Wellhead Housing Otc15396

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Copyright 2003, Offshore Technology Conference

This paper was prepared for presentation at the 2003 Offshore Technology Conference held inHouston, Texas, U.S.A., 5–8 May 2003.

This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Offshore Technology Conference and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Offshore Technology Conference or its officers. Electronic reproduction,distribution, or storage of any part of this paper for commercial purposes without the writtenconsent of the Offshore Technology Conference is prohibited. Permission to reproduce in printis restricted to an abstract of not more than 300 words; illustrations may not be copied. Theabstract must contain conspicuous acknowledgment of where and by whom the paper waspresented.

AbstractThis paper describes the development of full-bore wellheads, a

new 18-3/4 in. 15,000 psi W.P. system, from conception tofield installation. The wellhead when installed has a full-bore

diameter without a casing hanger landing shoulder to allow

one more casing string to be run below the mudline under BOP control due to this major wellhead innovation.

Introduction

Today wells are being drilled in deeper and deeper water

which associates to higher costs. More economical risk is

taken to drill wells in deeper water and reaching the ‘payzone’with a sufficient size production string to produce from is

more important than ever before. In addition to deeper water,

there is a need to find ways to drill in more difficult

formations some of which include various shallow zone

hazards1.

As a result of these concerns, there has been a demand tofind ways to ensure that the operators can reach the planned

hole depth and/or size required to produce from. Unforeseen

hole problems that may have not been expected may hinder reaching the depth requirements. By providing one more

casing string than a conventional 18-3/4 in. wellhead system, a

better opportunity to reach the desired hole depth and size can be achieved.

To help solve these problems a new 18-3/4 in. wellhead

system with a 36 in. conductor string was designed and

implemented. A 36 in. x 18-3/4 in. wellhead system consists

of the following casing program:

Conventional:

36 in. x 28 in./26 in. x 20 in. x 16 in. x 13-3/8 in. x 9-5/8in. x 7 in.

Full-bore:

36 in. x 28 in./26 in. x 22 in. x 18 in. x 16 in. x 13-3/8 in. x9-5/8 in. x 7 in.

The new system adds the 18 in. string which is run under

BOP control, and the 20 in. becomes 22 in. hanging from thehigh pressure housing as shown in Figure A. The 36 in. string

is jetted or cemented in place using conventional methods

The 18-3/4 in. high pressure housing is run with 22 in. casingsuspended from the bottom and landed in the 36 in. housing

and cemented in place. The 18 in. string is landed in the 22 in

string below the mudline in its respective sub. The 16 in

string is run like the 18 in. string, but it will land in an

independent sub in the 22 in. string above the 18 in. string and below the high pressure housing. The load shoulder is then se

in the high pressure housing, and 13-3/8 in., 9-5/8 in. and 7 in

casing can be run and set, respectively, with each subsequen

casing string landing on top of the other.The new system provides one more casing string to the

above conventional program, but with reduced radia

clearances between several of the strings. Furthermore, due tothe tight clearances, drives the requirement for high clearance

or flush joint connections. This additional string of casing

helps operators utilize existing rig equipment sizes and

capabilities1.

SpecificationsThe specifications for the wellhead system are the following:

18-3/4 in. - 15,000 psi rated working pressure Compliance with industry specifications: API 17D and

NACE MR-0175

Temperature range of 35 Deg. F to 250 Deg. F Weight set operation

Single trip installation of hanger and seal assembly

with metal sealing

Minimization of the number of trips and tools 18.630 in. nominal through bore of high pressure

housing prior to setting load shoulder

Load carrying capacity of 6.2 million lbs

1 million lbs per hanger (13-3/8 in., 9-5/8 in. and7 in.)(7 in. hanger does not transfer significant load to

the load shoulder) 4.1 million lbs end-load due to 15,000 psi full

bore test.

Design

Subsea Wellhead Housing

The primary design feature of this new wellhead system is the

high pressure housing. In a conventional 18-3/4 in. subseawellhead there is a load shoulder, which reduces the bore to an

approximately 17-9/16 in. diameter that allows a casing

OTC 15396

18-3/4 in. FullBore Wellhead SystemMarc Minassian, ABB Vetco Gray



2 OTC 15396

hanger to be run and set on at any time in the drilling program

and allows for a 17-1/2 in. bit to pass through. In this new

wellhead system, the high pressure housing has an 18-5/8 in.in diameter, or full-bore, throughout the entire length. This is

what coins the term ‘FullBore’.

The load shoulder in the FullBore Wellhead System is amechanism that consists of a c-ring, load shoulder retainer,

shear pins, and anti-rotation ring prepacked in the housing prior to shipping offshore, as shown in Figures B-1 thru B-5.When it is time to create the load shoulder the c-ring is shifted

down into its set position as shown in Figure B-3 with a load

shoulder actuation tool (LSAT). After the load shoulder is set,

the ID of the wellhead housing is approximately 17-9/16 in. in

diameter, like a conventional subsea wellhead.

Load Shoulder Actuation Tool

The load shoulder is set with a running tool that actuates

the load shoulder subsea with weight, as shown in Figure C-1.It runs down the hole on drill pipe, locates four (4) slots in the

housing, weight is applied down to set the load ring and a

pressure test is performed to verify the tool has energized theload ring and/or perform BOP isolation tests. The tool

consists of 3 primary systems, the detent system, the load

shoulder setting system, and the test verification system.

The detent system, as shown in Figures C-2 and C-3, gives

feedback to the rig floor that the four (4) dogs in the tool haveengaged in the four (4) slots in the wellhead. The detent

system consists of four (4) lever pins, an actuator ring, four (4)

levers, and four (4) dogs. When the tool stem is rotated to theright or left the dogs rub on the inside bore of the housing until

they line up with the slots in the housing. At this time, the

stem is locked to the tool. When the dogs line up with theslots, the dogs move outwards by the force that is transferred

from the weight on the stem. This outward movement occurs,

because the weight on the stem transfers into the actuator ring,to the lever pins, to the levers which are hinged, and finally

into the dogs. When the levers swing out, the actuator ring

expands, and the stem drops approximately two (2) feetreleasing from the tool. This drop gives the rig feedback that

the dogs are now oriented with the slots.The load shoulder setting system, as shown in Figures C-4

thru C-6, is a series of parts in the tool starting from the stem

down to the dogs that utilize weight to release the load

shoulder from its prepacked position and push the shoulder down into its final setting position. By maintaining sufficient

weight down on the stem, the lower body of the tool begins to

stroke and the dogs make contact with the load shoulder,

breaks the shear pins, collapses the load shoulder by sliding itdown the load shoulder retainer, and then drives it down untilit comes to a stop. At this point, the load shoulder is also

locked down with a detent mechanism by the load shoulder

retainer.The test verification system, is a two (2) part system, as

shown in Figure C-7. First, it gives the rig feedback that the

tool has fully stroked. Prior to fully stroking, pumping downthe annulus will circulate fluids back up the drill pipe and vice

versa if pumping down the drill pipe. When the tool fully

strokes, the bulk seal at the top of the tool becomes energized

with weight down on the stem. At this point, the BOP is

closed and pressure is applied using the choke or kill line up to

15,000 psi. The lead impression pins in the tool at the load

shoulder are fully impressed which will be verified after

retrieving the tool. Second, the pressure test, which isolatethe wellhead from the equipment above, will also allow the

operator to test rig equipment at this time if desired up to

15,000 psi.

Casing HangersWith the addition of the new wellhead system, three (3)

new casing hangers have been introduced. First, the 18 in

hanger, which is the key string to the wellhead program

Second, is the 16 in. hanger, which is not a new size hanger,

but it is unique to this wellhead program since it has to work

in relation to the 18 in. Third, the 9-5/8 in. or 2nd positionhanger in the wellhead is unique in the fact that the hanger

does not have wickers. This allows more deflection in the

system while maintaining sealability up to 15,000 psi and not

sacrificing lockdown capabilities. Design considerations othe 9-5/8 in. hanger geometry and how the annulus seal work

are beyond the scope of this paper 2.

18” Casing Hanger System

This hanger and landing sub with the running and retrieva

tool is one of the key components of this system. Figure D-1

shows what it looks like in its operational condition. The 18

in. string allows operators to run casing with a 21 in. drilling

riser and an 18-3/4 in. BOP stack. The 18 in. hanger is a one piece passive design with a high strength load shoulder. I

does not have any loose parts. The hanger’s landing sub is a

one piece design as well. It is a machined component with ahigh strength load shoulder.

Since the amount of contact between the hanger and the

landing sub is so small, 0.093 in., the high strength rings arerequired to provide the bearing capacity that is required to

support the weight and pressure requirements. The smal

shoulder is designed to support approximately 500,000 lbs ofweight from casing and 4000 psi of pressure which induces an

additional 1 million lbs on the load shoulder when testing the

annulus seal with its running and retrieval tool. This shouldemust support approximately 1.5 million lbs of axial load. The

landing sub has a nominal inside diameter of 18.225 in. Thisdoes not leave much clearance between the 18 in. casing and

its sub. To allow for fluid to pass as the pipe is tripped in the

hole, slots have been machined in the sub that go around the

back side of landing ring, as shown in Figure D-1. The flow by area while tripping pipe is approximately 12 in2 with 0.2 in

particle size. Once the hanger has fully landed, the flow-by

area increases to 16 in2 with a 0.7 in. particle size for

cementing operations.The running and retrieval tool, shown in Figures D-1 thru

D-3, is used to install the hanger and seal in the hole in the

same trip. It can also run the hanger and seal in separate trips

This tool consists of two (2) basic systems, the camming system and lead impression system.

The camming system allows the operator to pump down

the drill pipe to function different features of the too

depending on how many right hand turns are made in the dril pipe. This can be done because the cam travels up the tool

with respect to the rest of the tool, using threads interfaced

with the stem. As the cam travels up, ports in the cam open

and close communications with various parts of the tool



OTC 15396 3

When four (4) turns are made in the tool, the tool locks to the

hanger, is ready to run down hole and is in the cementing

position. When eight (8) turns are in the stem, communicationis now open between the drill pipe and the seal setting piston,

as shown in Figure D-2. Figure D-3 shows what the seal looks

like in the energized position after the piston is stroked on thetool. When twelve (12) turns are in the stem, communication

is now closed with the seal setting piston and the tool unlocksfrom the hanger to allow releasing from the hanger. Thefeature of unlocking and locking to a hanger using a cam is

explained in detail in a previous OTC paper 63913.

The lead impression system, as shown in Figure D-2,

allows the operator to visually look at the tool and determine

exactly where the hanger is located relative to its landing sub.During the seal setting mode, pressure strokes out the lead

impression piston and it impresses in a machined groove in the

landing sub. The piston is then retracted when the tool is

pressurized from above to test the seal.In the event that the seal needs to be removed because it

did not hold pressure, it can be removed on a separate trip

using the 18 in. Seal Retrieval Tool. This tool lands off on thehanger, latches into the seal, de-enenergizes the seal, and pulls

it out of the hole. If another seal is decided to be installed,

then an 18 in. Clean and Flush Tool, would be used to clean

out the pocket between the hanger and the landing sub using

wash ports in the tool. This is a simple tool that lands on thecasing hanger, rotated to the right slowly to agitate any debris

and fluid is pumped down the drill pipe to circulate the debris.

16” Casing Hanger System

This system is similar to the 18 in. system in the fact there

is a hanger and annulus seal as well as its unique running andretrieval tool. The 16 in. hanger is larger than conventional 16

in. hangers that are used in 18-3/4 in. wellhead systems. Since

the inside diameter of a conventional wellhead isapproximately 17-9/16 in., the outside diameter of the hanger

must be less than this to pass through. However, the full-bore

wellhead system has a full opening of 18.630 in. that allows alarger hanger to pass through. The hanger requires a larger

outside diameter than a conventional 16 in. hanger to be ableto land off in the 22 in. string since the 16 in. landing sub has

to big enough to allow the 18 in. hanger to pass through.

Since the landing sub has to allow the 18 in. hanger to pass

through, it does not leave much shoulder for the 16 in. hanger to land on. This leads to a No-Go collet style hanger, as

shown in Figure E-1.

The No-Go collet hanger is a 3-piece design which

consists of a hanger body, No-Go collet and centralizer band,as shown in Figure E-1. When the hanger is run in the holewith its running and retrieval tool, the collet tags off on the

landing sub. Next, when sufficient weight has transferred into

the shoulder, the hanger slides down the collet and at the sametime the collet arms swing outwards and catch a larger profile

in the landing sub which will support all the weight and

pressure requirements. The centralizer’s function is to keep

the hanger centered in the 22 in. pipe as much as possible.This is to prevent the collet from pre-maturely activating while

tripping in the hole. This style of hanger is required because

the small tag shoulder only provides 0.06 in. amount of

contact between the landing sub and the hanger. The large

profile supports 750,000 lbs of weight and 6500 psi o

pressure which induces an additional 670,000 lbs on the load

shoulder. The load shoulder must also support approximately1.5 million lbs of axial load at any one time. To allow fluid to

pass as the pipe is tripped in the hole and to keep pipe surges

to a minimum there are slots on the outside of the hanger andslots and holes in the running and retrieval tool. The flow-by

area while tripping pipe and during cementing operations is 16in2 with a 0.7 in. particle size. However, the particle size wil

be slightly reduced when the 16 in. casing enters the 18 in

casing.

The running and retrieval tool, shown in Figures E-2 thru

E-5, is used to install the hanger and seal in the hole in the

same trip. This tool, like the 18 in. running tool, can run thehanger and seal in separate trips. This tool consists of two (2

basic systems, the camming system and the dual test pressure

system.

The camming system, is very similar to the 18 in. systemIt allows the operator to pump down the drill pipe to function

different features of the tool. As the stem is rotated to the

right, the cam moves up the stem on threads. During thiupwards travel, the ports on the cam open and close

communication between various parts of the tool. Like the 18

in. tool, communication is opened between the drill pipe and

seal setting piston when there are eight (8) turns in the stem, as

shown in Figure E-2. Another feature of this rising cam is thathe stem does not see a torque build up as the stem is rotated

since it does not move vertically. Like the 18 in. tool, as the

stem is rotated every four (4) turns the tool performs differenoperations.

The dual test pressure system gives the ability to test the

seal through the drill pipe or in the annulus. When there areeight (8) turns in the stem, the BOP is closed and pressure is

applied down the choke or kill line to test the seal. This

applies pressure across a large area, from the inside diameterof the landing sub where the seal is located, to the outside

diameter of the drill pipe where the pipe rams or annular bag

seals. When testing to higher pressures, up to 6500 psi, testingdown the drill pipe is required. This mode occurs when the

stem has twelve (12) turns in it, as shown in Figure E-4Weight is set down on the drill pipe that energizes a bulk seal

and pressure is applied down the drill pipe at the same time

This traps the pressure between the bulk seal and the annulus

seal. The trapped pressure prevents the tool from applying anend load effect on the hanger and landing sub, but tests the

seal.

In the event that the seal needs to be removed because it

did not hold pressure, the same procedures would take effecas it did for the 18 in. system, however, with a unique 16 in.Seal Retrieval Tool and Clean and Flush Tool.

Operations

Operators have and can use this new full-bore wellhead

system in different ways. Some choose conservative

approaches while others take more aggressive ones to gain trip

savings.Conservative method of installation:

1) Jet in 36 in. casing.

2) Drill out for 22 in. casing.



4 OTC 15396

3) Run in hole and cement 22 in. casing.

4) Install 18-3/4 in. BOP stack and 21 in. riser.

5) Drill out for 18 in.6) Remove the nominal seat protector from the high pressure

housing.

7) Remove the nominal seat protector from the 16 in.landing sub.

8) Run in hole and cement 18 in. casing.9) Install nominal seat protector in the 16 in. landing sub.10) Install nominal seat protector in high pressure housing.

11) Drill out for 16 in.

12) Remove the nominal seat protector from the high pressure

housing.

13) Remove the nominal seat protector from the 16 in.landing sub.


15) Install nominal seat protector in high pressure housing.

16) Drill out for 13-3/8 in.17) Remove the nominal seat protector from the high pressure

housing.

18) Set the load shoulder and verify proper installation.19) Run and set 13-3/8 in. casing.

Since the 18 in. and 16 in. casing hangers will not pass

through the wellhead with the nominal seat protector installed,

it must be pulled prior to running the casing strings. Having to pull the protector prior to running 18 in. and 16 in. is a

downside to the full-bore system. Since clearances have

become so tight between the 22 in., 18 in. and 16 in. strings,something had to give to make this system work. In a

conventional wellhead system, 16 in. casing has a smaller

outside diameter which lands in a sub located in the 20 in.string and can run through the nominal seat protector without

having to retrieve it prior to running casing. As a result of this

downside, a new tool that allows operators to run a bore protector on the drill string is available to operators who are

willing to take more chances to save trips.

A more aggressive method of installation that allows tripsavings is the following:

1) Jet in 36 in. casing.2) Drill out for 22 in. casing.


4) Install 18-3/4 in. BOP stack and 21 in. riser.

5) Drill out for 18 in. with Drill String Installed Wear Sleeve Assembly and Running and Retrieval Tool.


7) Drill out for 16 in. with Drill String Installed Wear

Sleeve Assembly and Running and Retrieval Tool.8) Run in hole and cement 16 in. casing.9) Install the nominal seat protector in high pressure

housing.

10) Drill out for 13-3/8 in.11) Remove the nominal seat protector from the high

pressure housing.

12) Set the load shoulder and verify proper installation.13) Run and set 13-3/8 in. casing.

The (DSI-WS), Drill String Installed Wear Sleeve, allows

an operator to run a wear sleeve in the drill string and not

make additional trips to run and retrieve it (Figure F). The

tool is located above the bottom hole assembly latched to its

running and retrieval tool. When the string is tripped in the

hole, the wear sleeve latches into the high pressure housing

releases from the running and retrieval tool with right handrotation and the drilling string travels down hole to commence

drilling. The sleeve essentially protects the wellhead while

drilling. When the string is coming out of the hole the weasleeve latches back onto its tool and is retrieved.

The second method is more aggressive than the first because the high pressure housing seal profiles and 16 in. sea profile are exposed to the bottom hole assembly and bit when

passing through. Furthermore, the 16 in. sealing profile is also

exposed while drilling. Some operators are willing to take this

risk to save trips. In the case that the 16 in. seal does not hold

pressure, cement is one option to make the seal.For those operators who choose the more aggressive plan

six (6) trips are eliminated as compared to the conservative

plan. If the 16 in. protector is used then only three (3) trip

will be saved relative to the conservative plan. The protectohas to be pulled prior to running 18 in. and 16 in. casing.

Pre-development and Final Qualification ProgramEarly in the program, a stacked wellhead system was designed

and built to add one more casing string to a conventiona

wellhead. The 18 in. casing string was located in its landingsub in the 22 in. The 16 in. string was landed and located on

top of the 18 in. hanger. The 16 in. sitting on top of the 18 in

coined the term ‘stacked system’. This system allowed fo

100% passive hangers on both. Furthermore, if the 18 instring did not need to be run, the 16 in. hanger could land in

the same sub the 18 in. lands on. However, this system did

have a serious downside. If the 18 in. hanger did not make i

all the way down in the proper location, the 16 in. hanger

would also sit high. This could have created sealing problemsAs a result of this deficiency, the split full-bore system was

created. The 18 in. and 16 in. hangers were separated and

could be run as far apart and as close as desired within reasonThe split system went through vigorous testing in the

laboratory.

The load shoulder was load tested to 6.2 million lbs. Theload was simulated by apply 22,500 psi on a test plug across

an 18.630 diameter. The load shoulder showed negligible

brinelling after testing.

The 18 in. and 16 in. hanger systems which include

hangers, seals and running and retrieval tools were fully testedin their respective landing subs. The subs were welded in a

piece of 22 in. of pipe with test apparatuses to cross over to a

hydraulic ram underneath and above to push and pull the

running and retrieval tool to simulate offshore operations tofunction the tool.

Field Installation Status

In early part of 2001, this new wellhead was installed for the

first time in the Gulf of Mexico. The new high pressure

wellhead housing with the full-bore opening along with the 18in. and 16 in. were successfully installed. Since that time five

(5) more systems have been run and set with 100% success

through the year 2002. In 2003, six (6) to ten (10) more

systems are planned for installation. The numbers show tha



OTC 15396 5

there seems to be an increasing demand for this type of

system.

Conclusions

This new full-bore wellhead system gives operators theadvantage of running one more casing string through a high

pressure housing under BOP control. Being to able to drillone more hole section with mud that returns to the surfacethrough the 21 in. riser, lets operators work through the

difficult surface shall zone hazards.

It allows operators to use existing rig equipment and

capabilities. Rig space is saved because only one riser andone BOP stack need to be used to drill the entire wellhead

program and still have one more large casing string.

The new system provides the opportunity to drill deeper

and reach the required zone and/or complete the drilling

program with a larger size hole.However, this new system is more difficult to run than a

conventional system, due to the tighter clearances between

strings. Hence, pipe has to be run slower to reduce surge pressures and flush or near flush joint connections need to be

used on 18 in. and 16 in. casing.

In general, when one more casing string is needed to

complete the drilling program or to be able to have one morestring “in your back pocket” for those just in case or

unanticipated situations, the full-bore system is the wellhead

that can do that.

References1) Barker, J. W.: “Wellbore Design with Reduced Clearance

Between Casing Strings,” SPE/IADC 37615.

2) Milberger, L.J. and Boehm, C.F., “High Performance Metal-SealSystem for Subsea Wellhead Equipment,” OTC Paper 6085,

1989.3) Danner, B.L. and Henderson, H.O., “Development of an

Advanced Subsea Wellhead System Incorporating All Metal-to-Metal Sealing,” OTC Paper 6391, 1990.



6 OTC 15396

Figure A22 in. Casing Hanging from High Pressure

Housing with 16 in and 18 in Landing Sublocated in the 22 in. casing

18 in.

Landing Sub

22 in.

Casing

16 in.

Landing Sub

18 in

Pack

18 in

Han

16 in.

Packoff

16 in.

Hanger



OTC 15396 7

Lock Ring

Remotely ActivatedLoad Shoulder

MechanicalRetainer

Support Ring

Positive Loc

Figure B-118-3/4 in. Full-bore High Pressure Housing

with 18-5/8 in. ID

Figure B-3Load Shoulder Mechanism shown

energized and ready to run 13-3/8 in casing

Figure B-2Load Shoulder Mechanism shown Pre-

packed in wellhead to allow full opening

Figure B-4Looking down the high pressure housing

to the load shoulder

Figure B-5Looking up the high pressure housing to

the load shoulder

Load Shoulder



8 OTC 15396

Figure C-1Load Shoulder Actuation Tool (LSAT) in

High Pressure Housing

Landed in Housing Locating Slots in HighPressure Housing

Figure C-3:Detent System after finding slots

WellheadSlot

Figure C-2:Detent System prior to finding slots

Lever

Actuator Rin

Lever Pin

Dog

Ste

Lower Body



OTC 15396 9

Figure C-4:Load Shoulder Actuation Tool (LSAT) load

shoulder setting and function testverification systems

Shear Pin

Figure C-5:Dogs Landed o

Load Ring

Figure C-6Load Ring is

Figure C-7Lead Impress

pins areimpressed

Lead Pin

Dog

Shear PinLoad Shoulder

Load Shoulder Retainer

Bulk Seal



10 OTC 15396

Figure D-3:18 in. Seal is set when piston

stroked

Seal

Piston

Figure D-2:Drill pipe is communicating with piston to be

able to set seal and Lead Impression System

Communication Access

Lead ImpressionSystem

Stem

Figure D-1:18 in. Casing Hanger set on landing sub

with its Running and Retrieval Tool

Casing Hanger

Flow-by Slots

Load Shoulder

Landing SubCam

Dogs Engagedin Hanger



OTC 15396 11

Casing Hanger Body

Centralizer Band

No-Go Collet

Tag Shoulder

Landing Sub

Dogs engagedin Hanger

Figure E-1:16 in. Casing Hanger set on landing sub

with its running and retrieval tool

CommunicationAccess

Stem

Cam

Piston

Figure E-2:Drill pipe is communicating with piston to

be able to set seal

Seal in setposition

Figure E-3:

16 in. seal is set when piston stroked

Piston



12 OTC 15396

Figure F:Drill String Installed Wear Sleeve with

Running Tool

Running andRetrieval Tool

Landed in High

Pressure HousingTool releasing from

Wear Sleeve

Wear Sleeve

Figure E-4:Cam has moved up to open

communication to test seal through drillpipe with twelve turns in stem

Bulk Seal

CommunicationAccess to Seal

Wellhead Housing Otc15396

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