Industrial Equipments by Jyoti Process Equipments Pvt. Ltd., Navi Mumbai
Completion Equipments
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Transcript of Completion Equipments
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WELL COMPLETION EQUIPMENTS
Thanks to: Prof. Bahman Tohidi(Heriot-Watt University) Well design and completionwww.utp.edu.my
By: Dr. Syahrir Ridha
Having worked through this chapter the Student will be able to:
Discuss and review the main equipment options: Production tubing Wellheads Xmas trees Packers Subsurface safety valves Nipple profiles Tubing-annulus circulation devices
Lesson Outcomes
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1. Production Tubing2. Wellhead Systems3. X-mas Tree4. Packers5. Nipple and Mandrel Systems6. Sub-Surface Safety Systems7. Tubing-Annulus Communication Equipment
Completion Equipments
1. Production Tubing
Design of production tubing should satisfy the following criteria:
Minimising pressure dropHigh strength for suspension of tubing jointsHigh internal pressures for fluids flowHigh external pressures (between annulus &
tubing)Resistant to chemical corrosion
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Production Tubing
Tubing Diameter‐ OD + lbs/ft (4” OD, 9.5 lbs/ft)
Tensile Strength‐ H-40, C-75, L-80, et al‐ Number is an indication of minimum
yield strength multiply 1000 in psi.‐ Letter grades indicate the
manufacturing process Internal Pressure
‐ Internal vs differential pressure‐ Burst pressure is calculated for gas
filled tubing‐ Maximum generally occurs at surface
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Production Tubing
External Pressure‐ Collapse is most likely at the bottom of the well
Corrosion‐ Acid corrosion; i.e. CO2‐ Sulphide stress cracking/hydrogen embitterment;
i.e. H2S‐ Some treatment use of inhibitor
Coupling Types‐ Connections that require internal pressure‐ Metal to metal
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2. Wellhead Systems
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Wellhead Systems
It has the following functions: Suspension of casings and tubings Flanging up fluid flow devicesX-mas tree and/or BOPs
Hydraulix communication with annulus
Application in an offshore platforms or land based, wellhead can be devided into: Conventional Spool System Compact Spool Systems Mud Line Suspension System
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a. Run the 30” conductor, 20” casing is run and cemented. Sometimes the top of 20” casing is welded, so it can transfer some weigh to the 30” conductor.
b. The 17 ½” hole is drilled,13 3/8” casing is run with the hanger landing in the 20” housing. The casing is cemented in place.
c. A new 12 ¼” hole is drilled…with a new spool being installed for each casing string.
Conventional Spool System
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The disadvantages of this type of wellhead are:
A lot of time is spent flanging up the spools; The large number of seals, increases the
chance of pressure leak; BOPs must be removed to install the next
casing spool; A lot of headroom is require, which may not
be available in the wellhead area of an offshore platform.
Conventional Spool System
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Compact Spool System
This compact type was developed as an alternative to the conventional spool discussed above.
A compact spool enables several casing strings or tubing to be suspended from a single spool.
The BOPs can be connected to the top of housing and the next hole section drilled.
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Compact Spool System
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Mud Line Suspension System
Wellhead is built up on the seabed, but production well be completed back to the platform.
A wellhead built up on the seabed will be used to suspend casing strings
Each casing will have an extension string from subsea wellhead to a subsidiary wellhead at the platform where the BOP and X-mas tree will be attached.
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3. X-mas Tree
It is a system of valves which controls physical or hydraulic access into the tubing string or the annulus.
The access capabilities required are: Capability to inject fluids Capability to produce fluids Capability to lower wireline service tool Capability to completely close the well
‐ Manually controlled valve and remotely controlled valve (hydraulically)
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X-mas Tree
One major disadvantage of cross piece Xmas Tree is the large number of flanges significantly increased possibility of leakage.
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X-mas Tree
A solid block construction uses of a yoke piece configuration
Normally the Xmas Three is connected by a flange or clamp to the top of the wellhead.
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4. Packers
It provides physical isolation of the casing/tubing annulus above the production zone.
Provide well protection Corrosion protection Abrasion protection Casing/wellhead burst protection
Production stability Production annulus heading
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Packers
Zonal Isolation Selective or segregate production
Annulus to Tubing InjectionGas lift or chemical
Injection OperationsEconomic injection rate or fracturing
Temporary IsolationBridge plug
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Packers
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Packers have four key features:1. Slip2. Cone3. Packing-element system4. Body or mandrel.
The slip device penetrate and grip the casing wall when the packer is set.
The cone drives the slip outward and into the casing wall when setting force is applied to the packer.
Once the slips have anchored into the casing wall, additional applied setting force energizes the packing-element system and creates a seal between the packer body and the inside diameter of the casing.
Packer Classifications
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Permanent Packer Permanent packers difficult to remove and it can be removed
from the wellbore only by milling. Retrieval is usually accomplished by some form of tubing
manipulation The permanent packer is fairly simple and generally offers higher
performance in both temperature and pressure.
Retrievable Packer The retrievable packer may or may not be resettable, but
removal from the wellbore normally does not require milling. The retrievable packer can be very basic for low pressure/low
temperature (LP/LT) applications or very complex in high pressure/high temperature (HP/HT) applications.
This packer will invariably cost more with the same quality of permanent packer
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Packers Selection
Casing and tubing size Depth of the well and bottom-hole pressure Annular fluid type and differential pressure Extent of thermal stress and potential forces Need for tubing retrieval without the packer Bore size offered by the packer Completion string equipment compatibility The deviation angle, effect on setting mechanism
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5. Nipple and Mandrel Systems Applications
Isolation and plugging of the tubing string for well shut in, workover, or hydraulically setting packers.
A ported device for communication between the tubing and the annulus.
Emergency closure of the tubing or annular flow
Installation of downhole pressure and temperature recording gauges.
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6. Sub Surface Safety System
They are required forX-mas tree removal for workoverRemoval of surface valvesDamage to X-mas tree Leakage on X-mas tree
SSSV are available besed onDirect control (D.C. SSSV)Remotely of Surface contro (S.C. SSSV)
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Directly Controlled (D.C. SSSV)
Differential pressure operated safely valves Ambient or pre-charged type safety valves Advantages
Simple construction and operating principle Easy installation and retrieval Cheaper installation cost
Disadvantages Not 100% reliable Performance could be affected due to solid
deposition Testing of valve operation is not easy
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Surface Controlled (S.C. SSSV)
Held open by hydraulic pressure Either ball or flapper type Tubing or wireline retrievableTubing retrievable must be
reliableTubing retrievable offer larger
flow area
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7. Tubing-Annulus Communication Equipment
The communication (circulation) is required for: To displace out the tubing contents to initiate
production To displace tubing contents with a kill fluid To allow continuous or intermittent injection:
Corrosion or scale inhibitor Gas for gas lift
Available options are: Sliding side door or sliding sleeve Side pocket mandrel
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Sliding side door
A completion device that can be operated to provide a flow path between the production conduit and the annulus. Sliding sleeves incorporate a system of ports that can be opened or closed by a sliding component.
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Is it this?
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Side Pocket Mandrel
A completion component that is used to house gas-lift valves and similar devices that require communication with the annulus.
The design of a side-pocket mandrel is such that: the installed components do not
obstruct the production flow path enabling access to the wellbore and
completion components below. Consists of a tubing mandrels with ports
located on its outside wall
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Running Procedures
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THANK YOU