The document discusses the functions and types of casing strings used in oil and gas wells. It describes the different casing strings like conductor casing, surface casing, intermediate casing, and production casing. It also covers casing design criteria like classifications based on outside diameter, length, connections, weight, and grade. The mechanical properties of casing are discussed in relation to withstanding tensile, burst, and collapse loads during drilling and production operations.

1. JAMES A. CRAIG

2. Table of Contents

Functions of Casing

Types of Casing Strings

Classification of Casing

Mechanical Properties of Casing

Casing Design Criteria

Corrosion Design Considerations

3. 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

4. 
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.

5. 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

6. 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

7. Conductor pipe (7to 20in. 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.

8. 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.

9. 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

10. 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

11. 
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.

13. Liners

They are casings that do not reach the surface.

They are mounted on liner hangersto 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

14. 
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.

16. 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

17. 
Classifications to be considered are:

Outside diameter (OD).

Inside diameter (ID), wall thickness, drift diameter.

Length (range)

Connections

Weight

Grade

18. 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.

19. Inside Diameter (ID), Wall Thickness, Drift Diameter

The ID is specified in terms of wall thickness and drift diameter.

The maximalID 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%.

20. 
The minimalID 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

21. 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

22. 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.

23. 
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

24. API
Round Thread Connector

25. API
Buttress Thread Connector

26. API
Extreme-Line Connector

27. 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

28. 
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.
()()()210.680.0722nWODttOD=−+×

29. 
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 andcoupling 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.
()10.68peWODt=−

30. ○
Lc= length of coupling (in.)
○
J= distance between the end of the pipe and center of the coupling (in.)
21202024Weight of coupling 20Weight removed in threading two pipe ends 20ctcpeLJWW +=− + −

31. 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

32. 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

33. Tension

Under axial tension, pipe body may suffer 3possible 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

34. 
The strength of the casing string is expressed as pipe body yield strength and joint strength.

35. 
Pipe body strengthis the minimal force required to cause permanent deformation of the pipe.
aysFAσ=()224soiAddπ =−()224ayoiFddπσ=−
Fa= axial force to pull apart the pipe, lbf
As= cross-sectional area of the pipe, in.2
σy= minimum yield strength, psi
do= pipe outer diameter, in
di= pipe inner diameter, in

36. 
Joint strengthis 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 forceand minimal joint pullout force.
0.95ajupjpFAσ=
For fracture force, joint strength:
For pullout force, joint strength:
0.590.740.950.50.140.14oupyajjpetetoetodFALLdLd σσ− =+++ ()220.14254jpoiAddπ=−−
σup= ultimatestrength, psi
Ajp= area under last perfect thread, in.2
Let= length of engaged thread, in.

37. 
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.

38. 
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)
63bonFdW=Θ
Wn= nominal weight, lb/ft
ϴ= dogleg severity, degrees (o)/100 ft

39. Burst pressure

Minimum expected internal pressureat 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:
20.875ybrotPd σ =

41. Collapse pressure

Minimum expected external pressureat which the pipe would collapse if the pipe were subjected to no internal pressure or axial loads.

42. 
There are different types of collapse pressure rating depending on thedo/t ratio:

Yield strength

Plastic

Transition

Elastic
Grade
Yield strength collapse
Plastic collapse
Transition collapse
Elastic collapse
F1F2F3F4F5
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

43. 
Yield Strength Collapse Pressure

Plastic Collapse Pressure
212ocryodtPdt σ − =    123cryoFPFFdt σ   =−−  

44. 
Transition Collapse Pressure

Elastic Collapse Pressure
45cryoFPFdt σ   =−   6246.95101crooPddtt×= −

45. Combined stresses

The performance of casing is examined in the presence of other forces.
axial loadzsA σ= 2,10.750.5yeffizzyyyPσσσσσσ + =−− 

46. 2,10.750.5zzyeffyiyyP σσσσσσ =−−×−
σz= axial stress, psi(+ve for tension, - ve for compression)
Pi= internal pressure, psi
σy,eff= effective yield strength, psi

47. 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.

48. 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.

51. 
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

52. 
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

53. 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.

54. 
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.

55. 
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.

56. 
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

57. 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

58. 
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.

59. Graphical design method

Casing design itself is an optimization process to find the cheapestcasing 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

60. ○
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

61. Analytical design method

Burst requirements

Casing must withstand the maximum anticipated formation pressure that the casing string could possibly be exposed to.

62. 
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.

63. 
Worst possible conditions

Burstdesign: assume no “backup” fluid on the outside of the casing

Collapsedesign: assume that the casing is empty on the inside.

Tension design: assume no buoyancy effect.

64. 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

65. 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.

66. 
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.

67. 
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 CO2is more aggressive than H2S alone.

68. 
Carbon Dioxide (CO2)

CO2is 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 CO2is referred to as sweet corrosion.

Partial pressure of CO2is 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.

69. 
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.

70. 
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.

71. 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

72. 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: ()22axial load100,00024,820 psi5.55.0124zsA σπ === − 2,10.750.5zzyeffyyy σσσσσσ =×−−
72

73. Here the axial load decreased the J-55
rating to an equivalent “J-38.2” rating.
,38216 psiyeff,σ= 2,24,82024,82055,00010.750.555,00055,000yeffσ =×−−
73

74. Design a 9-5/8-in., 8,000-ft combination casing string for a well where the mud weight will be 12.5 ppgand 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

75. 
Burst requirement
Depth
Pressure
BPPore pressureDesign Factor=×BP6,0001.1=×BP6,600 psi=
The whole casing string must be capable of withstanding this internal pressure without failing in burst.

76. 
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.

77. CP0.052Mud weight DepthDesign Factor=×××CP0.05212.58,0001.125=×××CP5,850 psi=
Further up the hole the collapse requirement are less severe.
Depth
Pressure

78. Req’d:Burst:6,600 psiCollapse:5,850 psi

79. 
Note that two of the weights of N-80 casing meet the burstrequirements

But only the 53.5 #/ft pipe can handle the collapserequirement 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

80. 
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 pipe4,760P===4,231 psidesign factor1.125

81. 
First Iteration

At what depth do we see this pressure (4,231 psig)in a column of 12.5 #/galmud?
c1 P=0.052×12.5×hc1P4,231h=== 6,509 ft0.052×12.50.052×12.5

82. 
This is the depth to which the pipe
could be run if there werenoaxial 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’

83. 
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,W53.5 #/ft1,491 ft=×1W79,769 lbf= 12weight79,769 lbf5,877 psiend area13.572 in σ===

84. 
Interpolation between these values shows that the collapse resistance at 5,877 psi axial stress is:

With the design factor:
()1c111221σσPPPPσσ − =−−− ()c15,8775,000P4,6804,6804,6004,666 psi10,0005,000−=−×−=− c14,666P4,148 psi1.125==

85. 
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.
24,148h6,382 ft0.05212.5== ×

86. 86

87. 87

88. 
Second Iteration

Now consider running the 47 #/ft pipe to the new depth of 6,382 ft.
()2 Weight,W53.5 #/ft8,0006,382 ft=×− 2W86,563 lbf= 22weight86,563 lbf6,378 psiend area13.572 in σ===

89. 
Interpolation again:

With the design factor:
()1c111221σσPPPPσσ − =−−− ()c26,3785,000P4,6804,6804,6004,658 psi10,0005,000−=−×−=− c24,658P4,140 psi1.125== 34,140h6,369 psi0.05212.5== ×

90. 
This is within 13 ft of the assumed value. If more accuracy is desired (generally not needed), proceed with the:

Third Iteration
333h6,369 ftW(8,0006,369)53.587,259 lbf87,259σ6,429 psi13.572= =−×= ==

91. 
Interpolation again:

With the design factor:
()1c111221σσPPPPσσ − =−−− ()c36,4295,000P4,6804,6804,6004,658 psi10,0005,000−=−×−=− c34,658P4,140 psi1.125== c3c2PP≅

92. 
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).

93. 
Tension requirement

The weight on the top joint of casing would be:

With the design factor, the pipe strength required is:
(6,369 ft47.0 #/ft)(1,631 ft53.5 #/ft) 386,602 lbf=×+×= 386,6021.8695,080 lbf ×=

94. 
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.

95. N-80
47.0 #/ft
N-80
53.5 #/ft
6,369 ft
1,631 ft
Surface
8,000 ft