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Casing design in oil and gas industry
Citation preview
JAMES A. CRAIG
Table of Contents
Functions of Casing Types of Casing Strings Classification of Casing Mechanical Properties of Casing Casing Design Criteria Corrosion Design Considerations
Functions of Casing Isolate porous formations with different
fluid-pressure regimes and also allow isolated communication with selectively perforated formation(s) of interest.
Isolate troublesome zones (high-pressured zones, weak and fractured formations, unconsolidated formations, and sloughing shales) and to allow drilling to the total depth.
Prevent the hole from caving in
Serve as a high-strength flow conduit to surface for both drilling and production fluids.
Prevent near-surface fresh water zones from contamination with drilling mud.
Provide a connection and support of the wellhead equipment and blowout preventers.
Provide exact dimensions for running testing, completion, and production subsurface equipment.
Types of Casing Strings There are different types of casing for different
functions and drilling conditions. They are run to different depths and one or
two of them may be omitted depending on the drilling conditions. They are: Cassion pipe Conductor pipe Surface casing Intermediate casing Production casing Liners
Cassion pipe (26 to 42 in. OD)
For offshore drilling only. Driven into the sea bed. It is tied back to the conductor or surface
casing and usually does not carry any load. Prevents washouts of near-surface unconsolidated
formations. Ensures the stability of the ground surface upon
which the rig is seated. Serves as a flow conduit for the drilling mud to the
surface
Conductor pipe (7 to 20 in. OD) The outermost casing string. It is 40 to 500 ft in length for onshore and up
to 1,000 ft for offshore. Generally, for shallow wells OD is 16 in. and
20 in. for deep wells. Isolates very weak formations. Prevents erosion of ground below rig. Provides a mud return path. Supports the weight of subsequent casing
strings.
Surface casing (17-1/2 to 20 in. OD)
The setting depths vary from 300 to 5,000 ft 10-3/4 in. and 13-3/8 in. being the most
common sizes. Setting depth is often determined by
government or company policy and not selected due to technical reasoning. Provides a means of nippling up BOP. Provides a casing seat strong enough to safely
close in a well after a kick. Provides protection of fresh water sands. Provides wellbore stabilization.
Intermediate casing (17-1/2 to 9-5/8 in. OD) Also called a protective casing, it is purely a
technical casing. The length varies from 7,000 to 15,000 ft.
Provides isolation of potentially troublesome zones (abnormal pressure formations, unstable shales, lost circulation zones and salt sections).
Provides integrity to withstand the high mud weights necessary to reach TD or next casing seat
Production casing (9-5/8 to 5 in. OD)
It is set through the protective productive zone(s).
It is designed to hold the maximal shut-in pressure of the producing formations.
It is designed to withstand stimulating pressures during completion and workover operations.
A 7-in. OD production casing is often used
Provides zonal isolation (prevents migration of water to producing zones, isolates different production zones).
Confines production to wellbore. Provides the environment to install subsurface
completion equipment. Provides protection for the environment in the
event of tubing failure during production operations and allows for the tubing to be repaired and replaced.
Liners They are casings that do not reach the surface. They are mounted on liner hangers to the
previous casing string. Usually, they are set to seal off troublesome
sections of the well or through the producing zones for economic reasons (i.e. to save costs). Drilling liner Production liner Tie-back liner Scab liner Scab tie-back liner
Drilling Liner – Same as intermediate/protective casing. It overlaps the existing casing by 200 to 400 ft. It is used to isolate troublesome zones and to permit drilling below these zones without having well problems.
Production Liner – Same as production casing. It is run to provide isolation across the production or injection zones.
Tie-back Liner – it is connected to the top of the liner with a specially designed connector and extends to the surface, i.e. converts liner to full string of casing.
Scab Liner – A section of casing used to repair existing damaged casing. It may be cemented or sealed with packers at the top and bottom.
Scab Tie-back Liner – A section of casing extending upwards from the existing liner, but which does not reach the surface and normally cemented in place. They are commonly used with cemented heavy-wall casing to isolate salt sectons in deeper portions of the well.
Classification of Casing There are two types of casing standardization:
the API non-API
Some particular engineering problems are overcome by specialist solutions which are not addressed by API specifications: drilling extremely deep wells using ‘premium’ connections in high pressure high
GOR conditions. Nevertheless, we will stick to the API methods
Classifications to be considered are:
Outside diameter (OD). Inside diameter (ID), wall thickness, drift
diameter. Length (range) Connections Weight Grade
Outside diameter (OD)
Casing manufacturers generally try to prevent the pipe from being undersized to ensure adequate thread run-out when machining a connection.
Most casing pipes are found to be within ±0.75% of the tolerance and are slightly oversized.
Inside Diameter (ID), Wall Thickness, Drift Diameter The ID is specified in terms of wall thickness
and drift diameter. The maximal ID is controlled by the
combined tolerances for the OD and the wall thickness.
The minimal permissible pipe wall thickness is 87.5% of the nominal wall thickness, which in turn has a tolerance of -12.5%.
The minimal ID is controlled by the specified drift diameter.
The drift diamater refers to the diameter of a cylindrical drift mandrel that can pass freely through the casing with a reasonable exerted force equivalent to the weight of the mandrel being used for the test.
A bit of a size smaller than the drift diameter will pass through the pipe.
Casing & Liner OD (in.) Length (in.) Drift Diameter (in.)
≤ 8-5/8 6 ID – 1/8
9-5/8 – 13-3/8 12 ID – 5/32
≥ 16 12 ID – 3/16
API recommended dimensions for drift mandrels
Length (range)
The lengths of pipe sections are specified in three major ranges: R1, R2 and R3.
Range Length (ft) Average Length (ft)
1 16 – 25 22
2 25 – 34 31
3 > 34 42
Connections
API provides specifications for four types of casing connectors: CSG – Short round threads and couplings – offer
no pressure seal at internal pressure, threaded surfaces get further separated.
LCSG – Long round threads and couplings –same basic thread design as CSG but offers greater strength and also greater joint efficiency (though less than 100%). Often used because it is reliable, easy and cheap.
BCSG – Buttress threads and couplings – offers a nearly 100% joint efficiency. Not 100% leakproof.
XCSG – Extreme line threads – design is an integral joint, i.e. the coupling has both box and pin ends. Much more expensive.
CSG and LCSG are also called API 8-Round threads because they have eight threads per inch
API Round Thread
Connector
API Buttress Thread
Connector
API Extreme-Line
Connector
Weight
Pipe weight is usually expressed as weight per unit length in lb/ft. The three types are: Nominal Weight Plain-end Weight Threaded and Coupled Weight or Average Weight
Nominal weight Based on theoretical weight per foot for a 20-ft
length of threaded and coupled casing joint.
○ OD = outside diameter (in.)○ t = wall thickness (in.)
The nominal weight is not the exact weight of the pipe, but rather it is used for the purpose identification of casing types.
( )( ) ( )210.68 0.0722nW OD t t OD= − + ×
Plain-end weight The weight of the joint of casing without the
threads and couplings.
Threaded and Coupled Weight or Average Weight The weight of a casing joint with threads on both
ends and coupling at one end when in the power tight position.
The variation between nominal weight and average weight is generally small, and most design calculations are performed with the nominal weight.
( )10.68peW OD t= −
○ Lc = length of coupling (in.)○ J = distance between the end of the pipe and center
of the coupling (in.)
21 2020 24Weight of coupling
20Weight removed in threading two pipe ends
20
ctc pe
L JW W + = −
+
−
Grade
The steel grade of the casing relates to the tensile strength of the steel from which the casing is made.
The steel grade is expressed as a code number which consists of a letter and a number. The letter is arbitrary selected to provide a unique
designation for each grade of casing. The number deisgnates the minimal yield strength
of the steel in thousands of psi. For example, K-55 has a yield strength of 55,000 psi
Mechanical Properties of Casing
Casing is subjected to different loads during landing, cementing, drilling, and production operations.
The most important loads which it must withstand are tensile, burst and collapse loads.
Other important loads include wear, corrosion, vibration and pounding by drillpipe, the effects of gun perforating and erosion
Tension
Under axial tension, pipe body may suffer 3 possible deformations: Elastic – the metallurgical properties of the
steel in the pipe body suffer no permanent damage and it regains its original form if the load is withdrawn
Elasto-plastic – the pipe body suffers a permanent deformation which often results in the loss of strength)
Plastic
The strength of the casing string is expressed as pipe body yield strength and joint strength.
Pipe body strength is the minimal force required to cause permanent deformation of the pipe.
a y sF Aσ= ( )2 2
4s o iA d dπ= − ( )2 2
4a y o iF d dπ σ= −
Fa = axial force to pull apart the pipe, lbfAs = cross-sectional area of the pipe, in.2σy = minimum yield strength, psido = pipe outer diameter, indi = pipe inner diameter, in
Joint strength is the minimal tensile force required to cause the joint to fail.
For API round threads, joint strength is defined as the smaller of minimal joint fracture force and minimal joint pullout force.
0.95aj up jpF Aσ=For fracture force, joint strength:
For pullout force, joint strength:
0.590.740.95
0.5 0.14 0.14o up y
aj jp etet o et o
dF A L
L d L dσ σ−
= + + +
( )2 20.14254jp o iA d dπ = − − σup = ultimate strength, psi
Ajp = area under last perfect thread, in.2Let = length of engaged thread, in.
Bending force – Casing is subjected to bending forces when run in a deviated wells. The lower surface of the pipe stretches and is in tension. The upper surface shortens and is in compression.
Other tensional forces include:○ Shock load (the vibrational load when running
casing and the slips are suddenly set at the surface)
○ Drag force (frictional force between the casing and the borehole walls)
63b o nF d W= Θ
Wn = nominal weight, lb/ftϴ = dogleg severity, degrees (o)/100 ft
Burst pressure
Minimum expected internal pressure at which permanent pipe deformation could take place, if the pipe is subjected to no external pressure or axial loads. The API burst rating is given as:
20.875 y
bro
tP
dσ
=
Collapse pressure Minimum expected external pressure at
which the pipe would collapse if the pipe were subjected to no internal pressure or axial loads.
There are different types of collapse pressure rating depending on the do/t ratio: Yield strength Plastic Transition Elastic
GradeYield
strength collapse
Plastic collapse
Transition collapse
Elastic collapse
F1 F2 F3 F4 F5
H-40 16.40 27.01 42.64 2.950 0.0465 754 2.063 0.0325
J-, K-55 14.81 25.01 37.21 2.991 0.0541 1,206 1.989 0.0360
C-75 13.60 22.91 32.05 3.054 0.0642 1,806 1.990 0.0418
L-, N-80 13.38 22.47 31.02 3.071 0.0667 1,955 1.998 0.0434
C-90 13.01 21.69 29.18 3.106 0.0718 2,254 2.017 0.0466
P-110 12.44 20.41 26.22 3.181 0.0819 2,852 2.066 0.0532
Ranges of do/t when axial stress is zero
Yield Strength Collapse Pressure
Plastic Collapse Pressure
2
12
o
cr yo
dtPdt
σ
− =
12 3cr y
o
FP F Fdt
σ
= − −
Transition Collapse Pressure
Elastic Collapse Pressure
45cr y
o
FP Fdt
σ
= −
6
246.95 10
1cr
o o
Pd dt t
×=
−
Combined stresses
The performance of casing is examined in the presence of other forces.
axial loadz
sAσ =
2
, 1 0.75 0.5y eff i z z
y y y
Pσ σ σσ σ σ
+= − −
2
, 1 0.75 0.5z zy eff y i
y y
Pσ σσ σσ σ
= − − × −
σz = axial stress, psi (+ve for tension, -ve for compression)Pi = internal pressure, psiσy,eff = effective yield strength, psi
Casing Design Criteria
Casing costs is one of the largest cost items of a drilling project.
It is imperative to plan for proper selection of casing strings and their setting depths to realise an optimal and safe well at minimal costs.
Casing points selection
Initial selection of casing setting depths is based on the pore pressure and fracture pressure gradients for the well.
Information on pore pressure and fracture pressure gradients is usually available from offset well data.
This information should be contained in the geotechnical information provided for planning the well.
Other factors affecting casing points selection include: Shallow gas zones Lost circulation zones, which limit mud weights Well control Formation stability , which is sensitive to
exposure time or mud weight Directional well profile Sidetracking requirements Isolation of fresh water sands (drinking water) Hole cleaning Salt sections
High pressured zones Casing shoes should where practicable be set in
competent formations Casing program compatibility with existing
wellhead systems Casing program compatibility with planned
completion program Multiple producing intervals Casing availability Economy
Design factors
API design factors are essentially “safety factors” that allow us to design safe, reliable casing strings.
Each operator may have his own set of design factors, based on his experience and the condition of the pipe.
The design factors are necessary to cater for: Uncertainties in the determination of actual loads
that the casing needs to withstand. Reliability of listed properties of the various steels
used in the industry and the uncertainty in the determination of the spread between ultimate strength and yield strength.
Uncertainties regarding the collapse pressure formulas.
Possible damage to casing during transport and storage.
Damage to the pipe body from slips, wrenches or inner defects due to cracks, pitting, etc.
Rotational wear by the drill string while drilling.
The use of excessively high design factors guarantees against failure but provides excessive strength and, therefore, increased cost.
The use of low design factors requires accurate knowledge about the loads to be imposed on the casing as there is less margin available.
The company values selected for design factors are a compromise between safety margin and economics.
The API design factors are: Tension and Joint Strength: DFT = 1.8 Collapse: DFC = 1.125 Burst: DFB = 1.1
Example
Required Design factor Design
Tension: 100,000 lbf 1.8 180,000 lbf
Collapse: 10,000 psi 1.125 11,250 psi
Burst: 10,000 psi 1.1 11,000 psi
Worst possible conditions Tension Design
Assume there is no buoyancy effect. Design is based on the weight of the entire
casing string. Collapse Design
Assume that the casing is empty on the inside, that is, no pressure inside the casing and no buoyancy effect.
Design is based on the maximum mud weight at the casing depth
Burst Design Assume no backup fluid on the outside of the
casing. Design is based on maximum pressure on the
inside of the casing. The pressure is to design for is the estimated
formation pressure at TD for production casing, or estimated formation pressure at the next casing depth.
The casing string must be designed to withstand the expected conditions in tension, burst and collapse.
Graphical design method Casing design itself is an optimization
process to find the cheapest casing string that is strong enough to withstand the occuring loads over time.
The design is therefore depended on: Loading conditions during life of well (drilling
operations, completion procedures, production, and workover operations)
Strength of the formation at the casing shoe (assumed fracture pressure during planning and verified by the formation integrity test.
Availabilty and real price of individual casing strings
○ Burst: Assume full reservoir pressure all along the wellbore.
○ Collapse: Hydrostatic pressure increases with depth.○ Tension: Tensile stress due to weight of string is highest
at the top
Analytical design method
Burst requirements Casing must withstand the maximum anticipated
formation pressure that the casing string could possibly be exposed to.
Collapse requirements We start at the bottom of the string and work
our way up.
Our design criteria will be based on hydrostatic pressure resulting from the mud weight that will be in the hole when the casing string is run, prior to cementing.
Worst possible conditions
Burst design: assume no “backup” fluid on the outside of the casing
Collapse design: assume that the casing is empty on the inside.
Tension design: assume no buoyancy effect.
Corrosion Design Considerations
Corrosion “eats” through casing string This reduces the wall thickness It then affects the collapse resistance, burst
resistance and the yield strength, among others. Forecasting the presence and concentration of
corrosion is essential for a choice of a proper casing grade and wall thickness and for operational safety purposes.
Casing can also be subjected to corrosive attack opposite formations containing corrosive fluids
Factors causing corrosion
Most corrosion problems in oilfield operations are due to the presence of water.
Corrosive fluids can be found in water-rich formations and aquifers as well as in the reservoir itself.
Factors initiating and perpetuating corrosion can either act alone or in combination.
Oxygen (O2) Oxygen dissolved in water drastically increases its
corrosivity potential. It can cause severe corrosion at very low
concentrations of less than 1.0 ppm. The solubility of oxygen in water is a function of
pressure, temperature and chloride content. Oxygen is less soluble in salt water than in fresh
water. Oxygen usually causes pitting in steels.
Hydrogen Sulphide (H2S) H2S is very soluble in water and when
dissolved, behaves as a weak acid and usually causes pitting.
This type of attack is called sour corrosion. Other problems from H2S corrosion include
hydrogen blistering and sulphide stress cracking.
The combination of H2S and CO2 is more aggressive than H2S alone.
Carbon Dioxide (CO2) CO2 is soluble in water and forms carbonic acid,
decreases the pH of the water and increase its corrosivity.
It is not as corrosive as oxygen, but usually also results in pitting.
Corrosion by CO2 is referred to as sweet corrosion. Partial pressure of CO2 is used as a yardstick to
predict corrosion.○ Partial pressure < 3 psi: generally non corrosive.○ Partial pressure 3 – 30 psi: may indicate high corrosion
risk.○ Partial pressure > 30 psi: indicates high corrosion risk.
Temperature Like most chemical reactions, corrosion rates
generally increase with increasing temperature.
Pressure The primary effect of pressure is its effect on
dissolved gases. More gas goes into solution as the pressure is
increased, this may in turn increase the corrosivity of the solution.
Velocity of Fluids Stagnant or low velocity fluids usually give low
corrosion rates, but pitting is more likely. Corrosion rates usually increase with velocity as
the corrosion scale is removed from the casing exposing fresh metal for further corrosion.
High velocities and/or the presnce of suspended solids or gas bubbles can lead to erosion, corrosion, impingement or cavitation.
Corrosion control measures
Corrosion control measures may involve the use of one or more of the following: Cathodic protection Chemical inhibition Chemical control Oxygen scavengers Chemical sulphide scavengers pH adjustment Deposit control
Determine the collapse strength for a 5 1/2” O.D., 14.00 #/ft, J-55 casing under axial load of 100,000 lbf
The axial tension will reduce the collapse pressure as follows:
( )2 2
axial load 100,000 24,820 psi5.5 5.012
4
zsA
σ π= = =−
2
, 1 0.75 0.5z zy eff y
y y
σ σσ σσ σ
= × − − 72
Here the axial load decreased the J-55 rating to an equivalent “J-38.2” rating.
, 38 216 psiy eff ,σ =
2
,24,820 24,82055,000 1 0.75 0.555,000 55,000y effσ
= × − −
73
Design a 9-5/8-in., 8,000-ft combination casing string for a well where the mud weight will be 12.5 ppg and the formation pore pressure is expected to be 6,000 psi.
Only the grades and weights shown are available (N-80, all weights). Use API design factors.
Design for “worst possible conditions.”
74
Burst requirement
Dep
th
Pressure
BP Pore pressure Design Factor= ×
BP 6,000 1.1= ×
BP 6,600 psi=
The whole casing string must be capable of withstanding this internal pressure without failing in burst.
Collapse requirement For collapse design, we start at the bottom of the
string and work our way up.
Our design criteria will be based on hydrostatic pressure resulting from the 12.5 ppg mud that will be in the hole when the casing string is run, prior to cementing.
CP 0.052 Mud weight Depth Design Factor= × × ×
CP 0.052 12.5 8,000 1.125= × × ×
CP 5,850 psi=
Further up the hole the collapse requirement are less severe.
Dep
th
Pressure
Req’d: Burst: 6,600 psi Collapse: 5,850 psi
Note that two of the weights of N-80 casing meet the burst requirements
But only the 53.5 #/ft pipe can handle the collapse requirement at the bottom of the hole (5,850 psi).
The 53.5 #/ft pipe could probably run all the way to the surface (would still have to check tension), but there may be a lower cost alternative
To what depth might we be able to run N-80, 47 #/ft?
The maximum annular pressure that this pipe may be exposed to, is:
cCollapse pressure of pipe 4,760P = = =4,231 psi
design factor 1.125
First Iteration At what depth do we see this pressure
(4,231 psig) in a column of 12.5 #/galmud?
c 1 P =0.052×12.5×h
c1
P 4,231h = = = 6,509 ft0.052×12.5 0.052×12.5
This is the depth to which the pipe could be run if there wereno axial stress in the pipe…
But at 6,509’ we have (8,000 - 6,509) = 1,491’ of 53.5 #/ft pipe below us.
The weight of this pipe will reduce the collapse resistance of the 47.0 #/ft pipe!
8,000’6,509’
This weight results in an axial stress in the 47 #/ft pipe.
The API tables show that the above stress will reduce the collapse resistance from 4,760 to somewhere between:4,680 psi (with 5,000 psi stress)and 4,600 psi (with 10,000 psi stress)
1 Weight, W 53.5 #/ ft 1, 491 ft= ×
1W 79,769 lbf=
1 2
weight 79,769 lbf 5,877 psiend area 13.572 in
σ = = =
Interpolation between these values shows that the collapse resistance at 5,877 psi axial stress is:
With the design factor:
( )1c1 1 1 2
2 1
σ σP P P Pσ σ
−= − − −
( )c15,877 5,000P 4,680 4,680 4,600 4,666 psi
10,000 5,000− = − × − = −
c14,666P 4,148 psi1.125
= =
This (4,148 psig) is the pressure at a depth:
Which differs considerably from the initial depth of 6,509 ft, so a second iteration is required.
24,148h 6,382 ft
0.052 12.5= =
×
86
87
Second Iteration Now consider running the 47 #/ft pipe to the
new depth of 6,382 ft.
( )2 Weight, W 53.5 #/ ft 8,000 6,382 ft= × −
2W 86,563 lbf=
2 2
weight 86,563 lbf 6,378 psiend area 13.572 in
σ = = =
Interpolation again:
With the design factor:
( )1c1 1 1 2
2 1
σ σP P P Pσ σ
−= − − −
( )c26,378 5,000P 4,680 4,680 4,600 4,658 psi
10,000 5,000− = − × − = −
c24,658P 4,140 psi1.125
= =
34,140h 6,369 psi
0.052 12.5= =
×
This is within 13 ft of the assumed value. If more accuracy is desired (generally not needed), proceed with the:
Third Iteration
3
3
3
h 6,369 ftW (8,000 6,369) 53.5 87,259 lbf
87,259σ 6,429 psi13.572
== − × =
= =
Interpolation again:
With the design factor:
( )1c1 1 1 2
2 1
σ σP P P Pσ σ
−= − − −
( )c36, 429 5,000P 4,680 4,680 4,600 4,658 psi
10,000 5,000− = − × − = −
c34,658P 4,140 psi1.125
= =
c3 c2P P≅
This is the answer we are looking for: Run 47 #/ft N-80 pipe to a depth of 6,369 ft Run 53.5 #/ft N-80 pipe between 6,369 and
8,000 ft.
Perhaps this string will run all the way to the surface (check tension).
Tension requirement The weight on the top joint of casing would
be:
With the design factor, the pipe strength required is:
(6,369 ft 47.0 #/ft) (1,631 ft 53.5 #/ft)386,602 lbf
= × + ×=
386,602 1.8 695,080 lbf × =
The Halliburton cementing tables give a yield strength of 1,086,000 lbf for the pipe body and a joint strength of 905,000 lbf for LT & C.
Then 47 #/ft can be run to the surface.
N-8047.0 #/ft
N-8053.5 #/ft
6,369 ft
1,631 ft
Surface
8,000 ft