1. WELLHEADS

2. TEAMWORK
• Mohamed Abdelshafy Mahmoud Abozeima
cell: +20-102-003-2271
• Abraham Makoi Benny
cell: +20-111-676-0178
• Omar Labib
cell: +20-101-693-9292
• Alshimaa Ibrahim Mohamed
cell: +20-101-436-1152

3. REFERENCES
• Heriot Watt University - Production Technology I
• API 6A Wellhead Manual
• Wood Group Wellhead Manual
• Http://Petrowiki.Org
• Http://Www.Glossary.Oilfield.Slb.Com/
• Https://Www.Onepetro.Org
• Minimum Wellhead Requirements An Industry Recommended Practice (IRP) For The
Canadian Oil And Gas Industry Volume 5
• Development Consultant, Training On Beam Pumping, Module A.
• Cameron Mudline Suspension System.

4. OUTLINES
• Background on Oil and Gas Wells.
• Component Requirements Applicable to All Wellheads.
• Basic Components of a Wellhead.
• Advanced wellhead techniques
• Sweet Flowing Wells.
• Critical Sour, Sour and Corrosive Wells.
• Artificial Lift Wells.
• Other Well Types.
• Wellhead Installation.

5. BACKGROUND ON OIL AND GAS
WELLS
• fresh water sources pre-date 5000 BC.

6. BACKGROUND ON OIL AND GAS
WELLS
• By 1000 AD, drilled depths of over 200 m were
achieved and wood was being used to cap or
contain the fluid and pipeline production.
• The first "modern" wells were drilled in the mid-
late 1800s.
• But wells were opened to air!!!!!

7. WELLHEAD MAIN FUNCTIONS
1. Casing/Tubing suspension.
2. Pressure sealing and isolation between casing at surface when many casing strings are used.
3. Provides a means of attaching a blowout preventer during drilling. (Video)
4. Provides a means of attaching a Christmas tree for production operations.
5. Provides a reliable means of well access. (Tubing Head)
6. Provides a mean of attaching a well pump. (Artificial Lift)
7. Provides pressure monitoring and pumping access to annuli between the different
casing/tubing strings (video)

9. WELLHEAD CLASSIFICATION
ACCORDING TO THE WELL
LOCATION
• Wellhead for land drilling.
• Surface location offshore.
– Jack-up, platform (Mudline Suspension
sys.)
• Subsea wellhead.
ACCORDING TO THE WELLHEAD
DESIGN
• Spool Wellhead System
• Unitized Wellhead System

10. WELLHEAD CLASSIFICATION
Well Types
Flowing Wells
Sweet
Sour
Artificial Lift
Wells
Sucker Rod
Pump
ESP
PCP
Gas Lift
Plunger Lift
Hydraulic
Pump
Velocity
String
EOR
Injection
Hydraulic
Fracking
Disposal Well
Steam Assisted
Gravity Drainage
Cycle Steam
Stimulation
Other Types
Other Types
Cavern wells
Observation
Wells
• ACCORDING TO WELL TYPES

11. COMPONENT REQUIREMENTS
APPLICABLE TO ALL WELLHEADS
• Wellhead equipment that meets API Specification 6A (equivalent to ISO
10423) is available in standard pressure increments:
– 13.8 MPa (2000 psi)
– 20.7 MPa (3000 psi)
– 34.5 MPa (5000 psi)
– 69.0 MPa (10,000 psi)
– 103.5 MPa (15,000 psi)
– 138.0 MPa (20,000 psi)
– 207 MPa (30,000 psi)

12. COMPONENT REQUIREMENTS
APPLICABLE TO ALL WELLHEADS
• Standard temperature ratings are defined by an operating range.
– Conventional operations span -60 to 121⁰C in 8 ranges (K, L, P, R, S, T, U, V). K and U are
the largest and overlap the other ranges.
– Elevated temperature operations span -18 to 345⁰C in 2 ranges (X, Y). Y has the highest
temperature rating.

13. COMPONENT REQUIREMENTS
APPLICABLE TO ALL WELLHEADS
• Product Service Level (PSL) defines the degree of
testing applied to the wellhead component.
–PSL-1 is the baseline.
–PSL-2, PSL-3, PSL-3G, and PSL-4 include additional and
ever more stringent requirements to confirm component
suitability for challenging operations (e.g. high pressure,
elevated temperature, sour).

14. BASIC COMPONENTS OF A WELLHEAD
• Casing Head
• Casing Spool
• Casing Hangers
• Pack-off Flange
• Tubing Head
• Tubing Hanger
• Tubing Head Adaptor
• Christmas Tree
• Connections
• seals

18. CASING HEAD
• The casing head, also referred to as a casing bowl.
• Is the lowest part of the wellhead assembly.
• The bottom of the casing head is configured to attach to the casing below (typically, the
surface casing).
• The upper inside of the casing head provides a bowl in which the next casing string can
be set and sealed (if required).
• The top of the casing head then connects to the next wellhead component.
• A casing head may also be supplied with a landing base plate that takes the weight load
off the surface casing and spreads it over the conductor pipe.
• Access to the annulus between the surface casing and the next casing string is available
through side outlets.

20. W2 CASING HEAD
2,000 : 10,000 psi
PRL-2
Accept all hanger
types

21. W2 CASING HEAD WITH S4 SURELOK
CONNECTOR
Would eliminating welding save you rig time?

22. SCH1 CASING HEAD
Want to save time installing your Casing Head?
• No welding required to install riser on conductor.
• No waiting on cement required when running
surface casing.
• Installed through drilling riser as part of surface
casing string.
• No welding required to install the casing head.
• Allows normal cementing.
• 3,000, 5,000 or 10,000 psi working pressure.

24. CASING HEAD FUNCTION
• Isolate the inside of the surface casing from the outside environment.
• Provide a platform for and a means to test the rig BOP stack during drilling and
well servicing operations.
• Support or transfer the weight of drilling and workover equipment during
drilling and well servicing operations.
• Allow for suspending and packing off the next casing string
• Provide access to the surface inner casing annulus for monitoring and fluid
return purposes.
• Access to the annulus is available through side outlets drilled through the
casing head.

25. CASING SPOOL
• If a well includes one or more intermediate casing strings between the surface and
production casing, the next component required after the casing head is the casing
spool.
• The bottom of the casing spool mounts on top of a casing head or previous spool,
and the top connects to the next spool or tubing head assembly.
• The spool is designed so the bottom bowl or counter-bore will allow a secondary seal
to be set on the previous casing string, while the top bowl will hold a casing hanger
to suspend and allow a primary seal around the next string of casing. Multiple casing
spools may be used, one on top of the other, to hang intermediate casing strings and
the final production casing string.

27. W2 CASING SPOOL

28. CASING SPOOL FUNCTION
• Allow for a secondary seal on the previous casing string in the counter-bore.
• With a secondary seal in place, flange or hub seals and casing hanger seals are isolated
from internal casing pressure.
• Provide a port for pressure testing primary and secondary casing seals and flange
connections.
• Provide a platform to support, seal and pressure test the BOP during drilling and well
servicing operations.
• Provide a load shoulder and controlled bore in the top bowl to support the next casing
hanger and enable a primary seal for the next intermediate or production casing.
• Provide annular access for fluid returns or fluid injections and pressure monitoring,
through side outlets drilled in the spool assembly.

29. CASING HANGER
• Both casing heads and casing spool assemblies may require the use of casing
hangers.
• Casing hangers attach to the end of a given casing string and suspend and seal the
casing string in the top bowl of a casing head or spool.
• Casing hangers come in two main varieties:
– Slip type hangers that are installed around the casing after it is run, either
before or after the casing is cemented into place.
• Slip type casing hangers are used as a contingency when pipe is stuck, allowing
the casing to be cut off and set where it sits.
– Mandrel type hangers that are threaded onto the casing.
• Mandrel type casing hangers provide superior well control when landing the
hanger and improve the annular seal.

30. CASING HANGER
• Shallow intermediate strings are usually suspended from the hanger and then
cemented to surface.
• Longer intermediate and production strings that are not cemented to surface are
usually cemented while the casing is suspended in tension from the rig traveling block.
• After the cement has set for a few hours, the traveling block pulls a calculated tension
on the casing above the cement and it is at this point the hanger is set in the bowl.
• Casing hangers are often called slips or seals as they are designed with built-in seals.
• Sometimes, we install only a primary seal in shallow depth.
• Lock-down (also called hold-down) screws are used to hold the hanger in place.
• It may be one piece, two or three pieces ( in larger diameters)

31. Mandrel-types CSG hanger
Slip-types CSG hanger

32. CASING HANGER FUNCTION
• To suspend the load of the casing string from the casing head or spool.
• To center the casing in the head.
• To provide a primary seal against the inside of the casing head and isolate the casing
annulus pressure from upper wellhead components.

33. PACK-OFF FLANGE
• A pack-off flange is rarely used.
• It is set above a casing head or spool assembly and also sealed against
the intermediate or production casing to enable a safe increase in
pressure rating between the casing head or spool and any wellhead
equipment above the flange, for example, a tubing head.
• It is also known as a “restricted pack-off flange” or “crossover flange”.

35. PACK-OFF FLANGE FUNCTION
• It may be used during well re-entry where anticipated
pressure rise.
• In temporary operations such as
– Pressure testing primary seals
– As a safety device when drilling out the cement that remains in
the shoe joint.

36. PROBLEMS & SOLUTIONS
• The new pressure in the production casing is expected to jump from 10
MPa to 30 MPa on a well with a 13.8 MPa Casing Head and Tubing
Head.
– Solution: A packoff flange on the casing head that provides a transition
from 13.8 MPa to 20.7 MPa. The tubing head is upgraded to 34.5 MPa.
• The new pressure in the production casing is expected to jump from 10
MPa to 40 MPa on a well with a 13.8 MPa Casing Head and Tubing
Head.
– Solution: A packoff flange on the casing head that provides a transition
from 13.8 MPa to 20.7 MPa. Another packoff flange on top of the
previous that provides a transition from 20.7 MPa to 34.5 MPa. The
tubing head is upgraded to 69.0 MPa.

37. TUBING HEAD
• The tubing head assembly provides a means to suspend and seal the production
tubing in the wellhead.
• The tubing head is the top spool in the wellhead assembly and is installed after the last
casing string is set.
• The bottom of the tubing spool includes a counterbore that can be used to set a seal
against the production casing.
• The top of the tubing head provides a landing shoulder and a seal bore for landing
and enabling a seal to the tubing hanger.
• Above the tubing head is the tubing head adaptor which provides a transition to the
Christmas tree.

39. TUBING HEAD TYPES
• Top connection threaded; bottom connection threaded or welded
– should be limited to low pressure gas or oil wells.
– it does not offer lock screws for tubing hanger retention.
– A workover flange needs to be installed in order to install a BOP stack.

40. TUBING HEAD TYPES
• Top connection flanged; bottom connection threaded or welded.
– may be used for re-entry operations, new shallow gas or oil wells, and thermal operations
such as cyclic steam injection.
– It does not provide a secondary seal on the production casing.
– No ability to pressure test between the production casing and the previous casings string

41. TUBING HEAD TYPES
• Top and bottom connection flanged or clamp hub
– Can be used for any operation

42. TD TUBING HEAD (DUAL COMPLETION)

43. MTH2 MINI TUBING HEAD
• provides a low cost tubing support solution for fracking and
siphon string applications.
• Reduced equipment cost compared to conventional fracking
equipment
• Secondary casing seal fully rated to the working pressure of the
tubing head.
• Secondary casing seal can be monitored through the seal test port
• Eliminates the need for a secondary seal to protect the isolation
tool during multiple frack Operations.

45. TUBING HEAD FUNCTION
• Enable the suspension of the tubing.
• Allow for sealing the annulus between the tubing and the production casing.
• Allow access to the annulus between the tubing and production casing, through side
outlets.
• Provide a means to support and test the service rig BOP during well completions.
• Provide a bit guide for running the tubing without causing damage to the production
casing.
• Allow a secondary annulus seal to be set around the top of the production casing.
• Provide access for a test port to test primary and secondary seals.
• Ensure safe running and retrieving of tubing hangers in high pressure operations
(e.g., snubbing operations).
• Allow for correct orientation of equipment to enable running multiple tubing strings.

46. TUBING HANGER
• A tubing hanger is also commonly known as a dog nut.
• A tubing hanger typically is threaded onto the top of a tubing string and
is designed to sit and seal in the tubing head.
• Usually the tubing hanger is run through the BOP and landed in the top
bowl of the tubing head.
• The top of the tubing hanger provides a profile necessary for the lock
screws that will secure the hanger in the tubing head.

47. TUBING HANGER TYPES

48. TUBING HANGER TYPES
• Extended neck tubing hangers
– Allow for a primary and secondary seal on the tubing hanger. In this
configuration, a secondary seal packs off inside the tubing head adaptor. As a
result, the lock down screws are isolated from the well bore fluids and the
primary and secondary seals can be pressure tested.
• Extended neck tubing hangers are required for sour wells and possibly
corrosive wells.

50. T-M TUBING HANGERS/ADAPTERS
The T-M tubing hanger is a high capacity, mandrel tubing
hanger pressure rated to 15,000 psi.

51. TD-M DUAL TUBING
HANGERS/ADAPTERS
• The TD-M dual tubing hanger is a high capacity, dual
mandrel tubing hanger pressure rated to 15,000 psi.
• To accommodate down-hole control lines use a TD-M-CCL
tubing hanger and tubing head adapter.

52. T-2W WRAP-AROUND TUBING
HANGER
• Seals against H2S
• Provides a reciprocating
action

53. O2 COUPLING AND ADAPTER
• Increase suspension capacity.
• Extra seal against corrosive fluids.
• Reciprocating movement of tubing that helps in packer
setting.

54. O3 COUPLING AND ADAPTER
• A metal-to-metal neck seal for superior sealing.
• A coupling nut for simplified make up of the adapter and
tree.

55. TUBING HANGER BACK-PRESSURE
VALVE
• Tubing hangers may come with a back
pressure thread profile that enables the
operator to lubricate and isolation plug into
the tubing hanger.
• With an isolation plug in place, pressure
testing can now be carried out above the
tubing head.
• It also provides well control for installing and
removing the BOP or Christmas Tree, and for
temporary well suspensions.

56. TUBING HEAD ADAPTOR
• The tubing head adaptor provides a transition from the tubing head to the
Christmas tree.
• With a basic tubing head configuration where the tubing hanger is seated in
the top of the tubing head.
• The bottom of the tubing head adaptor will seal against the tubing head and
contain reservoir or injection fluids moving through the top of the tubing.
• With an extended neck tubing hanger, the adaptor will provide a secondary
seal against the hanger, isolating the seal between tubing head and adaptor
and any lock screws holding the tubing hanger in place. This configuration
provides a means to test the primary and secondary seals on the tubing
hanger.

57. TUBING HEAD ADAPTOR TYPES

58. WEAR BUSHING
• While drilling the well, it is required that the seal bores in each of the intermediate
casing spools and tubing spools be protected.
• A series of wear bushings are supplied to protect the seal areas discussed during the
drilling operation.
• The wear bushings are run on a drill pipe tool with J-lugs located on the OD that
interface with J-slots located in the top ID section of the wear bushing.

59. wear bushings for a typical land drilling wellhead system.
wear bushing running tools.
These tools are also used to test the BOP stack.

61. CHRISTMAS TREE
• A Christmas tree is an assembly of gate valves, chokes and fittings included with the
wellhead during well completion.
• Christmas tree provides a means to control the flow of fluids produced from or fluids
injected into the well, at surface.
• While Christmas trees come in a variety of configurations based on a number of well
design and operating considerations, typically the bottom connection of the tree
matches the top connection of the tubing head adaptor and these are generally
installed as a unit, immediately after production tubing is suspended.

62. Christmas tree for a flowing well

63. Christmas tree for Sucker Rod Pump

65. TYPICAL CHRISTMAS TREE
COMPONENTS
• A minimum of one master valve that will control all flows to and from each tubing
string.
• Under certain service conditions and well pressures, additional master valves.
– The upper valve is typically used in routine operations while the lower valve provides
backup and the ability to service the upper valve as the need arises.
• A tee or cross leading to control valves such as production gate valves, surface safety
valves, flow control valves or chokes
• Potentially a swab valve above the tee that permits vertical access to the wellbore.
• A tree cap that might be fitted with a pressure gauge. The tree cap provides quick
access to the tubing bore for bottom hole testing, installing down hole equipment,
swabbing, paraffin scraping, and other thru-tubing well work.

66. CONNECTIONS
• Connections provide a secure, leak free joint between wellhead components. There
are five basic connection types commonly used in wellhead design.
– Threaded
– Welded
– Flanged
– Studded
– Clamp hub
– Sliplock
– Connection that is unique to coiled tubing.

67. THREADED
• Casing head to surface casing connections
• Casing head to upper wellhead components
• Side outlets
• Tubing hangers
• Tubing heads
• Adaptors
• Valves
• Flow tees
• Pipe nipples
• Bull plugs
• Pressure and temperature gauges
• Needle valves
• Bottom hole test adapter or fluid sampling
port
• Polished Rod BOPs
• Polished Rod Stuffing boxes
• Plunger lift lubricator
• Back pressure valve
• Erosion (e.g. sand) or corrosion monitoring
probes
• Typically used only in lower pressures, sweet operations and for smaller diameter pipe or
fittings.

68. WELDED
SLIP-ON WELD
• Used to make a connection between
different diameters.
BUT WELD
• connecting two lengths of pipe of the
same unit weight (kg/m) and diameter.
• joining different lengths of wellhead
piping
• where a casing extension or repair is
required at surface.
• Seal + Connection

69. STUDDED
• one component that has studs threaded into its housing and a second component with
a flange bolted to the studs.
• Uses:
– Typically used in any high pressure (i.e., 2000 psi to 30,000 psi) or higher risk operations.
– Used in any operations where there are requirements to shorten the height or length of the
wellhead components.
– Used in any operations where there is a need to reduce the bending moment on equipment.
– Along with flanged connections, studded connections allow for the installation of a test port
to meet requirements of pressure testing between primary and secondary seals.

70. CLAM HUB
• the hubs of the two components being joined
are squeezed together over a seal ring or ring
gasket and held in-place by a clamp.
• The two clamp halves wrap around the hub
and are bolted to each other to a specified
torque to provide the required connection
strength and seal rating.

71. CLAM HUB USES
• Typically used in any high pressure or higher risk operations.
• Most commonly found in thermal operations.
• Provides a superior ability to align and seal wellhead components and piping
modules as compared to flanged or studded connections, as small differences in
alignment are more easily “absorbed” by this type of connection.
• Provides a higher fatigue resistance than flanged or studded connections.
• Offers a faster make up time versus flanged or studded connections.
• Since any damage to the face of the hub may compromise the metal to metal seal,
special care must be taken in any operation where there is potential for this type of
damage.

72. SLIPLOCK
• Typically used in drilling or other temporary
operations in place of welded or threaded
connections as the Sliplock provides a faster
connection time than either of these other
methods.
• May be used in observation style wells
where the well bore is not exposed to
formation conditions.

73. COIL TUBING CONNECTION TYPES

74. SEALS
• Seal composition:
– Elastomer and Graphite / Carbon Seals.
– Metal Seals.
• Seal types:
– Primary Seals
– Secondary Seals
• If both are installed the wellhead can be pressure
tested.

75. FLOWING WELLS
• When the reservoir pressure is capable to lift fluid to the surface.
• Flowing wellheads typically are simple.
• Depending on the type of produced fluids and well completion, production can be up
the production casing, production tubing, or the tubing-casing annulus.
– Sweet, low pressure, low risk wells (e.g., shallow gas) often do not have a tubing string
installed.

76. Above 13.8 MPa
SWEET FLOWING WELLS
P≤ 13.8 MPa

77. • Low Pressure / Low Risk Gas Wells

78. SOUR WELLS
• Death + Corrosion
• The following examples all present a corrosion hazard:
– CO2 and water
– Salt water
– Aggressive solvents (e.g., DMDS)
– Acid (well stimulation)

79. ARTIFICIAL LIFT WELLS
• Gas Lift
• ESP
• PCP
• Plunger Lift
• Sucker Rod Pump
• Hydraulic Pump
The conventional wellhead should be modified to meet the artificial lift method.
Each method along with the modification applied will be discussed.
Special Wellhead Design

80. BEAM PUMPING
• the wellhead must be modified to seal
around the reciprocating rod.
• Emergency precaution in case of broken rod.

81. WELLHEAD EQUIPMENT
• Flowing T
• BOP
• Stuffing Box
• Lubricator

82. FLOWING TEE
• Replaced the wing valve in conventional well head,
to direct the fluid towards surface facilities.

83. BOP
• Designed to prevent oil spills in case
of sucker rod or polished rod breaks
• May be installed
– Between tubing head and flowing T
– Between flowing T and stuffing box

84. • Can be operated manually or
automatically (hydraulically or
pneumatically)
A flapper valve may be used to
seal the wellbore in case of
complete drop of the rod.

85. STUFFING BOX
• Assembly to seal around the
polished rod to prevent leakage
to the surface

87. • Many stuffing boxes have two
sets of packing elements.
• The lower is relaxed in normal
conditions, but used in case of
the upper one fails
• The packing element is made
of rubber or Teflon to offer
low friction but provide the
required seal
• The sealing mechanism is the
bolted being tightened

88. LUBRICATION
• Normally the packing element is lubricated by
the fluid in the well.
• Intermittent pumping or high water cut may
lead to poor lubrication.
• Poorly lubricated (dry) packing element may
burn leading to fluid leakage to the surface.
• A lubrication oil reservoir may be mounted
above the stuffing box

89. PCP LIFTING
• the wellhead must be modified to seal
around the rotating rod.
• Emergency precaution in case of broken rod.
• The rod string is supported on the wellhead

90. The Wellhead must perform the following
functions:
•Suspend the rod string and carry the axial loads
•Deliver the torque required at the polished rod
•Safely rotate the polished rod at the required
speed
•Prevent produced fluid from escaping the system

91. WELLHEAD EQUIPMENT
• Wellhead frame containing
– Flowing T
– BOP
– Stuffing Box
– Prime mover
• Power transmission equipment

93. PRIME MOVER
Electric motor along with switch
board and transformer will be needed

94. PRIME MOVER
ICE will provide the
prime motion

95. GAS LIFTING
• The X-tree is used not only to
control the production but also
the injection of the gas

96. ESP LIFTING
• the wellhead must include a gas tight feed for the electric power cable that runs
from surface to the downhole ESP motor.

98. HYDRAULIC LIFTING
• the wellhead must provide:
– Inlet of the injected fluid
– Outlet for the formation fluid mixed with the
injection fluid
– The wellhead should also withstand the high P of
the injected fluid.

99. PLUNGER LIFTING
• the wellhead must accommodate a
lubricator / “plunger catcher” installed on
top of the flow cross.

100. • At surface the arriving plunger is captured in
a lubricator, the produced fluid unload to the
flowline.
• In normal operations, the force of the
incoming plunger is absorbed by the fluid
column and springs and stops in the
lubricator assembly.
• In some cases the plunger may be lifted
without fluid, the velocity will be faster, the
impact will be stronger.
• In extreme circumstances, a plunger arriving
at a high velocity without a fluid column may
be capable of blowing through the top of the
lubricator.

101. INJECTION WELLHEAD
– Similar in configuration to flowing wells.
– The major concerns in the wellhead are
• The operation pressure.
• The injected fluid
• Temperature (especially in STEAM INJECTION)

102. THE OPERATION PRESSURE.
• The wellhead pressure in case of injection wells is always greater than a normal flowing
well, so the wellhead must be chosen to withstand the anticipated pressure.

103. The injected fluid
• A wise selection of the wellhead material is a must to be suitable for the injected fluid and
TEMPERATURE variation.

104. OFFSHORE
WELLHEADS

105. OFFSHORE WELLHEAD
• Mudline suspension
• Subsea wellhead

106. MUDLINE SUSPENSION SYSTEM
• as jackup drilling vessels drilled in deeper water, the need to transfer the
weight of the well to the seabed and provide a disconnect-and-
reconnect capability became clearly beneficial. This series of hangers,
called mudline suspension equipment, provides landing rings and
shoulders to transfer the weight of each casing string to the conductor
and the sea bed.
• The mudline suspension system also allows the well to be temporarily
abandoned (disconnected) when total depth (TD) is achieved (when
drilling is finished at total depth)

107. THE MUDLINE HANGER SYSTEM CONSISTS
OF THE FOLLOWING COMPONENTS
• Butt-weld sub
• Shoulder hangers
• Split-ring hangers
• Mudline hanger running tools
• Temporary abandonment caps and running tool
• Tieback tools

108. MUDLINE HANGER SYSTEM
• Each mudline hanger landing shoulder and landing ring
centralizes the hanger body, and establishes concentricity around
the center line of the well. Concentricity is important when tying
the well back to the surface.
• In addition, each hanger body stacks down relative to the
previously installed hanger for washout efficiency.
• Washout efficiency is necessary to clean the annulus area of the
previously run mudline hanger and running tool. This ensures that
cement and debris cannot hinder disconnect and retrieval of each
casing riser to the rig floor upon abandonment of the well.

109. TEMPORARILY ABANDONING THE WELL
• After each casing string is disconnected from the mudline suspension hanger and
retrieved to the rig floor in the reverse order of the drilling process, threaded
temporary abandonment caps or stab-in temporary abandonment caps (both of which
makeup into the threaded running profile of the mudline hanger) are installed in
selected mudline hangers before the drilling vessel finishes and leaves the location.
The temporary abandonment caps can be retrieved with the same tool that installed
them.

111. RECONNECTING TO THE WELL
• A mudline suspension system also incorporates tieback tools
to reconnect the mudline hanger to the surface for re-entry
and/or completion.
• A surface wellhead system is installed, and the well is
completed similarly to the method used on land drilling
operations.

112. • The mudline suspension system has been designed to
accommodate tying the well back to the surface for surface
completion, and it also can be adapted for a subsea
production tree. A tieback tubing head can be installed to the
mudline suspension system at the seabed, and a subsea tree
can be installed on this tubing head.

113. Drilling is done by jack
up rig
Sea surface
Sea bed
When the desired
depth is reached ,
mudline system is
installed
The drilling rig is removed
,so the abandonment cap
is installed and the well is
disconnected .
The well is reconnected
using tieback tool for
deeper drilling or
completion

114. DIFFERENCE BETWEEN THE LAND
WELLHEADS AND A THE JACKUP MUDLINE
• The main difference between the wellheads used in the land drilling
application and the jackup drilling application (with mudline) is the slip-
and-seal assembly
• Because the weight of the well now sits at the seabed, a weight-set slip-
and-seal assembly is not used. Instead, a mechanical set (energizing the
seal by hand) is used, in which cap screws are made up with a wrench
against an upper compression plate on the slip-and-seal assembly to
energize the elastomeric seal.

115. A MECHANICAL-SET SLIP-AND-SEAL
ASSEMBLY

116. SUBSEA WELLHEAD SYSTEMS
• is a pressure-containing vessel that provides a means to hang off
and seal off casing used in drilling the well.
• The wellhead also provides a profile to latch the subsea blowout
preventer (BOP) stack and drilling riser back to the floating drilling
rig. In this way, access to the wellbore is secure in a pressure-
controlled environment.
• The subsea wellhead system is located on the ocean floor, and
must be installed remotely with running tools and drillpipe

117. A STANDARD SUBSEA WELLHEAD SYSTEM WILL
TYPICALLY CONSIST OF THE FOLLOWING:
• Drilling guide base.
• Low-pressure housing.
• High-pressure wellhead housing (typically 18¾ in.).
• Casing hangers
• Metal-to-metal annulus sealing assembly.
• Bore protectors and wear bushings.

118. DRILLING GUIDE BASE
• provides a means for guiding and aligning the
BOP onto the wellhead. Guide wires from the
rig are attached to the guideposts of the base,
and the wires are run subsea with the base to
provide guidance from the rig down to the
wellhead system.

119. LOW-PRESSURE HOUSING
• provides a location point for the drilling guide base,
and provides an interface for the 18¾-in. high-
pressure housing. It is important for this first string
to be jetted or cemented in place correctly, because
this string is the foundation for the rest of the well.

120. HIGH-PRESSURE HOUSING
• a unitized wellhead with no annulus access.
• It provides an interface between the subsea BOP
stack and the subsea well.
• The subsea wellhead is the male member to a
large-bore connection, (the female counterpart is
the wellhead connector on the bottom of the BOP
stack)

121. CASING HANGERS
• The casing hanger provides a metal-to-metal sealing
area for a seal assembly to seal off the annulus
between the casing hanger and the wellhead.
• The casing weight is transferred into the wellhead by
means of the casing hanger/wellhead landing
shoulder.
• Each casing hanger stacks on top of another, and all
casing loads are transferred through each hanger to
the landing shoulder at the bottom of the subsea
wellhead.
• Each casing hanger incorporates flow-by slots to
facilitate the passage of fluid while running through
the drilling riser and BOP stack, and during
the cementing operation.

122. METAL-TO METAL ANNULUS SEAL
ASSEMBLY
• isolates the annulus between the casing hanger and
the high-pressure wellhead housing.
• The seal incorporates a metal-to-metal sealing system
that today is typically weight-set (torque-set seal
assemblies were available in earlier subsea wellhead
systems).
• During the installation process, the seal is locked to
the casing hanger to keep it in place.
• If the well is placed into production, then an option to
lock down the seal to the high-pressure wellhead is
available. This is to prevent the casing hanger and
seal assembly from being lifted because of thermal
expansion of the casing down hole.

123. BORE PROTECTORS AND WEAR
BUSHINGS
• Once the high-pressure wellhead housing and the
BOP stack are installed, all drilling operations will
take place through the wellhead housing.
• The risk of mechanical damage during drilling
operations is relatively high, and the critical landing
and sealing areas in the wellhead system need to
be protected with a removable bore protector and
wear bushings

124. BIG BORE SUBSEA WELLHEAD SYSTEMS
• as a result of the challenges associated with deepwater drilling.
• Ocean-floor conditions in deep and ultradeep water can be extremely
mushy and unconsolidated, which creates well-foundation problems that
require development of new well designs to overcome the conditions.
• Second, underground aquifers in deep water have been observed in far
greater frequency than in shallower waters, and it quickly became clear that
these zones would have to be isolated with a casing string.
• wellhead equipment designs would also have to change to accommodate
the additional requirements.

125. WITH SUBSEA WELLHEAD SYSTEMS
• conductor and intermediate casing strings can be reconfigured to strengthen and
stiffen the upper section of the well (for higher bending capacities), and overcome the
challenges of an unconsolidated ocean floor at the well site.
• Each “water flow” zone encountered while drilling requires isolation with casing and,
at the same time, consumes a casing-hanger position in the wellhead.
• It became obvious that more casing strings and hangers were required to reach the
targeted depth than the existing wellhead-system designs would accommodate.

126. UNITIZED WELLHEAD (C0MPACT)
• The unitized wellhead is a one-piece body that is typically run on 13 3/8 -in. casing
through the BOP, and lands on a landing shoulder located inside the starting head or
on top of the conductor itself.
• The casing hangers used are threaded and preassembled with a pup joint.
• This way, the threaded connection can be pressure tested before leaving the factory,
ensuring that the assembly will have pressure-containing competence.
• Gate valves are installed on the external outlet connections of the unitized wellhead to
enable annulus access to each of the intermediate and the production casing strings.

127. UNITIZED WELLHEAD (C0MPACT)
• After the next hole section is drilled, the casing string, topped out with its mandrel
hanger, is run and landed on a shoulder located in the ID of the unitized wellhead.
• A seal assembly is run on a drillpipe tool to complete the casing-hanger and seal-
installation process.
• Each additional intermediate casing string and mandrel hanger is run and landed on
top of the previously installed casing hanger without removing the BOP stack.
• Besides saving valuable rig time, the other advantage of the unitized wellhead system
over spool wellhead systems is complete BOP control throughout the entire drilling
process.

130. TIME-SAVING WELLHEAD
• These types of wellhead is used when rig daily rate is high and
there is a massive need to decrease the rig cost by decreasing
the time necessary to install the wellhead
• Decreasing the time of testing the BOP.

131. SH2 SPLIT SPEEDHEAD SYSTEM
Pack-off
• No need to un-screw the BOP.
• Reduces waste time in testing BOP.
• Maximum pressure 15,000psi.

132. SH3 SPEEDHEAD SYSTEM
• Improved safety
– Eliminates one flange
– Eliminates all lock down screws
• Time savings
– Reduced BOP/diverter handling
– Replaces lock down screws with lock rings
• Flexible system
– Emergency equipment
– Alternate casing programs
– Adapts to conventional equipment for extended
casing programs.
• Maximum pressure 15,000psi.

133. LSH LAND SPEEDHEAD SYSTEM
• The LSH System is designed for use as a 2-stage
starting head, combining the casing head and
casing spool into a single housing.
• The BOP stack is made up to the starting head
before drilling commences and is not removed
until two strings of casing have been run.
• Maximum pressure 5,000psi

134. MULTI-WELL COMPLETION
MWC SYSTEM
• Completion of different wells from the same
conductor pipe.
• We can use SH-2, SH-3, LSH in this type
completion.
• It is more common in offshore application.

135. OSH (OFFSHORE SPEED WELLHEAD(
• It has a 2-stage starting head,
combining the casing head and
casing spool into a single housing.
• The diverter or BOP stack is made
up to the starting head before
drilling commences and is not
removed until two strings of casing
have been run.

136. • This technique impacts both rig costs and safety. By landing two casing strings in one
compact forged housing, the OSH system eliminates one complete BOP nipple-
down/nipple-up thereby saving significant rig time. By reducing handling of wellhead and
BOP equipment and minimizing potential wellhead leakpaths,
• the OSH system substantially improves safety. When combined with the SH2 Split Speed
Wellhead System, this package can save from 24 to 40 hours of valuable rig time.

137. FEATURES
1- Improved safety ,
• Field proven,
– Weld-less attachment option to drive pipe
– Run annular seals through BOP
.
– External seal testing/monitoring capability
2- Time saving
– Reduces BOP/diverter handling
– Eliminates wait-on-cement time
– Uses simple emergency procedure
– Installs tubing spool with casing spool

138. 3- Flexible system
– Allows alternate casing programs
– Has pressure ratings up to 15,000 psi
– Accepts standard tubing hangers with continuous control lines
– Accepts standard casing hangers in the upper bowl and will connect to a conventional
tubing head spool for extended casing program
– Accepts conventional casing spool/tubingSpool