Drilling Engineering - Casing Design

Petroleum Engineering, Drilling Engineering, Casing Design

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 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

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.
( )( )( )
2
10.68 0.0722
n
W OD t t OD= −+ ×

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.
( )10.68
pe
W OD t= −

30. ○L
c= length of coupling (in.)
○J= distance between the end of the pipe and center
of the coupling (in.)
21
20
20 24
Weight of coupling

20
Weight removed in threading two pipe ends

20
c
tc pe
LJ
WW
 +
= − 

+
−

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.
a ys
FAσ= ( )
22
4
s oi
A dd
π
= − ( )
22
4
a yo i
F dd
π
σ
= −
F
a= axial force to pull apart the
pipe, lbf
A
s= cross- sectional area of the
pipe, in.
2
σ
y= minimum yield strength, psi
d
o= pipe outer diameter, in
d
i= 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.
0.95
aj up jp
FA σ=For fracture force,
joint strength:
For pullout force,
joint strength:
0.59
0.74
0.95
0.5 0.14 0.14
o up y
aj jp et
et o et o
d
F AL
LdLdσσ
−

= +

++

( )
2
2
0.1425
4
jp o i
Ad d
π
=−−

σ
up= ultimatestrength, psi
A
jp= area under last perfect
thread, in.
2
L
et= 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)
63
b on
F dW= Θ
W
n= 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:
2
0.875
y
br
o
t
P
dσ
=

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 thed
o/t ratio:
Yield strength
Plastic
Transition
Elastic
Grade
Yield
strength
collapse
Plastic
collapse
Transition
collapse
Elastic
collapse
F
1 F
2 F
3 F
4 F
5
H-40 16.40 27.01 42.64 2.950 0.0465 754 2.063 0.0325
J-, K-55 14.81 25.01 37.212.991 0.0541 1,206 1.989 0.0360
C-75 13.60 22.91 32.053.054 0.0642 1,806 1.990 0.0418
L-, N-80 13.38 22.47 31.023.071 0.0667 1,955 1.998 0.0434
C-90 13.01 21.69 29.183.106 0.0718 2,254 2.017 0.0466
P-110 12.44 20.41 26.223.181 0.0819 2,852 2.066 0.0532
Ranges
of d
o/t
when
axial
stress is
zero

43. Yield Strength Collapse Pressure
Plastic Collapse Pressure
2
1
2
o
cr y
o
d
t
P
d
t
σ


−
=




1
23cr y
o
F
P FF
d
t
σ


= −−





44. Transition Collapse Pressure
Elastic Collapse Pressure
4
5cr y
o
F
PF
d
t
σ


= −




6
2
46.95 10
1
cr
oo
P
dd
tt
×
=

−



45. Combined stresses
The performance of casing is examined
in the presence of other forces.
axial load
z
s
A
σ=
2
,
1 0.75 0.5
y eff i zz
y yy
Pσ σσ
σ σσ
 +
=−−  
 
 

46. 2
,
1 0.75 0.5
zz
y eff y i
yy
P
σσ
σσ
σσ

 

= − − ×− 
 
 

σ
z= axial stress, psi(+ve for tension, -
ve for compression)
P
i= internal pressure, psi
σ
y,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:DF
T= 1.8
Collapse: DF
C= 1.125
Burst: DF
B= 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 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

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 (O
2)
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 (H
2S)
H
2S 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 H
2S corrosion include
hydrogen blistering and sulphide stress
cracking.
The combination of H
2S and CO
2is more
aggressive than H
2S alone.

68. Carbon Dioxide (CO
2)
CO
2is 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 CO
2is referred to as sweet corrosion.
Partial pressure of CO
2is 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:
( )
22
axial load 100,000
24,820 psi
5.5 5.012
4
z
s
A
σ
π= = =
−
2
,
1 0.75 0.5
zz
y eff y
yy
σσ
σσ
σσ

 

=×− −  
 
 

72

73. Here the axial load decreased the J- 55
rating to an equivalent “J- 38.2” rating.
,
38216 psi
y eff
,σ=
2
,
24,820 24,820
55,000 1 0.75 0.5
55,000 55,000
y eff
σ


= ×− −

 

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
B
P Pore pressure Design Factor= ×
B
P 6,000 1.1= ×
B
P 6,600 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. C
P 0.052 Mud weight Depth Design Factor=× ××
C
P 0.052 12.5 8,000 1.125= ×× ×
C
P 5,850 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 burst requirements
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:
c
Collapse pressure of pipe 4,760
P= = =4,231 psi
design factor 1.125

81. First Iteration
At what depth do we see this pressure
(4,231 psig)in a column of 12.5 #/gal
mud?
c1
P=0.052×12.5×h
c
1
P 4,231
h = = = 6,509 ft
0.052×12.5 0.052×12.5

82. This is the depth to which the pipe
could be run if there were
noaxial 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,W 53.5 #/ft 1,491 ft= ×
1
W 79,769 lbf=
1 2
weight 79,769 lbf
5,877 psi
end area 13.572 in
σ= = =

84. Interpolation between these values shows
that the collapse resistance at 5,877 psi axial
stress is:
With the design factor:
( )
1
c1 1 1 2
21
σσ
P P PP
σσ
−
=−−
−

( )
c1
5,877 5,000
P 4,680 4,680 4,600 4,666 psi
10,000 5,000
−
=− ×−=

−
c1
4,666
P 4,148 psi
1.125
= =

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.
2
4,148
h 6,382 ft
0.052 12.5
= =
×

86. 86

87. 87

88. Second Iteration
Now consider running the 47 #/ft pipe to the
new depth of 6,382 ft.
( )
2
Weight,W 53.5 #/ft 8,000 6,382 ft= ×−
2
W 86,563 lbf=
2 2
weight 86,563 lbf
6,378 psi
end area 13.572 in
σ= = =

89. Interpolation again:
With the design factor:
( )
1
c1 1 1 2
21
σσ
P P PP
σσ
−
=−−
−

( )
c2
6,378 5,000
P 4,680 4,680 4,600 4,658 psi
10,000 5,000
−
=− ×−=

−
c2
4,658
P 4,140 psi
1.125
= =
3
4,140
h 6,369 psi
0.052 12.5
= =
×

90. 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 ft
W (8,000 6,369) 53.5 87,259 lbf
87,259
σ 6,429 psi
13.572
=
= − ×=
= =

91. Interpolation again:
With the design factor:
( )
1
c1 1 1 2
21
σσ
P P PP
σσ
−
=−−
−

( )
c3
6,429 5,000
P 4,680 4,680 4,600 4,658 psi
10,000 5,000
−
=− ×−=

−
c3
4,658
P 4,140 psi
1.125
= =
c3 c2
PP≅

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 ft 47.0 #/ft) (1,631 ft 53.5 #/ft)
386,602 lbf
=× +×
=
386,602 1.8 695,080 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