotation of ring 72 within threads
66 to thereby stop rotation of ring 72. An aperture 102 is
provided through ring 7Z 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 enough 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
wellhead housi~g 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~ inch bit.
Such subsea wellhead systems required underreaming.
In the present invention, breech block housing seat 70 is an
installable support shoulder which need not be installed in
wellhead housing 46 until greater working pressures are encount-
ered. ~ousing seat 70 is not installed until the drilling opera-
tion for surface casi~g 44 is complete, permitting full bore
access. Slnce only nominal working pressures are encounter~l
during the drilling for the surface ca~ing 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,
- ~sufficient clearance is provided prior to installation of housing
seat 70 to pass a 17-1/2 inch bit.
To install breech block housing seat 70, housing seat 70 is
connected to a running tool (not shown) by shear pins, a portion
of which are shown at 104. The running tool on a drill string
then lowers housing seat 70 into bore 60 of wellhead 24 until
lowermost tooth segment 84 lands-on the uppermost tooth segment
of tooth segments 66. Seat 70 is then rotated until teeth group-
ings 88 on wellhead 24 drop into breech block slots 86 and teeth
groupings 82 on ring 72 are received in corresponding slots 87 on
wellhead teeth 66. Continuous annual flange 85 lands on the
uppermost tooth segment-of segments 66 in wellhead 24. Housing
seat 70 is then rotated by the drill string and running tool
until keys 78 are engaged in stop notches 64 to stop rotation. A
pressure test may be performed to be sure housing sea~ 70 is
down. 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
string 44 for suspending string 44 within borehole 42, a thickened
upper-section 114 having an outwardly projecting radial annular
shoulder 116, and a plurality of annular grooves 12~ (shown i.n
Figure 2B) in the inner periphery of body 110 adapted for connec-
tion with a running tool 200, hereinafter described.
Refer~ing now to Figures 2A and 2B, threads 118 are provided
from the top down along a substantial length of the exterior of
I
tubular body 110 for engagement with holddown and sealing assembly
.. . . . . . ........... . .
180, hereinafter described;
The cementing operation for cementing surface casing string
44 into borehole 42 requires a passageway from lower annulus 130,
between surface casing string 44 and'conductor casing 22, to
- ~upper annulus 134, between wellhead 24 and-the drill string 236,
to flow the returns to the surface. A plurality of upper and
lower flutes or circulation ports 122, 124 are provided through
upper section 114 to permit fluid flow, such as for the cementing
operation, around casing hanger 50. Lower flutes 122 provide
fluid passageways through radial 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 provided on the external periphery of upper
section 114 below annular shoulder 116 to threadingly receive and
engage threaded shoulder 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 breech block housing seat
70. Casing hanger 50 thus lands on housing seat 70 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 pressure load.
Wells, having a working pressure in the range of 15,000 psi,
create unique loads on the wellhead supports. Not only must the
wellhead support the weight o~ the casing hangers with their
suspended casing a~d o~e or more tubing hangers with their sus-
pended tubing, but the wellhead must withstand and contain t~e
15,000 psi working pressure. m us, the wellhead must suppor,t
both the casing and tubing weight and the pressure load. A
15,000 psi wor~ing pressure wellhead must have sufficient support
and bearing area throughout the wellhead design such that the
load does not subs~antia-lly exceed the yield strength in vertical
, . . .
compression of the material of the wellhead supports. Although
at lower working pressures materials having a 70,000 minimum
yield are used, a hlgher strength yield material with an 85,000
minimum yield is normally used for 15;000-psi wellheads. Con- -
~ ~servatively assuming a 90,000 vertical compressive stress on thewellhead, the wellhead of the present invention will support over
6,000, oob lbs. of load 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 load 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 70, and between housing seat 70 and supporting breech block
teeth 66 on wellhead 24 must be sufficient to support such loads
without substantially exceeding their material yield strength in
vertical compression, i.e. over 25% of yield strength. Such s
design has been achieved in the wellhead system of the present
invention.
To assure sufficient bearing area between casing hanger 50
and seat 70, hanger shoulder ring 12~ has been threaded onto
radial annular shoulder 116 projecting from upper section 114 of
casing hanger body 110. Xanger shoulder ring 128 provides a 360
conical face 132 for engasing 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 i~ches. Thus, the bearing area between shoulder 80 and
face 132 is approximately 70 s~uare inches permitting such bearing
area to support in excess of 6,000,000 lbs. in load.
-17-
iz~
Interior and exteri~r breech block teeth 66, 76 of welihead
24 and housing seat 70 also-have been designed to provide suffi-
cient bearing area to support the anticipated load described
above. As described previously, breech ~lock teeth 66, 76 include
six groupings 8~, 88 of teeth provide~ on-wellhead 24 and housing
- -seat~70. Each grouping 82, 88 includes six teeth 66, 76 to
support the load. The bearing area of breech block teeth 66, 76
is greater than the bearing area between shoulder 80 and conical
face 132. The number of teeth is determined by the loss of bear-
ing area due to the six spaces 86, 87 for receiving corresponding
groupings 82, 88 during makeup.
Referring again to Figure 2C, radial annular shoulder 116
projecting from upper section.ll4 of hanger body llO has an
upwardly facing, downwardly and outward~y tapering conical cam
surfac~ 136 with an annular relief groove 138 extending upwardly
at its base. An annular chamber 1~2 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
shoulder 116 is positioned below annular lock groove 68 in well-
head housing 46 after hanger 50 is landed within wellhead 24.
Cam surface 136 ha6 its lower annular edge terminating just above
the lower terminus of groove 68.
Casing hanger ~0 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 68 for
engagement with wellhead housing 46 to hold and lock down hanger
50 within wellhead 24. Wellhead groove 68 has a base vertical
wall 146 with a~ upwardly tapered wall and a downwardly tapered
wall. Latch ring 144 has a base vertical surface 148 with a
downwardly tapered surface of the extent of the upwardly ta~ered
wall of ~roove 68 and an upwardly tapered surface parallel to the
downwardly tapered wall of groove 68 whereby upon expansion of
latch ring 144, the vertical surface 148 of ring 144 engages the
-18-
1~0~
vertical wall 146 of gr~ove 68. Further, latch ring 144 includes
a downwardly facing outwardly and downwardly tapering lower
camming face 152 cammingly engaging upwardly facing C~m~; ng
surface 136 of radial annular shoulder 116, an inwardly projec'ing
annular ridge 154 received by annular reIief groove 138 in the
~ --retracted position, and an upwardly and inwardly facing camming
head 156 adapted for camming engagement with holddown and sealing
assem~ly 180, hereinafter described. Extending between camming
head 156 and annular ridge 154 is tapered surface 158 parallel to
the wall of chamber 142.
Projecting annular ridg~ 154 is received within groove 138
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 during the lowering of casing hanger 50 that latch
ring 144 pass several narrow diameters such as in blowout pre-
venter 40. Blowout preventer 40 often includes a rubber doughnut-
type seal which does not fully retract thereby requiring casing
hanger 50 to press through that rubber seal. If annular ridge
154 was not housed in groove 138, latch ring 144 might catch at
such a narrow diameter ~nd drag along the exterior surface. This
might draw latch ring 144 from groove 138 and permit it to slide
upwardly around casing hanger 50 until latch ring 144 engages
seal means 210. This would not only prevent the actuation of
holddown actuator means 212, but would also prevent the actuation
of sealing means 210. Annular chamber 142 provides clearance so
that groove 138 can recei~e annular ridge 154. This profile also
provides a step which keeps latch ring 144 from having such an
upward load as the load is placed on latch ring 144.
Holddown assembly and sealing 180 is shown in Figures 2B and
2C, engaged with running tool 200 and actuated in the holddo~n
position. Holddown and sealing assembly lRO includes a stationary
member 184 rotatably mounted on a rotating member or packing nut
182 by retainer means 186. Packing nut 182 has a ring-like body
1~ 5
with a lower pin 188 and a castelated upper end 198 with upwardly
projecting stops 202. The inner diameter surface of nut 182
includes threads 204 threadin~ly engaging the external threads
118 of casing hanger body 110.
Stationary member 184 has a ring-like body 216 and includes
- ~a soal means 210 for sealing between the internal bore wall 61 of
wellhead 24 and external sealing surface 140 o casing hanger 50,
and a holddown actuator means 212 for actuating latch ring 144
into holddown engagement within groove 68 of wellhead 24. Ring-
like body 216 is a continuous and integral metal member and
includes an upper drive portion 218, an intermediate Z portion
220, and a lower cam portion 222.
Upper drive portion 218 includes an upper counterbore 190
that rotatably receives lower pin 188 of packing nut 182. Re-
tainer means 186 includes inner and outer races in counterbore
190 and pin 188 housing retainer roller cones or balls 196.
Retainer means 186 does not carry any load and is not used for
transmitting torque or thrust from packing nut 182 to stationary
member 184. Beari~g means 205 is provided above sealing means
210 and includes bearing rings 206, 208 disposed between the
bottom of counterbore 190 and the lower terminal end of pin 188.
Bearing rings 206,.208 have a low coefficient of friction to
permit sliding engageme~t 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 surface 224 (shown
in Figure 2A) adapted 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
182 to lower cam portion 222.
~$ ~
s
Sealing means 210 includes Z portion 220 and elastomeric
back-up seals 330, 332 which will be described in detail with
respect to Figure 4 hereinafter, and upper drive portion 218 and
lower cam portion 222 for compressing intermediate Z portion 220.
Sealing m~ans 210 is a combination primary metal-to-metal seal
~~and~secondary elastomeric seal. Having a metal-to-metal seal be
the primary seal has the advantage that it will not tend to
deteriorate as does an elastomeric seal.
Holddown and sealing assembly 180 is lowered into the well
on casing hanger 50 by a running tool 200. Running tool 200
includes a mandrel 230, which is the main body of tool 200, a
connector body or sleeve 240, a skirt or outer sleeve 250, and an
assembly nut 260. Mandrel 230 includes an upper pin end 232 with
internal threads 234 for connection with the lowermost pipe
section of drill pipe 236 extending to the surface 18 and a lower
box end 238 also having internal threads. Above box end 238 is
located an annular reduced diameter groove portion 242. Another
reduced diameter portion 248 is disposed above groove portion 242
forming an annular ridge 252. Below upper pin end 232 and above
reduced diameter portion 248 is a third threaded reduced diameter
portion 254 (shown in Figure 2A) having a diameter smaller than
that of portions 242 and 248.
Connector body or sleeve 240 includes a bore 246 dimensioned
to be telescopically received over annular ridge 252 and box end
238. Connector body 240 is telescopingly received in the annulus
formed by mandrel 230 and skirt 250. Ridge 252 includes annular
seal grooves 258, 262 housing 0-rings 264, 266, respectively, for
sealing engagement with the inner diameter surface of bore 246.
The top end of connector body Z40 includes an internally directed
radial annular flange 268 having a sliding fit with the surface
of reduced diameter portion 248. The lower end of connector body
240 has a redu~ed diameter portion 270 which is sized to be
slidingly received by bore 272 of casing hanger 50. Reduced
12~88~
diameter portion 270 forms downwardly facing annular shoulder 274
.
which engages ~he upper terminal end 276 of casing hanger S0 upon
landing running tool 200, holddown and sealing assembly 180 on .
casing hanger 50 within wellhead 24. Reduced diameter portion
270 has a plurality o~ circumferentially spaced slots or windows
- --278 ~ ich slidingly house segments or dogs 280 having a plurality
of teeth 282 adapted to be received by grooves 120 of casing
hanger 50 for connection of running tool 200 with casing hanger
50. Dogs 280 have an upper projection 284 received within an
annular groove 286 around the upper inner periphery of windows
278. Above windows 278 are a plurality of seal grooves 288, 290
housing 0-rings 292, 294 for sealingly engaging the seal bore 272
of casing hanger 50. Adjacent to the upper exterior end of
connector body 240 is a snap ring groove 296 housing snap ring
298 used in the assembly of running tool 200 as hereinafter
described. Dogs 280 collapse back into groove portion 242 after
lower box end 238 is moved to the lower position, as shown, upon
the application of torque on tool 200 to set holddown and sealing
assembly 180.
Skirt or outer sleeve 250 includes a generally tubular body
having an upper inwardly directed radial portion 300, a medial
portion 302, a transition portion 304, and a lower actuator
portion 306. Portions 3~0, 302, 304 and 306 are contiguous and
have dimensions to telescopically receive the upper terminal end
276 of casing hanger 50, connector body 240 and mandrel 230.
Lower actuator portion 306 has a castilated lower end 308 engaging
the upper castilated end 198 of packing nut 182 whereby torque
may be transmitted from running tool 200 to holddown and sealing
assembly 180. The inner diameter of actuator portion 306 is
sufficiently large to clear the outside diameter of threads ~18
of casing hanger 50.
Medial portion 302 slidingly receives connector body 240.
Portion 302 includes an internal annular groove 310 adapted to
receive snap ring 298 mounted on connector body 240 upon disen-
gagement o~ running tool 200 from holddown and sealing assembly
1~0~
180 and casing hanger 50, as hereinafter described. Portion 302
has a plurality of threaded bores 312 extending from its outer
periphery to groove 310 whereby bolts (not shown) may be threaded
into groove 310 to prevent snap ring 298 from engaging groove 310
during the resetting of running tool 200 on another casing hanger.
~ ~~Snap ring 298 has an upper cam surface 316 for engaging the ends
of the bolts. Once connector body 240 is received into the upper
portion of the annular area formed by outer sleeve 250 and mandrel
230 whereby snap ring 298 is above annular groove 310, connector
body 240 cannot be removed without snap ring 298 engaging groove
310. Thus, to remove connector body 240 upon the resetting of
running tool 200, bolts are threaded into bores 312 to close
groove 310 and prevent grooves 310 from receiving and engaging
snap ring 298. This permits connector body 240 to move downwardly
on mandrel 230 until shoulder 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 ar~e 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
cast~lated to form a splined connection 320 with mandrel 230 for
the transmission of ~orgue.
Referring now to Figures 2A and 2B, assembly nut 260 has
internal threads 32~ for a threaded connection at 322 with threa~s
235 of reduced diameter portion 254 of mandrel 230. The lower
terminal face of assembly ~ut 260 bears against the upper terminal
end of outer sleeve 250 to retain outer sleeve 250 on mandrel
23~.
In op~ration, the packing nut 182 is only partially threaded
to threads 118 at the top of casing hanger 50 so that mandrel 230
is mounted in the running position on casing h~nger 50. In the
running position, annular ridse 252.abuts shoulder 269 formed by
~adial annular~flange 268 on~connector-body 240. The outer
tubular surface of box end 238 is adjacent to and in engageme~t
with the internal side of dogs 280 whereby teeth 282 are biased
into grooves 120 o~ casing hanger S0 preventing the disengagement
~of running tool 200 and casing hanger 50 as they are lowered into
the well on drill pipe 236. The running position of running tool
200 is not illustrated in the figures.
Upon landing face 132 of shoulder ring 128 of casing hanger
50 on support shoulder 80 of housing seat 70 in wellhead 24,
surface casing 44 is cemented into place within borehole 42.
After the cementing operation is completed, running tool 200 is
rotated and tor~ue is transmitted to holddown and sealins assembly
180 to actuate holddown and sealing assçmbly 180 into the holddown
position shown i~ Figures 2B and 2C. Rotation of drill pipe 236
at the surface 18 causes mandrel 230 to rotate which rotates
outer sleeve 250 by means of splined connection 320. The toroue
from 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
24 as shown in Figure 2. Sealing means 210 has not yet been
actuated to seal between upper annulus 134 and lower annulus 130.
Latch ~ing 144 requires only a predetermined camming load for
actuation and therefore has a predetermi~ed contractual tension.
Sealing means 210 is designed in cross section to insure that
sealing means 210 will not be prematurely compressed upon the
actuation and camming of latch ring 144 by holddown actuator
means 212. The load reguired to compress sealing means 210 is
substantially greater than that required to expand and actuate
.
latch ring 144. Mandrel 230 moves downwardly with skirt 250 upon
the actuation of holddown and sealing assembly 180. This downward -
movement of mandrel 230 releases dogs 280.
For a description of sealing means 210, reference will now
~~be ~ade to Figures 4 and 4A showing sealing means 210 in the
running and holddown positio~s and the sealing position, respec-
tively. Sealing means 210 includes metal Z portion 220, upper
and lower elasto~eric members 330, 332, respectively, and upper
drive portion 218 and lower cam portion 222 for compressing Z
portion 220 and elastomeric members 330, 332. Metal annular Z
portion 220 includes a plurality of annular links 334, 336, 338
connected together by annular metal connector rings 340, 342 and
connected to upper drive portion 218 by upper metal connector
ring 344 and to 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 positive connective link from bottom to
top between lower cam portion 222 and upper drive portion 218.
This positive connective link causes links 334, 336, and 338 to
move into a more angled disengaged position from wellhead 24 and
casing hanger 50 upon the retrieval and disengagement of sealing
means 210 and act~ator means 212 from wellhead 24. Further this
positive connective link provides a metal connection extending
from drive portion 218 to lower cam portion 222 to permit the
application of a positive upward load on lower cam portion 222
upon disengagement. Were it not for the advantage of this
retrieval, connector rings 340, 342, 344, and 346 may not be
required.
Connector rings 344, 346 adjacent drive portion 21R and cam
portion 222, respectively, must have a minimum length to ensure
the sealing engagement of annular links 334 and 338. If connector
rings 344, 346 are too short, there will be insufficient bending
to allow links 334 and 338 to contact surfaces 61, 140, respec-
tively. Because drive portion 218 and cam portion 222 are massive
~za~
in size when compared t~ connector rings 344, 346, t~e comparative
. .
massive body of portions 218-, 222 will not bend so as to permit
'~he sealing engagement of links 334, 338. Thus, it is essential
that connector rings 344, 346 permit such bending. Connector
rings 340, 342, 344, and 346 provide~a local high stress contact
- --point throughout metal Z portion 220.
The metal ~ portion 220 is made of a very soft ductile steel
such as 316 stainless. Such metal would have a yield of approxi-
-
mately 40,000 psi. This yield is less than half the yield of
approximately 85,000 psi of the material for wellhead 24 and
hanger 50. Upon sealing engagement of metal Z portion 220, metal
Z portion 220 plastically deforms while surface 61 of wellhead 24
and surface 140 of hanger 50 tends to elastically deform. Should
there be any imperfection in surfaces 61, 140, the ductility of
the material of annular Z portion 220 will permit such material
to deform 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.
Upper, intermediate, and lower annular links 334, 336, 338
respectively~ each have a diamond-shaped cross-section. Since
~he cross-section of linXs 334, 336, 338 is substantially the
same, a description of link 336 shall serve as a description of
links 334, 338. Annular link 336 includes substantially parallel
upper and lower annular sides 348, 350 respectively, with upper
side 348 facing generally upward and lower side 350 facing gener-
ally downward, substantially parallel inner and outer annular
sides 352, 354 respectively, with outer side 3S2 facing radially
outward and inner side 354 facing radially inward, and parallel
inner and outer annular sealing contact rims 356, 358 respectively.
Annular links 334, 338 h ve comparable upper and lower sides,
inner and outer sides and inner and outer sealing contact rims.
In the hoiddown p~sition, the sealing contact rims of l~ks
.. . . . . . . .
334, 336, 338 are deformed su~stantially parallel with the bore
wall 61 of wellhead housing ~6 and the outer wall 140 of casing
hanger ~0. Upper connector ring 344 extends fro~ the lower end
364 of upper drive portion 218 to the upper side 335 of upper
- --link 334 to form an annular channel 366. Metal connector ring
340 extends from the lower side 337 of upper link 334 to upper
side 348 of intermediate link 336 to form annular channel 368 and
metal connector ring 342 extends from lower side 350 of interme-
diate link 336 to the upper side 339 of lower link 338 to form
annular channel 370. Lower connector ring 346 extends from the
lower side 341 of lower link 338~to the upper end 372 of lower
cam portion 222 to form annular channel 374. Annular channels
366, 368, 370 and 372 between adjacent ridges assist in achieving
the-bending of Z portion 220 at predetermined locations, namely
at connector rings 340, 342, 344, and 346. Lower end 364 of
drive portion 218 is sub-stantially parallel with the upper side
- . 335 of upper link 334 and upper end 372 of cam portion 222 is
substantially parallel with the lower side 341 of lower link 338.
In the running and 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 and lower elastomeric members 330, 332 are molded to
conform to the shapes of annular grooves 376, 378 formed by links
334, 336, 338 and are bonded to links 334, 336, 338. Upper and
lower elastomeric members 330, 332 have outer and inner annular
vertical sealing surfaces 380, 382 respectively, adapted for
sealingly engaging bore wall 61 and outer wall 140 in the sealing
position. The upper and lower annular ridges formed by sealing
surfaces 380, 382 are chamfered to permit deformation into sealing
position of members 330, 332 upon compression. Elastomeric
members 330, 332 are also chamfered to permit a predetermined
I
3S
de~formation of members 330, 33Z between links 334, 336, 338.
Although the cross sections of elastomeric members 330, 332 are
substantially the same, inner elastomeric member 332 may be .
chamfered or trimmed more than outer elastomeric member 330 to
.
avoid any premature extrusion of memb-ers 330, 332 prior to links
~ --334r 336, 338 establishing an anti-extrustion seal with bore wall
61 of wellhead 24 and outer sealing surface 140 of casing hanger
50.
It is preferred that sealing means 210 include at least
three links. This number is preferred since it provides an
anti-extrusion link for each side of elastomeric members 330,
332. Also, the three links 334, 336, 338 achieve a symmetry of
design. However, sealing mea~s 210 could include one or more
links and might well include a series o~ links capturing a plural-
ity of elastomeric members. Surfaces 364 and 372 of drive portion
218 and lower cam portion 222, respectively, would preferably
have tapers tapering in the same direction as the adjacent links
such as links 334 and 338 shown in the preferred design.
m e diamond shaped cross section of links 334, 336, 338
permits the mid-poxtion of links 334, 336, 338 to be very ri~id.
By having a thick mid-portion, the redùced areas at the ends of
links 334, 336, 338 will become the area which will yield or bend
such as that area adjacent to connector rings 340, 342, 344, 346.
It is not desirable that links 334, 336, 338 bend or yield at
their mid-portio~. However, the particular diamond-shaped cross
section shown occurs only because of the ease of manufacture of
that shape. Links 334, 336 and 338 could have a continuous
convex or ellipsoidal shape. This shape might be termed frusto-
conoidic. This provides a protuberant center portion. If the
cross section of links 334, 336, 338 were of the same thickn~ss,
links 334, 336, 338 might tend to bend or bow at their mid-section.
Although it is preferred to have a thickened center portion for
1~0~
links 334, 336, 338 to ~ontrol the point of bending at the rims
.
~or a predetermined plastic deformation and to insure there is no
distortion at the center of links 334, 336, 338, links 334, 336,
33>3 may be frustoconlcal metal rings with a cross section of even
thicXness,rather than frustoconoidic'rings.
Referring now to Figures 4 and 4A, Figure 4A illustrates
sealing means 210 in the sealing position. Sealing means 210 is
compressed as holddown actuator means 212 reaches the limit of
its travel against latch ring 144 and packing nut 182 continues
its downward movement on threads 118 of casing hanger 50 as shown
in Figures 2B and 2C.
Metal-to-metal sealing means 210 is series actuated from
bottom to top. In other words, the lowest annular link 338 bends
and deforms first upon compression of sealing means 210 and is
the'first linX to initiate sealing contact with surface 61 and
surface 140. This series actuation is preferred to limit the
drag of upper annular lïnks 334, 336 down surfaces 61, 140 upon
actuation if the upper links 334, 336 were to make sealing engage-
ment prior to lower link 338. It is preferred that there be a
balanced force applied ,to upper annular link 334.
Elastomeric members 330, 332 provide the initial seal.
Elastomeric seals 330, 332 engage surfaces 61, 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 upcn the initial compression set of a few thousand psi,
i.e., 3,000 psi, of sealing means 210. Links 334, 336, 338
provide a backup for members 330 and 332, an anti-extru~ion means
for such members and are a retainer for such members. Therefore,
it is desired that the rims of links 334, 336, 338 engage surfaces
61, 140 prior to the elastomeric members 330 and 332 extruding
past the adjacent rims. It is undesirable for such extrusion
past the rims to occur prior to the sealing contact of the rims
~()z~
since any elastomeric material between the rims and surfaces 60,
140 may be detrimental t~ the-sealing engagement of links 334,
336, 338. Thus, as shown and described, the volume of elastomeric
material in members 330 and 332 has been calculated and predeter-
mined so that the rims contact surfaces 60, 141 prior to any
_ ~xtr~sion of members 330, 332.
Links 334, 336, 338 are designed to ~e thin enough to deform
into sealing engagement upon a compression set o~ a few thousand
psi. Connector rings 340, 342, 346 form stress points or weaX
areas around annular Z portion 220 locating the bending of Z
portion 220 at predetermined 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 coin onto bore wall
61 and outer wall 140 to form a metal-to metal seal between
wellhead 24 and casing hanger 50 thereby sealing upper annulus
134 from lower annulus 130 of the well. Sealing means 210 is
designed 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 of lower link 338 to mo~e
downwardly and engage upper end 372 of lower cam portion 222.
The taper of surface 372 of lower cam portion 222 provides an
initial starting deformation angle for lower annular link 338.
Surface 372 also ensures that link 338 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
moves downwardly, upper link 334 bends at connector ring 344
causing the inner side 333 of upper link 334 to engage lower end
36g as lower end 364 compressors Z portion 220. Intermediate
link 336 moves from its angled position to a more horizontal
position. Elastomeric members 330, 332 are compressed between
links 334, 336, 338 and sealingly engage bore wall 61 and outer
`
~O~
wall 140. The inner rims of links 334, 336, 33~ make annul~r
.
`~sealing contacts with outer wall 140 of casing hanger 50 at 380,
382 and 384 and the outer rims of links 334, 336, 338 make annular -
sealing contact with bore wall 61 of wellhead 24 at 386, 388, and
390. The seal means 210 thus achieves a~six point annular metal-
- -to-metal sealing contact. The sealing contact of the inner and
outer rims causes links 334, 336, 338 to become antiextrus1on
rings for elastomeric members 330, 332. Elastomeric members 330,
332 ser~e as backup seals to the metal seals.
As links 334, 336, 338 move from their angled position to a
more horizontal position upon actuation, each end or each inner
and outer rim of links 334, 336, 338 move into engagement with
bore walls 61 and 140. It is not intended that links 334, 336,
338 become horizontal. It is essential-that the inner and outer
-rims of links 334, 336, and 338 become biased between bore wall
61 of wellhead 24 and outer wall 140 of casing hanger 50. The
inner and outer rims of each link react from the ~earing load of
the other. For example, as inner rim 356 of link 336 bears
against casing hanger wall 140, this contact places a reaction
load on outer rim 3~8 moving outer rim 358 toward wellhead bore
wall 61. If each link did not have an opposing rim, the link
would continue to move downwardly until its side engaged an
adjacent link rather than move,into sealing engagement with
either wall 61 or 140. This bearing against the inner and outer
rims necessitates the prevention of any buckling 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 cannot buckle or relieve itself. Further, if links 334,
336, 338 were permitted to become horizontal, the tolerances
between the inside diameter of wellhead 24 and the outside dia-
meter of casin~ hanger 50 w~uld become critical. Also, where
links 334, 336, 33~ are not horizontal but at an angle, it is
easier to disengage Z portion 220 upon extraction of sealing
means 210. Surface 364 of drive portion 218 and surface 372 of
lower cam portion 222 are tapered to prevent links 334 and 338
respectively, from becoming horizontal.
It should be understood that elastomeric seals 330,
332 may not be required where the rims of links 334, 336, 338
sufficiently engage 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, it should be understood that members 330 and 332
may be replaced by a spacer which would permit a predetermined
amount of collapse or deformation of links 334, 336, 338. As
disclosed in the present embodiment, elastomeric members 330 and
332 become such a spacer means. Also, the present invention is
not limited to an elastomeric material. Members 330 and 332 may
be made of other resilient materials such as Grafoil, an all-
graphite packing material manufactured by DuPont. Grafoil, in
particular, may be used where fire resistance is desired.
"Grafoil" is described in the publications "Grafoil - Ribbon-
Pack, Universal Flexible Graphite Packing for Pumps and Valves"
by F. W. Russell (Precision Products) Ltd. of Great Runmow,
Essex, England, and "Grafoil Brand Packing" by Crane Packing
Company of Morton Grove, Illinois.
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 elastomeric material to surfaces 61 and 140 to
provide a primary elastomeric 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 33~, 336, 338 become the primary backup for elastomeric
seals 330, 332. These links would become energized backup rings
for members 330, 332. In such a case, the backup seals would not
drag down into position. -32-
The "resent invention is designed for 15,000 psi working
.
pressures and therefore it is the objective of the present i~ven-
tion to achieve a 20,000 psi compression set on seal means 210
whereby seal means 2l0 is pre-energized in excess of the antici-
pated wor~ing pressure.
In achieving a 20,000 psi compression set, sealing means 210
is actuated by a combination of tor~ue and hydraulic pressure.
Initially, an initial torgue of approximately lO,OOO 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. Particularly, drill
pipe 236 rotates mandrel 230 wh`ich in turn rotates outer sleeve
250 by means of spline connection 320. Outer sleeve 250 drives
packing nut 182 by means of the castell~ted connection of lugs
198, 308. Packlng nut 182 bears against drive portion 28 by
transmitting thrust through beari~g means 205. Since holddown
actuator means 212 has previously reached the limit of its down
ward travel again~t latch ring 144 in moving to the holddown
position, seal means 210 and specifically, Z portion 220 are
compressed between drive portion 218 and lower cam portion 222.
This torque applies an axial force of approximately 150,000 lbs.
As Z portion 220 is compressed between drive portion 2' e and
lower cam portion 222, elastomeric members 330, 332 become com-
pressed between links 334, 336, 338 as links 334, 336, 338 move
into a more horizontal position. As such compression occurs,
elastomeric mem~ers 330, 332 begin to completely fill the grooves
formed between links 334, 336, 338 housing elastomeric members
330, 332. ~he amount of elastomeric material of elastomeric
members 330, 332 is predetermined sucb that as links 334, 336,
338 move into a more horizontal position, links 334, 336, 338
achieve sufficient contact wi~h bore wall 61 of wellhead 24 and
outer bore wall 140 of casing hanger 50 to func~ion as metal
anti-extrusion means for preventing the extrusion of elastomeric
seals 330, 332. Particularly, the inside annular contact areas
~2~3~81~S
382, 38~ prevent the extrusion vf inside elastomeric member 332
.. .. .. .
and annular contact areas 386, 388 prevent the extrusion of
outside elastomeric member 330. Thus, an initial anti-extrusion
seal is achieved by links 334, 336, 338 before elastomeric members
330, 332 can extrude past their,adjacent annular sealing contact
_
areas. It is essential that elastomeric members 330, 332 have
the right volume of elast~meric material and the proper configu-
ration so that upon compression of sealing means 210, metal
anti-extrusion contact is achieved before thè extrusion of elas-
tomeric members 330, 332 past contact areas 382, 384, 386, and
388.
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, 140 of wellhead 24 and
casing hanger 50 respectively. The initial tor~ue is unable to
completely actuate the metal-to-metal seal means 210 because o
friction losses in the riser pipe, the blowout preventer stack,
the drill pipe itself, and more particularly, because o~ various
thread loads such as at threads 118. Such friction losses limit
the compression load which may be applied to sealing means 210 by
drill pipe 236.
To achieve the desired compression set of sealing means 210,
hydraulic pressure is combined with the torque to set the metal-to-
metal seals of sealing means 210. Referring now to Figures 2A
and 2B, blowout preventer 40 is shown schematically and includes
rams 34 with kill line 38 com~-~nicating with annulus 134 below
blowout 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 blow~ut preventer 40, hydraulic pressure
would be applied through choke line 36.
In applying pressure through kill line 38 and into annulus
134, it is necessary to seal off annulus 134. Note in Figure 2A
that kill line 38 is shown in phase with rams 34, but in actuality
$~ ~
1~02~
is manufactured 90 out oL phase. In doing so, pipe rams 34 are
closed to ~eal around drill pipe 236, 0-ring seals 264, 266 seal
between mandrel 230 and sleeve 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
across annulus 134. Thus, hydraulic pressure may be applied
through kill line 38 and into annulus 134.
Because of the corkscrew effect caused by the application of
torque to a drill string such as drill pipe 236, 10,000 ft-lbs of
torque is generally considered to be the most torque that can be
transmitted through a drill pipe string in an underwater situation.
In the present invention, a 10,000 ft-lb torque on drill pipe 236
will establish a seal across annulus 134 which would withstand a
few thousand psi of hydraulic pressure. This relatively low
pressure seal would then permit the pressurization of annulus 134
to further compress sealing means 210 which in turn increases the
sealing engagement in annulus 134 to withstand additional hydrau-
lic pressure. Metal annular Z portion 220 with annular links
334, 336, 338, is designed so that annular rings 334, 336, 338
are thin enough to establish a metal-to-metal seal in cooperation
with elastomeric seals 330, 332 to withstand a hydraulic pressure
of a few thousand psi upon the application of a 10,000 ft-lb
torque.
In applying pressure on seal means 210, the effective pres-
sure areas are the diameter of running tool seal 264 less the
diameter of drill pipe 236 and in addition thereto, the annular
seal area of sealing means 210. Since the annular seal area is
fixed for a particular sized wellhead and casing ha~ger, the
principal variable in determining the pressure setting force is
the difference in pressure area between the running tool se~l 264
and drill pipe 236. Thus, this difference may be varied to
permit a predetermined compression setting force on sealing means
210. The difference in diameter may vary, for example, from
between 5 inches and 10 inches.
The particular function of the nydraulic pressure is to
.
provide an axial force capable of inducing 20,000 psi into the
sealing means 210 without exceeding the pressure design limits of
the apparatus in the wellhead system. The function of the tor~ue
on nut 182 after hydraulic pressure is applied is to cause nut
182 to follow the travel of sealing means 210 as it moves down
under force and prevent its relaxing when the hydraulic force is
relieved. It is essential that a high torque, i.e. 10,000 ft-lbs,
be maintained in drill pipe 236 so that packing nut 182 follows
seal means 210 since otherwise nut 182 might prevent the downward
movement of sealing means 210. This procedure is repeated by
gradually and co~tinuously increasing the hydraulic pressure
until packing nut 182 has been rotated a sufficient number of
rotations to insure that a 20,000 psi compression set has been
achieved by sealing means 210.
Running tool 200 is a combination tool for applying torque
to holddown and sealing assembly 180 and for assisting in the
application of hydraulic pressure to holddown and sealing assembly
180. The rotation o~ drill pipe 236 for the transmission of
torque via running tool 200 to holddown and sealing means 180
permits an initial sealing engagement of sealing means 210 in
annulus 134 between wellhead 24 and hanger 50 whereby hydraulic
pressure may then be applied to annulus 134 to further set sealing
means 210. As hydraulic pressure is gradually and continuously
increased in annulus 134 through kill line 38, sealing means 210
is further compressed into a greater sealing engagement against
surface 61 of wellhead 24 and surface 140 of hanger 50. As this
sealing engagement increases, sealing means 210 will seal against
an even greater annulus pressure. Thus, pressure through kill
line 38 may be gradually increased until sealing means 210 has a
compression set of approximately 20,000 psi. The hydraulic
pressure applied throug~ kill line 38 and annulus 134 does not
exceed the design limits of the system. All systems have a
standard working pressure which an operator may ~ot exceed. The
1'~0'~8S
system of the present invention is designed f~r 15,000 psi working
- ~pressures and ~hus the hydrXulic pressure in annulus 134 to fully
actuate sealing means 210 cannot exceed 15,000 psi although a
20,000 psi compression set is desired. The pressure invention
achieves a 20,000 psi compression set of sealing means 210 without
_ ~applying a hydraulic pressure exceeding 15,000 psi.
As hydraulic pressure is gradually increased in annulus 134
to achieve a 20,000 psi compression set on sealing means 210,
packing nut 182, due to the continuous application of the 10,000
ft-lb torque on drill pipe 236 which is transmitted to skirt 250,
follows sealing means 210 downwardly in annulus 134 on threads
204. Upon the release of the hydraulic pressure through kill
line 38 and annulus 134, packing nut 182 prevents the release o~
: the 20,000 psi compression set on sealing means 210 due to the
engagement of threads 204 with casing hanger 50.
It is essential that elastomeric seals 330, 332 are ener-
. gized into sealing engagement after the application of the initial
; torque by.drill pipe 236. Unless elastomeric mem~ers 330, 332
are engaged, the application o hydraulic pressure through kill
line 38 will be lost past sealing means 210 into lower annulus
130. However, the seal of elastomeric members 330, 332 need only
be sufficient to seal against an incremental amount of hydraulic
pressure through kill 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 members 330, 332 to increase the metal-to-metal and elas~o-
meric seali~g contact with walls 61, 140. Such increased sealing
contact will permit the continued increase in hydraulic pressure
through kill line 38 for the further actuation of sealing means
210.
The seal actuation means just described is a simplification
of prior art actuator arrangements. Prior art actuators pressure
down through drill pipe to actuate an internal porting piston
system. A dart seals off the end of the drill pipe bore for the
application of pressure through the piston system which in turn
Q
12~
applies pressure to thç seal. Although such a prior art actuator
~:system could be adapted to the present invention, the arrangement
of the present invention has substantial advantages over the
prior art.
It may be necessary to increase-the initial torque applied
_ to drill string 236 after blowout preventer rams 34 have been ~
closed. Although the rubber contact of rams 34 with drlll pipe
236 does not create the friction loss as would a metal-to-metal
contact, some additional friction loss will occur. Thus, addi-
tional torque, if possible, may be applied to drill string 236
above the initial torque to overcome such friction loss. However,
d`rill pipe 236 will rotate with rams 34 in the closed position.
The annulus between the riser and drill pipe 236 contains well
fluids which will cause well fluids to be disposed bPtween pipe
rams 34 and drill pipe 236 upon closure of blowout preventer 40.
Thus, it is believed that the 10,000 ft-lb tor~ue will not be
substantially reduced. If, due to the particular application,
the friction between pipe rams 34 and drill pipe 236 must be
reduced, a special pipe joint, not shown, may ~e series connected
in drill pipe 236 whereby pipe rams 34 engage a stationary tubular
member having a rotating member passing therethrough to transmit
torque past rams 34. Such a special pipe joint would include
rotating seals between the stationary member and rotating inner
member to prevent the passage of fluid.
Referring now to Figures 5A, 5B, and 5C, there is shown the
complete assembly of wellhead 24 with 16 inch casing hanger 420,
13-3~8 inch casing hanger 50, 9-5/8 inch casing hanger 400, and 7
inch casing hanger 410. Casing hanger 50 is shown in Figure 5B
in the holddown and sealing position described in Figures 1-4
with holddown and sealing assembly 180 actuated in the holddown
and sealing position. 9-5/8 inch casing hanser 400 is shown
supported at 402 on top of casing hanger S0. Casing hanger 400
also includes a holddown and sealing assembly 404 comparable to
assembly 180 of casing hanger 50. 7 inch casing hanger 410 is
æ~ -
s
shown supported at 412-on top of 9-5/8 inch casing hanger 400.
Casing hanger 410 includes a holddown and sealing assembly 414
comparable to that of assembly 180. Figures 5A and 5B show the
holddown grooves of wellhead 24, namely holddown groove 68 for
casing ha~ger 50, hoiddown groove 406 for casing ha~ger 400, and
- --holddown groo~e ~16 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 support a smaller load, the amount of contact
support area required for casing hanger 50 is not needed for
casing hangers 400, 410. ~anger 50 requires a 100 percent con-
tact area which is not required for hangers 400, 410. Further,
the shoulders on hangers 400, 410 are sguare and shoulder out
evenly on top of the supporting hanger.-
Figure 5C discloses an alternative embodiment for removablecasing hanger support seat means or breech block housing seat 70
shown in Figure 2C. Referring now to Figure 5C, a modified
breech bl~ck housing seat 420 is shown adapted for lowering into
bore 60 and connecting to breech block teeth 66 of wellhead 24.
In certain areas there are formations below the 20 inch
casing which cannot take the pressure of the weight of the mud
used 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 S0 and as a casing hanger for the 16 inch
casing 422.
Housing seat 420 includes a solid annular tubular ring 424
and a packoff ring 426. Solid annular tubular ring 424 includes
exterior breech block teeth 428 substantially the same as breech
block teeth 76 described with respect to housing seat 70. Ring
1~02~
424 also has an upwardly facing and tapering conical seat or
.
support shoulder 430 adapted-for engagement with packof~ ring
426. Ring 424 also includes a plurality of keys 432, substan~
tially the same ~s keys 92 shown in Figure 2C, for locking hous~
ing seat 420 within wellhead housing 46.- Ring 424 is provided -
- ~wit~ a box end 434 for threaded engagement to the upper pipe
section of 16 inch casing string 422.
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 of ring 424 for threaded connec-
tion at 44~. Packing ring 426 includes an upwardly facing sup-
port shoulder 4S0 for engagement with the downwardly facing
shoulder 132 of casing hanger 50. O-ring seals 444 and 446 are
housed in annular O-ring grooves around the upper end of packing
ring 426 for sealing engagement with bore wall 61 of wellhead 24.
Packing ring 426 also i~cludes O-rings 452, 454 housed in annular
O-ring grooves above thread 442 on pin 440 for sealing engagement
with the 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 string 422 must be cemented, hous-
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 block slots, such as slots 86, 87 of housing seat 70 and
wellhead 24 shown in Figure 3, and a series of circumferentially
spaced slots through continuous annular flange 85 aligned above
breech block slots 86, 87. The slots of flange 85 are more
narrow than breech block slots 86, 87 to prevent seat 420 from
passing through wellhead 24. Packing ring 426 is provided, after
the cementing, to packoff annulus 134. ~o test packing ring 426,
the rams of the blowout preventer are closed and the running tool
is sealed below the test port 456 and annulus 134 is pressurized.
If there is a leak between wellhead housing 46 and packing ring
8~
4~6 or the packing ring and counterbore 438, it will be impossible
to pressure up annulus 134. Also there will be an increased
volume of hydraulic flow into annulus 134 from kill line 38. It I
is not necessary that packin~ ring 426 establish a high pressure
seal since at thls stage of the compietion of the well, mos~
pressures will be in the range of less than 5,00~ psi.
It should be undexstood that one varying embodiment would
include making housing seat 70 and casing hanger 50 one piece
whereby seat 70 and hanger 50 could be lowered and disposed in
wellhead 24 on one trip into the well. Hanger 50, for example,
could include breech block teeth for direct engagement with
wellhead breech block teeth 66.
Another varying embodiment would include extending the
longitudinal length of the tubular ring 424 of housing seat 420
whereby sealing means 210 and/or actuator holddown means 212
could be disposed directly on housing seat 420 and between seat
420 and wellhead 24 for sealing and/or holddown engagement with
wellhead 24. In such a case, packing ring 426 would no longer be
reguired.
Because many varying and different embodiments may be made
within the scope of the inventor's concept taught herein and
because many modifications may be made in the embodiments herein
detailed in accordance with the descriptive reguirements of the
law, it should be understood that the details herein ~re to be
interpreted as illustrative and not in a limiting sense. Thus,
it should be understood that the invention is not restricted to
the illustrated and described em~odiment, but can be modified
within the scope of the following claims.
