Wellhead Systems
Introduction to Wellhead Systems
SECTION 1
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CONTENTS
Wellhead Assembly.......................................................................................................................... 3
Wellheads and Associated Equipment............................................................................................. 4
Casing Head.................................................................................................................................... 5
Test Plug.......................................................................................................................................... 6
Wear Bushing aka (bowl protector).................................................................................................. 6
Casing Hangers (slip and seal assembly)......................................................................................... 6
Automatic Seal, Slip-Type Casing Hanger......................................................................................... 7
Non-Automatic Seal, Slip-Type Casing Hanger.................................................................................8
Secondary Seal Assemblies............................................................................................................. 8
Casing Spool.................................................................................................................................... 8
Tubing Head (aka Tubing Spool)....................................................................................................... 9
Tubing Hangers.............................................................................................................................. 10
Hanger Flanges........................................................................................................................... 10
Slip-Type Tubing Hanger.............................................................................................................. 10
Wrap Around Tubing Hangers..................................................................................................... 10
Mandrel Tubing Hanger............................................................................................................... 11
Flanges and Seal Connections....................................................................................................... 12
API Ring Gaskets............................................................................................................................ 13
Type R Ring Gasket..................................................................................................................... 13
Type RX Ring Gasket................................................................................................................... 13
Type BX Ring Gasket................................................................................................................... 13
NON-API Connections.................................................................................................................. 14
Wellhead Systems for Unique Applications....................................................................................15
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WELLHEAD ASSEMBLY
A wellhead is part of an oil well that terminates at the surface, whether on land or offshore. The
primary role of the wellhead is pressure containment and to hold the casings and the production
tubing. Every oil or gas well has some type of wellhead. Conventional wellhead assemblies
include the casing head, casing hangers, spool sections, tubing head, tubing hanger, valves and
fittings. The assembly of valves and fittings that sit on top of the wellhead are also known as the
Christmas tree.
Wellheads provide for a safe and adequate means for supporting and attaching blowout control
equipment during drilling. It also provides sealing between casing strings and a connection for
the Christmas tree, which controls the flow of fluids from the well. Lastly, the wellhead provides
an additional opening into the well which may be utilized for stimulation treatments, circulating
fluids, producing the well and other emergency or miscellaneous uses that might arise during the
life of the well. Figure 1.1 shows a typical wellhead and tree assembly.
200
300 0
0
100
0
4000
500
0
0
Figure 1.1
Conventional Wellhead and Christmas Tree Assembly
Section D
Production Tree
Section C
Tubing Spool
Section B
Casing Spool
Section A
Casing Head with Landing Base
Conductor Pipe
Surface Casing
Intermediate Casing
Production Casing
Production Tubing
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WELLHEADS AND ASSOCIATED EQUIPMENT
A casing head should be installed on the first string of casing requiring blowout preventers (BOP)
for further drilling. The BOP Assembly is no better than:




The
The
The
The
casing to which it is attached
primary cement jobs
breakdown strength of the formations at the casing seat
wellhead between the casing and the preventers
Surface casing is important blowout protection
because it is the anchor and base for the blowout
preventers.
The annular space between the
conductor and the surface casing should be filled
with cement to center the wellhead beneath the
rotary and to stabilize the blowout preventer
assembly. The wellhead holds in position the BOP
equipment used for well control during drilling
operations. It is the vital link between preventer
equipment and the casing strings required to drill
and produce the well. The wellhead assembly
serves several important purposes:



To support a large part of the weight of the
subsequent casing strings
Provide a pressure seal between the outer
and inner casing strings
Provide an outlet to bleed off pressure that
might accumulate between the two strings.
Figure 1.2
BOP Stack Made Up to Wellhead
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CASING HEAD
The A-Section, the lowermost wellhead section, may
be attached to the casing by either a female thread or
a slip-on and weld connection to fit the particular size
casing. Threaded connections are simple to install
and permit easy removal, but they require that the
casing be run and set with the threaded coupling at
precisely the desired elevation. Because spacing out
the connection at the desired elevation is often a
problem, a slip-on and weld connection is usually
preferred (Figure 1.3). This requires welding services
for installation. Also, routine field welding on grades
higher than K-55* is not recommended. When
installing the casing head, great care should be taken
to assure that the casing head is level and aligned
with the rotary table. In turn the derrick should be
Figure 1.3
level. This will eliminate contact between the Kelly and
Slip On Weld (SOW) Casing Head Installed
the BOP/casing head system during subsequent
drilling which could cause damage to the seal and support areas.
After installation, based on rated pressures of the pipe and flanged fittings, the casing
head/casing connection should be hydrostatically tested. The casing head usually provides one or
more side openings that provide access to each casing annulus and can be used for bleeding off
pressure or for pumping into a well. Continued pumping of mud through these fittings might erode
them so badly that they would not hold well pressure when needed. Presence of pressure should
be checked periodically. Casing head side outlets may be screwed, studded, clamp hub, or
flanged. Casing heads with screwed outlets are acceptable for service up to and including 5,000
psi working pressure, provided that the casing head working pressure rating is the same. Some
companies require flanged or studded connections for all 5,000 psi and higher working pressure
heads.
In sizing casing heads, the top flange must be
sized to permit drilling the desired hole size and
subsequent running and hanging of casing strings.
Usually the flange opening is sized to equal or
exceed the casing inside diameter of the casing
string on which it is installed. Adapter spools or
flanges to connect blowout preventers of different
sizes or pressure ratings to the casing head are
not desirable, though sometimes they are
necessary. Adapters constitute another joint in
the assembly that might leak. Also, it is not good
practice to use a preventer too large for the
casing head.
Large preventers are heavy and sometimes cause
flanges to leak because of vibration and shaking.
Figure 1.4
Casing Head with Base Plate
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Most A-Sections are designed for universal use for most types of completions. They can hang the
most casing strings without being permanently damaged and in the event of a dry hole can be
salvaged and used again after being refurbished. In some locations, a landing base or base plate
may be required to help support the wellhead load. In water or marsh locations, the drive pipe
must normally support a portion, if not all, of the total tubular load. A landing base, also called
base plate is usually required on the first string of casing out of the drive pipe to facilitate this
transfer of load. The particular wellhead manufacturer should be consulted for load ratings of
various size landing bases. On land locations for deep wells, landing bases may also be desirable
or necessary. In these types of applications it may be appropriate to provide a reinforced concrete
cellar floor to help support the landing base.
TEST PLUG
Once the casing head is installed and the BOP stack is
attached, all connections must be tested. As shown in
Figure 1.5, a test plug is lowered through the BOP
stack on a joint of drill pipe and landed in the casing
head bowl. This isolates the surface casing from test
pressure and allows the top flange of the casing head
and all the equipment above it to be tested.
The test plug is designed to match the profile of the
casing head bowl, land properly on the load shoulder
and seal against the bore of the casing head. It is
important that the correct size and profile of test plug
be used. After a satisfactory test, the test plug is
retrieved and drilling commences.
WEAR BUSHING
AKA
Figure 1.5
Running a Test Plug
(BOWL PROTECTOR)
A wear bushing is used to protect the load shoulder
which will support the next casing string. This
protector is run and landed through the BOP assembly
with a running tool. The running tool is retrieved
before drilling starts. In some cases, the test plug
serves dual duty: test plug one way, but if turned
upside down, it becomes a combo running and
retrieving tool for the wear bushing.
Lock screws are often desirable to keep the bowl
protector from spinning along with the drill pipe. Lock
screws can either be ordered as part of the casing
head or included in a special adapter flange made up
between the casing head and the BOP stack.
Figure 1.6
Installing a Wear Bushing
The BOP must be tested periodically during the
drilling process and each time the bowl protector must be retrieved in order to run a test plug.
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CASING HANGERS (SLIP AND SEAL ASSEMBLY )
The casing hangers, which are most generally used in standard operations, are the slip-packoff
types of which there are two general categories:
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1. Those that may be set through preventers but require removal of preventers to establish
a seal;
2. Those that may be set and sealed without removing blowout preventers, the automatic
type.
The type chosen depends upon casing loads and operating conditions. Either of these categories
of hangers will permit setting casing at desired depths without the use of pup joints.
AUTOMATIC SEAL, SLIP-TYPE CASING HANGER
Typical automatic slip style wrap-around
casing hangers (Figures 1.7 and 1.8) are
hinged and feature a weight-set seal which
automatically energizes when the hanger is
properly landed. Slip hangers are installed on
the casing joint by wrapping around the pipe,
latching the hanger together, releasing the
internal wedge-shaped slips and lowering
through the blowout preventers into the
casing head.
When the weight of the suspended casing is
transferred to the hanger slips and to the
casing
head,
the
elastomer
seal
is
compressed and extrudes to seal between the
rough casing and the smooth bore of the
casing head. Most designs which do not
incorporate a method to limit extrusion of the
seal or downward movement of the slip
Figure 1.9
Non-Automatic Seal, WFT-21P Slip-Type Casing Hanger with
manually energized seal
segments have a maximum design load which
the combination of casing weight and test
pressure must not exceed.
Figure 1.7
Automatic Seal, WFT-22 Slip-Type Casing Hanger
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Another result of excessive casing load can be impingement of the casing by the slips. Often, a
controlled suspension technique (dulled teeth on the back of the slips) increases friction between
the slips and the hanger body and prevents the slips from moving far enough downward to deform
the casing. These hangers (Figure 1.8) are designed
for heavy casing loads and are, therefore,
recommended for long strings where the automatic
sealing feature is also required. Generally, the
longer the slips, the greater the safe load carrying
capacity. Slip manufacturers have extensive test
data on their slip design supporting their
recommended safe hanging loads.
NON-AUTOMATIC SEAL, SLIP-TYPE
CASING HANGER
With the non-automatic casing hanger, the wrapped
around hanger is lowered through the preventers to
suspend the pipe. The pack-off seal must be
tightened after removal of preventers. The seal is
Figure 1.11
Casing Spool
expanded, depending upon the make, by cap screws on
top of the packing (Figure 1.9) or by external lock screws.
This design of manually sealed slip-type hanger is recommended for shallow or medium depth
wells where casing weight is not enough so automatic sealing is not possible.
SECONDARY SEAL ASSEMBLIES
To increase the pressure rating in the upper portion of
the wellhead, it is necessary to provide isolation
from the lower pressure section below. This is
commonly achieved by a secondary seal assembly
known as a pack-off or o-ring secondary seal in
the lower portion of the next spool to be added
after the casing is landed and cut. With secondary
seal in place, any pressure applied to the upper
portion of the spool does not affect the bottom
flange. Figure 1.10 shows a typical pressureenergized seal assembly. Test ports should be
provided to test the secondary seal as well as the
flanged connection. These secondary seals can be
supplied in various nominal casing sizes in one of
two ways: as a separate bushing or integral to the
bottom flange of the mating spool.
CASING SPOOL
1.10
FigureFigure
1.8
Heavy Pressure-Energized
Duty Automatic Seal, WFT-29
Slip-TypeSeal
Casing Hanger
Secondary
with extra slips to suspend heavier casing strings
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If a protection string is required to drill deeper, an intermediate casing spool is installed after the
casing is hung off and cut. This B-Section, shown in Figure 1.11, usually includes one or more
secondary seals as discussed above. External flanged or studded outlets should be used for
5,000 psi working pressure and higher service. Designing a casing spool closely follows the
design of the wellhead housing. The top flange must permit drilling the desired hole diameter and
hanging the next string of casing or tubing. The top flange may have the next higher pressure
rating over the mating flange on the bottom when a secondary seal assembly is used. This casing
spool provides the bowl for suspending and sealing the production casing string. Blind flanges
and VR (valve removal) plugs should be installed in studded or flanged outlets for all casing heads
and spools, which are not equipped with a valve. Nipples with special internal VR threads (often
referred to as reinstallation nipples) are sometimes used in screwed outlets. Such devices permit
installation of a valve under well pressure conditions.
TUBING HEAD (AKA TUBING SPOOL)
In a three-string wellhead, the production casing is run, hung and sealed in the B-Section in the
same manner as the intermediate string. After removing the BOP assembly, the casing is
suspended, cut, and the primary annulus seal is installed and tested.
In a two-string wellhead, as illustrated in Figure 1.12, when the
protection string is not required and/or a liner is set in lieu of
bringing the production casing back to surface, the B-Section will
not be required. In this case, after the production casing is
landed, the tubing head is installed above the A-Section. In highpressure wellhead assemblies, a crossover pack-off flange may
be required. Often, a smaller size and higher working pressure
BOP assembly is utilized for completion work. Tubing, like casing,
is run through blowout preventers and hung-off in the tubing
head. The design of the tubing spool is similar to that for a
casing spool. The bottom flange must have the same size and
pressure rating as the mating flange. The upper flange may be
one pressure rating higher if a secondary seal is used in the
lower flange to isolate it. Some customers prefer studded outlets
for 5,000 psi and higher working pressures.
The top flange size and minimum bore through the spool should
be selected to permit running full casing ID tools. When liners or
contingency strings are provided in a drilling plan, it should be
noted that it is essential for safe workover operations that the
tubing spool bore be sufficiently large enough to allow packers,
bridge plugs, etc., to pass through and set in any casing size
exposed in the well. On a pumping well, practically any tubing
head is acceptable as long as it meets the pressure and strength
requirements of the well. It should not be so tall that an elevated foundation is required for the
pumping unit. Injection well tubing head selection is usually not critical. Any spool that meets the
pressure and strength requirements should be adequate. The pressure rating should be high
enough to safely contain the maximum anticipated injection pressure as this pressure could be
applied to the tubing head in the event of a tubing leak. For shallow (less than 3000 feet) low
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pressure (less than 1500 psi), short life (5 to 10 years) wells, the screwed and capped tubing
heads are acceptable for flowing, pumping or injection wells. An example of a low pressure
flowing well is shown in Figure 1.12.
Figure 1.12
Two-String Wellhead with Hanger
Flange Wrap-Around Tubing Hanger
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TUBING HANGERS
There are numerous methods available to hang tubing strings. The most suitable all purpose
hanger is the mandrel type, internally grooved or threaded for a back pressure valve. Hangers
should normally be EUE (external upset end) to provide a standard connection but some
customers prefer to have the same thread top and bottom even when an exotic or premium
thread is being used.
HANGER FLANGES
Use of internally threaded tubing head adapter flanges (aka hanger flanges), shown in Figure
1.12, should be restricted to low pressure single completion oil wells. The primary disadvantage is
lack of well control due to the fact that there is no back pressure valve (BPV) preparation. Also,
this hanger may cause a minor space out problem if the well is equipped with a packer or
mechanically set tubing anchor.
SLIP-TYPE TUBING HANGER
A slip-set hanger is acceptable for relatively shallow
(8,000 feet or less), low pressure (less than 1,000 psi) oil
wells. The slips and packing gland hold and seal the
tubing. A stripper rubber can be installed in the tubing
head spool for low pressure well control while handling the
tubing.
In general, slip type hangers should be avoided except on
shallow wells. The slip crushing loads that may occur as
the result of a shallow rod failure should be considered.
WRAP AROUND TUBING HANGERS
The “wrap-around” tubing hanger is not really a hanger
since it supports no weight. Instead it is a split, wraparound packoff that allows reciprocation of the tubing
string to displace fluid, set packers, etc. while maintaining
complete control of annulus pressure. The design of the
hanger relies upon a resilient seal energized by the lock screws of the tubing head causing the
compression of the seal on the non-machined OD of the
tubing. A wrap-around tubing hanger is used in conjunction Figure 1.13
Wrap-Around Tubing Hanger with a Hanger
with either a hanger flange (Figure 1.12) or a tubing hanger Coupling
coupling (Figure 1.13) which allows the use of a back pressure
valve.
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MANDREL TUBING HANGER
The mandrel type hanger with internal preparation for BPV (back pressure valve), as shown in
Figure 1.14, should be used on all wells of 5,000 psi and higher working pressure. An extended
neck which seals into the tubing head adapter flange should also be used. Mandrel type hangers
require lock screws in the top flange of the tubing spool to hold the hanger in place and to
activate the annulus seal between the hanger and the bowl. On dual wells, a segmented mandrel
type hanger is preferred. The design of this type of hanger permits well control by use of a back
pressure valve, provides maximum clearance through the tubing head, allows running or pulling
of either string and assures positive hanger orientation. Wells requiring more than two strings of
tubing are very unusual and the hanger designs will be customized. For injection wells, a slip type
hanger may be acceptable unless
the well is capable of flowing
back large quantities of injection
fluid which could be damaging to
the environment or personnel. In
this case, a mandrel type hanger
prepared for a back pressure
valve should be used. Depending
on the type of fluid, it may be
advisable to make the hanger out
of stainless steel or other similar
non-corrosive material.
Figure 1.14
Mandrel Tubing Hanger with extended neck
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FLANGES AND SEAL CONNECTIONS
The most common end connections used in the oil industry aside from welds and threads are
flanges. Most companies will only use API flanges on wellheads, Christmas trees, blowout
preventers, rotating heads, valves connected to them and other drill-through components. API
flanges are pressure sealed by means of ring joint gaskets made of soft iron, low-carbon steel or
stainless steel. Per API, all flanges in the stack, wellhead, tree and side-outlet flanges should be
fitted with new ring joint gaskets each time they are assembled. API ring joint gaskets are also
used for the smaller lines and fittings leading away from the preventer stack. The oval or round
type R ring gasket was the first ring type joint gasket designed by API. API Flange specifications
are
tabulated
below:
7,500
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API RING GASKETS
TYPE R RING GASKET
The R ring-type joint gasket is energized by compression as the mating flanges are made up and
is not energized by pressure. The gasket is actually crushed against the ring groove to create a
metal seal. Sealing takes place along narrow bands of contact between the grooves and the
gasket on both the OD and ID of the gasket. The gasket may be either oval or octagonal in cross
section. The R design does not allow face-to-face contact between the hubs or flanges, so
external loads are transmitted through the sealing surfaces of the ring. Vibration and external
loads may cause the small bands of contact between the ring and the ring grooves to deform
plastically, so much so that the joint may develop a leak unless the flange bolting is periodically
tightened. If additional weight is added to the upper half of a flange, such as in a wellhead assembly, it may crush
the ring additionally and have the same effect as loosening the flange bolts. Standard procedure with type R ring joints in
the BOP stacks is to check and re-tighten the flange bolting weekly. API recommends that a new gasket be used each time
the connection is made up.
TYPE RX RING GASKET
The RX gasket is a pressure-energized ring that fits the standard API flange ring groove and has
been accepted by API as an alternate form of ring gasket. The RX ring evolved during the
development of 15,000 psi working pressure flanges. It was determined when testing with
octagonal rings that when the ratio of the height of the ring to the height of the sealing surfaces
was 3 to 1 or greater, the seal was energized by pressure. That is, the internal pressure tended to
expand the ring gasket against the outer sides of the ring groove with sufficient force to energize
a seal. To insure that initial contact is made between the sealing surfaces of the ring and the
outer surfaces of the ring groove, the pitch diameter of the ring is made slightly larger than the
groove, and the ring height is generally greater in proportion than the conventional octagonal
ring.
The advantages of the RX ring are:
1. Less bolt load is required as the ring does
not have to be overly crushed to affect the
seal;
2. It is pressure energized.
The fact that the ring does not require excessive
crushing while tightening permits faster tightening
of the flanges as a reduced number of rounds of
bolt tightening is required. This is especially helpful
when working with large flanges in a limited
working space such as with blowout preventers
and drill-through equipment underneath the
derrick floor. It is important to point out that care
should be exercised to have the bolts tightened
securely to prevent breathing of the flange and
subsequent galling of the flange seals.
Figure 1.15
The evolution of the API steel ring joint
gasket from the original oval R to the square,
pressure-energized BX
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TYPE BX RING GASKET
The 15,000 psi working pressure BX flange design was developed by
AWHEM (the Association of Wellhead Equipment Manufacturers) for
the industry. The seal ring, although it is square, has a 3: 1 height to
seal pressure energizing ratio. The BX flange now adopted by API is
different from the standard flange in that the raised faces touch when
tightened, as shown in Figure 1.15. The old API ring and flange design
would have to be tremendously large for 15,000 psi working pressure.
This BX flange design results in substantial weight savings and the
technique has been extended to the 5,000 and 10,000 psi working
pressure flanges for some sizes.
NON-API CONNECTIONS
Various proprietary connections are commonly used throughout the
industry for pressure sealing wellhead and blowout preventer Figure 1.16
Grayloc Clamp Connection
equipment, particularly in underwater drill-through hookups. API has
developed specifications for a clamp tree connector. These are
covered in API Specification 6A for 5,000 psi and 10,000 psi working pressure connections. This
type of clamped connection uses the API RX ring gasket. It should be noted that API clamped
connectors can be provided on 2,000 psi and 3,000 psi working pressure equipment. The
connectors are the same as 5,000 psi working pressure but do not increase the rated working
pressure of the equipment.
The Grayloc style clamp connection (Figure1.16) utilizes a well bore type of seal and thus does not
have a ring groove. It is pressure energized and is no longer a proprietary connection.
The advantages of this type of connection are:
1. Reduced area exposed to pressure, thus reducing end thrust;
2. Quick connecting, thus time saving;
3. Reusable seal ring;
4. Lighter weight.
A disadvantage is that the bore of the seal ring may be subject to damage from tools and direct
washing action of fluids. The Grayloc style of ring gasket and clamps is marketed under different
names for both the US and international markets.
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WELLHEAD SYSTEMS FOR UNIQUE APPLICATIONS
Multi-Bowl Wellheads (aka split speed heads, compact wellheads, etc.) should be considered
where time savings, improve safety, and reduced wellhead height are desired. One time
consuming activity is disconnecting/reconnecting (nipple down/nipple up) of the BOP stack. This is
usually performed after each casing string is run when the subsequent wellhead spool is added to
the stackup. Multi-bowl wellheads reduce the number of times the BOP has to be manipulated by
providing support and seal capabilities for more than one casing string in one wellhead assembly.
The wellhead assembly consists of two full-bore housings installed as one unit (Figure 1.17) where
the hangers stack on top of each other and are supported by one large support shoulder. Multibowls allow uninterrupted blowout preventer protection while providing improved safety to
personnel and the environment. If the mandrel hanger does not land properly due to improper
casing space-out, the wellhead sections can be separated to allow for use of conventional sliptype casing hanger to suspend the casing. For offshore applications, similar systems have been
developed which feature special large connectors for diverters (part of the offshore drilling mud
circulation system).
Figure 1.17
Multi- Bowl Two Stage System