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Casing Design
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Casing Design
By
Dr. Khaled El-shreef
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Casing Design CONTENTS
Function of Casing
Casing Types & Tools
Strength Properties
Casing Specification
Casing Design
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RUNNING AND
CEMENTING CASING
Reasons for Running Casing Provide a means of controlling well
pressures.
Permit circulation.
Prevent collapse of hole.
Prevent fluid migration.
Isolate troublesome zones.
Facilitate control of a production well.
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Types of Casing and Common
Size
Conductor 20: 24
Surface Casing 13 3/8
Intermediate String 9 5/8
Production String 9 5/8: 7
Liner 7: 5"
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Conductor Casing
Characteristics:
Casing is usually large: 20 in. to 30 in. diameter.
The hole may be severely eroded.
The setting depth of the conductor can vary from as little as 20 ft to as much as a few hundred feet.
The most common pipe and hole sizes are a 16 in. pipe in a 20 in. hole and 20 in. pipe in a 26 in. hole.
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Conductor Casing
Conductor Casing is set to :
Prevent washing out under rig. Provide elevation for flow line. Provide support for part of the wellhead.
A BOP is usually not attached to conductor casings.
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Surface casing Surface casing is usually the second string of pipe
set in the well.
when a conductor casing is not set because, the surface pipe becomes the first string set.
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Surface casing Surface casing is set to:
Protect fresh water sands.
Case unconsolidated formations.
Provide primary pressure control (BOP usually nippled up on surface casing).
Support future casings.
Case off potential loss circulations zones.
Casing sizes normally range from 13-3/8in. on shallow wells to 20 in. on deep, multistring wells.
Guide shoe, or float shoe, float collar and centralizers are commonly used
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Intermediate Casing The intermediate casing strings extend from the
surface to formations able to hold the expected mud
weights at greater depths.
This depth can vary several thousand feet in a single stage job.
When a second intermediate string is set, the casing is run to just below the weak zone to a firm
formation and cemented at that point.
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Intermediate Casing
Intermediate casing is set to: Separates hole into workable drilling segments and
cases off loss circulation zones, water flows, etc.
isolates salt sections. protects open hole from increases in mud weight. prevents flow from high pressure zones if
mud weight must be reduced.
Basic pressure control casing. BOP always installed. Supports subsequent casings.
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Production Casing The production casing is the last full string of pipe
set in the well.
It extends from below the deepest producing formation to the surface-
Production tubing, downhole pumps, and other equipment needed to produce oil and gas are housed in this casing.
The production-casing cement must give a pressure-tight seal between the formations and the production casing.
It is essential to isolate the reservoir from fluids both within the producing zone itself and from other zones.
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Production Casing Since the production casing may extend from the
total depth of the well to the surface, the setting
depth can vary from a few thousand feet to as much
as 14000 feet.
Below 14000 ft, liners may be set because of cost savings and less pipe weight.
The size of the casing depends upon the number of strings of production tubing to be run into the well
and the size of production equipment used.
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Production Casing Characteristics Common size 4-1/2 in., 5-1/2 in., and 7 in.
casing.
Drilling mud usually of good condition.
Usually not circulated. Generally cemented back to intermediate casing.
Good cement job is vital to successful completion.
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Production Casing Production casing is set to:
Complete well for production.
Effect zonal isolation.
Protect pay zones from unwanted fluids.
Provide pressure control.
Cover worn or damaged intermediate casing.
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Liners String A liner is a string of casing that does not reach the
surface.
They are hung on the intermediate casing by use of suitable arrangement of a packer and slips called a
liner hanger.
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Types of Liners String
Drilling liners, used to isolate lost circulation or abnormally pressured zones to permit
deeper drilling.
Production liners, run instead of a full casing to provide isolation across the production or
injection zones.
Tie back liner, a section of casing extending upwards from the top of an existing liner to
the surface.
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Types of Liners String
The scab liner, a section of casing that does not reach surface. It is used to repair existing
damaged casing. It is normally sealed with
packers at top and bottom and in some cases
is also cemented.
The scab tie back liner, a section of casing extending from the top of an existing liner but
does not reach the surface and is usually
cemented in place.
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Liner String The liner string consists of:
The cementing head with a drill pipe wiper dart in place.
A drill pipe swivel if movement is considered.
Drill pipe.
Liner-setting mechanism.
Latch-in liner wiper plug.
A mechanical set or hydraulic set liner hanger.
Floating equipment.
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Liner hangers are set mechanically or hydraulically.
The float shoe and float collars are spaced two to five joints apart.
The liner plug landing collar is located some distance above the float collar.
Most liner hangers are equipped with a tie-back receptacle should the need arise to run a tie-back string to surface or to run a scab liner.
The tie-back sleeve is usually a minimum of six feet in length and fluted for easier entry.
Production liners are many times equipped with a polished bore receptacle to serve as a seal assembly placement facility when production string is run in the well.
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Hole Conditions
Sloughing In many cases, this is the purpose of setting an
intermediate casing and it can create several
cement problems, such as bridging the annulus,
sticking the casing, and increasing the annulus
hydrostatic pressure.
Drill Pipe Drag
Where the drag is occurring, and exactly why it
exists, could be important. This condition may
indicate the need for centralized casing or the use
of fluid loss control cements.
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Hole Conditions
Low Pressure Zone: One of the most persistent problems is
incompetent formations that will not support
effective columns of cements.
Mud Condition:
A well-conditioned mud greatly increases the
mud removal capability of the flushes and
cement slurry.
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Hole Conditions
Fluid Movement Zone isolation fails any time fluid movement is
allowed to move during the time a cement slurry is between the fluid and set state. If the cement moves during the hardening, the cement will not set.
Formation Movement
Are you located in an active fault zone? The most common formation movement occurs with salt intrusions.
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Physical Properties Length Ranges
a. Casing comes in three range lengths:
R I 10 to 25 feet
R II 25 to 34 feet
R III > 34 feet
b. There are different 'grades' of casing which indicate the strength of the sheet.
These are color coded:
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These are color coded:
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Casing Grades
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Couplings API couplings STC- Short round thread casing
LTC- Long round thread casing
BTC- Buttress thread casing
XL- Extreme line casing
Non-API couplings Hydril super EU, TS
Valorec
Vam
See Halliburton Book ..
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Basic Design Features of Coupling
Form: V-shaped or squared shaped
Taper: change in thread diameter in inch per foot of thread length
Height: distance between crest and root
Lead: distance between one point on the thread and the corresponding point on the other one.
Pitch diameter: diameter on an imaginary cone that bisects each thread midway between its crest and root
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Basic Element of Threads
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API Coupling Configurations
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Strength Properties
Yield strength
Collapse strength
Burst strength
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Yield strength (Tensile Loading )
Tensile loading is applied to casing as a result of its own weight and is at a maximum underneath the casing hanger at the surface.
Buoyancy reduces the tensile loading on casing.
Tensile loading on the casing is increased as a result of running it in directional hole.
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Yield strength (Tensile Loading)
A critical factor is the outside diameter of the casing which, if reduced, reduces the tensile
loading on the casing.
It is for this reason that smaller sizes of casing are selected to be run on the build up sections
of directional hole, particularly if rapid
changes of angle are expected.
API defines it as the tensile stress required to produce a total elongation of 0.5 % of the
gauge length
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Yield strength (Tensile Loading )
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Collapse Loading The maximum external pressure required to
collapse a specimen of casing.
If the casing is emptied of fluid completely the worst collapse situation exists. With no
internal hydrostatic pressure of the mud, the
full formation pressure is exerted on the casing
at the shoe.
At the surface the collapse pressure is clearly zero since only atmospheric pressure is acting
on the casing.
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Collapse Loading
Where exceptional circumstances occur such as casing run in salt formations or in earthquake areas, extra collapse resistance is required and must be designed for.
Types
Elastic collapse
Plastic collapse
Transition collapse
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Burst Loading (or Internal Yield
strength) The maximum value of internal pressure required
to cause the steel of casing to yield.
Burst loading is the net internal pressure load exerted on the casing.
The worst case of burst loading usually occurs when a gas kick is taken and the well is shut in.
The net burst load is the difference between the pressure inside the casing and the pressure outside.
The point of maximum burst loading in this case is therefore at the top of the casing string where there is a high gas pressure.
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Biaxial Loading Collapse and burst loading on casing are both
affected by tensile loading.
Tensile loading tends to reduce the collapse resistance of casing. This is a particular problem in deep wells with long casing strings.
Tensile loading has the reverse effect on burst resistance.
Burst resistance is increased due to the tensile loading.
Temperature effects must also be considered as the elongation of the casing can effect all loadings.
The Drilling Engineer will make use of standard tables and equations to allow for the effect of tension and temperature.
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Casing Design
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Casing Design Casing design is required to ensure that casing run in the well will withstand the various loads applied to it.
The principle loadings casing is subjected to are:
Burst Collapse Tensile
The worst case loading is considered in each case.
Safety Factors
Burst pressure 1- 1.1 Collapse pressure 0.85 - 1.125 Tensile force 1.6 - 1.8
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Graphical Method for Casing Design
Collapse Line
Pc = Pout - Pin,
P = 0.052* (ppg)*D (ft) psi
Calculate P surface, P shoe (empty casing).
Draw collapse line
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Graphical Method for Casing Design
Burst Line
Burst pressure = Internal pressure
External pressure
Internal pressure = Pf (TD CSD)*G
External pressure = CSD* Gm
Where
Pf, formation pressure at total depth
TD, total depth, CSD, casing setting depth
G, formation fluid gradient (0.1 psi/ft)
Gm, mud gradient (0.465 psi/ft)
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Graphical Method for Casing Design
Tensile force
Tensile force = weight of casing in air Buoyancy force
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Graphical Method for Casing Design
Assume full reservoir pressure all along the wellbore.
Hydrostatic pressure increases with depth
Tensile stress due to weight of string is highest at top
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Worst Possible Conditions
1. For Collapse design, assume that the casing is empty on the inside (p = 0 psig), and assume no buoyancy effect
2. For Burst design, assume no backup fluid on the outside of the casing (p = 0 psig)
3. For Tension design, assume no buoyancy effect
The casing string must be designed to stand up to the
expected conditions in burst, collapse and tension.
Above conditions are quite conservative. They are
also simplified for easier understanding of the basic
concepts.
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Running Casing Condition hole.
Casing shoe and first two or three joints.
Check float equipment.
Remove wear bushing.
While running casing, check calculated displacement to trip tank.
Keep pipe moving to avoid sticking and circulate.
Rig up cement head and plugs.
Pump water or chemical spacer to remove mud cake.
Drop bottom plug.
Load top plug (if not already in cement head).
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Refer to Examples in the text
The End