1. Chapter 2: Casing Design Casing Selection

2. Introduction
To obtain the most economical design, casing strings often consist of multiple sections of different steel grade, casing depths, wall thickness, and coupling types.
Such a casing string is called a combination string.
Additional cost savings sometimes can be achieved by the use of liner combination strings instead of full strings running from the surface to the bottom of the hole.
However, the potential savings must be weighted against the additional risks and costs of a successful, leak-free tieback operation as well as the additional casing wear that results from a longer exposure of the upper casing to rotation and translation of the drill string.

3. Casing Design Process
1. Select the Casing sizes and setting depths on the basis of: the geological and pore pressure prognosis provided by the geologist and reservoir engineer; and the production tubing requirements on the basis of the anticipated productivity of the formations to be penetrated.
2. Define the operational scenarios to be considered during the design of each of the casing strings. This should include installation, drilling and production (as appropriate) operations.
3. Calculate the burst loading on the particular casing under consideration.
4. Calculate the collapse loading on the particular casing under consideration.
5. Increase the calculated burst and collapse loads by the Design Factor.

4. Casing Design Process
6. Select the weight and grade of casing (from manufacturers tables or service company tables) which meets the load conditions calculated above.
7. For the casing chosen, calculate the axial loading on the casing. Apply the design factor for the casing and load conditions considered and check that the pipe body yield strength of the selected casing exceeds the axial design loading.
8. Choose a coupling whose joint strength is greater than the design loading. Select the same type of coupling throughout the entire string.
9. Taking the actual tensile loading from above determine the reduction in collapse resistance at the top and bottom of the casing.

5. Casing Design Process
Several attempts may have to be made before all these loading criteria are satisfied and a final design is produced. When deciding on a final design bear the following points in mind:
• Include only those types of casing which you know are available. In practice only a few weights and grades will be kept in stock.
• Check that the final design meets all requirements and state clearly all design assumptions.
• If several different designs are possible, choose the most economical scheme that meets requirements.

6. Selection of Casing Setting Depths
The selection of the number of casing strings and their setting depths generally is based on a consideration of the pore pressure gradients and fracture gradients of the formations to be penetrated.
The pore pressure and fracture pressure are expressed as an equivalent density and are plotted vs. depth. A line representing the planned-mud-density program also is plotted.
The mud densities are chosen to provide an acceptable trip margin above the anticipated formation pore pressure to allow for reductions in mud weight caused by upward pipe movement during tripping operation.
A commonly used trip margin is 0.5 lbm/gal or one that will provide psi of excess bottomhole pressure over the formation pore pressure.

7. Selection of Casing Setting Depths

8. Selection of Casing Setting Depths
Point a: to prevent the formation fluid into the well and to reach the desired depth.
Point b: to prevent the fracture of formation --> intermediate casing need to run at this depth.
Point c: Fluid density is reduced until it reaches to margin of the curve
Point d: casing shoe of the surface casing

9. Example
A well is being planned for a location in Jefferson Parish, LA. The intended well completion requires the use of 7’’ production casing set at 15,000 ft. Determine the number of casing strings needed to reach this depth objective safely, and select the casing setting depth of each string. Pore pressure and fracture gradient, and lithology data from logs of nearby wells are given in the next Figure. Allow a 0.5 lbm/gal trip margin, and a 0.5 lbm/gal kick margin when making the casing seat selections. The minimum length of surface casing required to protect the freshwater aquifers is 2000ft. Approximately 180 ft of conductor casing generally is required to prevent washout on the outside of the conductor. It is general practice in this are to cement the casing in shale rather than in sandstone.

10. Example

11. Selection of Casing Sizes
To enable the production casing to be placed in the well, the bit size used to drill the last interval of the well must be slightly larger than the OD of the casing connectors.
The selected bit size should provide sufficient clearance beyond the OD of the coupling to allow for mud cake on the borehole wall and for casing appliances, such as centralizers and scratchers.
The bit used to drill the lower portion of the well also must fit inside the casing string above.
The production tubing also depends on the basis of the anticipated productivity of the formations to be penetrated.

12. Selection of Casing Sizes

13. Selection of Casing Sizes

14. Load Calculations in Casing Design
In general, each casing string is designed to withstand the most severe loading conditions anticipated during casing placement and the life of the well. The loading conditions that are always considered are burst, collapse, and tension.
Because the loading conditions in a well tend to vary with depth, it is often possible to obtain a less expensive casing design with several different weights, grades, and couplings.
The casing design usually is based on an assumed loading condition.
The assumed design load must be severe enough that there is a very low probability of a more severe situation actually occurring and causing casing failure.

15. Load Calculations in Casing Design Surface and Intermediate Casings
The high-internal pressure loading condition used for the burst design is based on a well control condition assumed to occur while circulating out a large kick.
The high-external pressure loading condition used for the collapse design is based on a severe lost-circulation problem.
The high-axial tension loading condition is based on an assumption of stuck casing while the casing is run into the hole before cementing operations.

16. Design for Surface and Intermediate Casings
Burst Design
The burst design should ensure that formation fracture pressure at the casing seat will be exceed before the burst pressure is reached.
Thus, this design uses formation fracture as a safety pressure release mechanism to ensure that casing rupture will not occur at the surface.
The pressure within the casing is calculated assuming that only formation gas is in the casing.
The external pressure outside the casing that helps resist burst is assumed to be equal to the normal formation pore pressure for the area.

17. Design for Surface and Intermediate Casings
Burst Design
Pabn
Pshoe Ps
Internal Pressure:
Pi = Pfracture at the shoe
External Pressure:
Pe = Pnormal formation Pi Pe

18. Design for Surface and Intermediate Casings
Collapse Design
The collapse design is based either on the most severe lost-circulation problem that is felt to be possible or on the most severe collapse loading anticipated when the casing is run.
For both cases, the maximum possible external pressure that tends to cause casing collapse results from the formation pressure (if abnormal formation pressure exists, this Pff will be used as the external pressure).

19. Design for Surface and Intermediate Casings
Collapse Design
Internal Pressure:
Pi = 0
External Pressure:
Pe = Pabnormal formation Pi Pe
Empty
Mud
Collapse
Lost Circulation
Dlc Dm

20. Design for Surface and Intermediate Casings
Collapse Design
If a severe lost circulation zone is encountered near the bottom of the next interval of hole and no other permeable formations are present above the lost circulation zone, the fluid level in the well can fall until the BHP is equal to the pore pressure of the lost circulation zone.
where Dlc is the depth of the lost circulation zone; rp is the formation fluid density; rmax is the maximum mud density anticipated in drilling to Dlc; and Dm is the depth to which the mud level will fall.

21. Design for Surface and Intermediate Casings
Tension Design
In most cases, the design load for tension is based on conditions that could occur when the casing is run. It is assumed that the casing may become stuck near the bottom and that a maximum amount of pull would then be required to work the casing free.
In directional wells, the additional axial stress in the pipe body and connectors caused by bending should be added to the axial stress that results from casing weight and fluid hydrostatic pressure. The lower portion of the casing will have to travel past all the curved sections in the wellbore, but the upper section of the casing may not be subjected to any bending.

22. Design for Surface and Intermediate Casings
Tension Design

23. Design for Production Casings
Burst Design
The burst-design loading condition assumes a producing well has an initial shut-in. The BHP equal to the formation pore pressure and a gaseous produced fluid in the well.
The production casing must be designed so that it will not fail of the tubing fails
A tubing leak is assumed to be possible at any depth. It generally is also assumed that the density of the completion fluid in the casing above the packer is equal to the density of the mud left outside the casing.

24. Design for Production Casings
Collapse Design
The collapse design load is based on conditions late in the life of the reservoir, when reservoir pressure has been depleted to a very low abandonment pressure.
A leak in the tubing or packer could cause the loss of the completion fluid, or the casing is totally evacuated due to gas-lifting operations.
Thus, for design purposes, the entire casing is considered empty. The fluid density outside the casing is assumed to be that of the mud in the well when the casing was run, and the beneficial effect of the cement is ignored.
The tension design load criteria for production casing are the same as for surface and intermediate casings.

25. Example
The table below is a data set from a real land well. As a drilling engineer you are required to calculate the burst and collapse loads that would be used to select an appropriate weight and grade of casing for the Surface, Intermediate and Production strings in this land well:
Hole Size Depth, ft
Casing size, in
Expected min/max Pf, ppg
Expected Pff gradient, ppg
Mud weight, ppg
Potential hole problems
Driven 100
30’’
26’’ 3000
20’’
8.6 ft
9.0
Unconsolidated
17 ½’’
13 3/8’’
8.6/9.5 ft
11.0
Possible lost circ.
12 ¼’’ 10,000
9 5/8’’
9.5/11
10,000 ft
14.0
Unstable shales
8 ½’’ 9,500-12,000
7’’
11/14
15.0
Overpressured

26. Example Assumptions: Gas density above 10,000 ft: 0.1 psi/ft
Design factor for burst: 1.1
Design factor for collapse: 1.0
Well test completion fluid density: 8.6 ppg
Test packer depth: 11,000 ft TVD
Test perforation depth: 11,250 ft TVD
Pressure at top of perforations: 14.0 ppg

27. Surface Casing (20’’ at 3,000 ft)
Example
Surface Casing (20’’ at 3,000 ft)
Burst Design:
Depth
External Load, Pe
Internal Load, Pi
Net Load
Design Load (SF)
Surface
Shoe

28. Surface Casing (20’’ at 3,000 ft)
Example
Surface Casing (20’’ at 3,000 ft)
Burst Design
Internal Loads: Assuming that an influx of gas has occurred and the well is full of gas to surface
Pressure at bottom of 17 ½’’ hole = 9.5 x x 6000 = 2964 psi
P at surface (Ps) = P at bottom of 17 ½’’ hole – P due to column of gas
Ps = 2964 – 0.1 x 6,000 = 2364 psi
Pressure at 20’’ casing shoe = 2964 – 0.1 x 3,000 = 2,664 psi

29. Surface Casing (20’’ at 3,000 ft)
Example
Surface Casing (20’’ at 3,000 ft)
Burst Design
Internal Loads:
Fracture pressure at 20’’ casing shoe = 13 x x 3,000 = 2,028 psi
The formation at the casing shoe will breakdown at 2028 psi and therefore it will breakdown if the pressure of 2664 psi is applied to it. The maximum pressure inside the surface casing at the shoe will therefore be at 2,028 psi
The maximum pressure at surface will be: 2028 – 0.1 x 3,000 = 1728 psi

30. Surface Casing (20’’ at 3,000 ft)
Example
Surface Casing (20’’ at 3,000 ft)
External load: assuming that the pore pressure is acting at the casing shoe and zero pressure at surface.
Pore pressure at the casing shoe = 8.6 x x 3,000 = 1,342 psi
External pressure at surface = 0 psi
Casings have to be stronger at the surface to prevent the burst of the casings because the net load at the surface is higher than at the casing shoe.
Depth
External Load, Pe
Internal Load, Pi
Net Load
Design Load (SF)
Surface
1728
1901
Shoe (3000 ft)
1342
2028
686
755

31. Surface Casing (20’’ at 3,000 ft)
Example
Surface Casing (20’’ at 3,000 ft)
Fracture pressure
External pressure
Internal pressure

32. Surface Casing (20’’ at 3,000 ft) – Collapse Design
Example
Surface Casing (20’’ at 3,000 ft) – Collapse Design
Depth
External Load, Pe
Internal Load, Pi
Net Load
Design Load (SF)
Surface
Shoe

33. Surface Casing (20’’ at 3,000 ft)
Example
Surface Casing (20’’ at 3,000 ft)
Collapse Design:
Internal Loads: Assuming that the casing is totally evacuated due to loss of drilling mud.
Internal pressure at surface = 0 psi
Internal pressure at shoe = 0 psi
External Loads: Assuming that the pore pressure is acting at the casing shoe and zero pressure at surface
Pore pressure at the casing shoe = 8.6 x x 3000 = 1,341 psi
External pressure at surface = 0 psi

34. Surface Casing (20’’ at 3,000 ft)
Example
Surface Casing (20’’ at 3,000 ft)

35. Intermediate Casing (13 3/8’’ at 6,000 ft)
Example
Intermediate Casing (13 3/8’’ at 6,000 ft)
Burst Design:

36. Intermediate Casing (13 3/8’’ at 6,000 ft)
Example
Intermediate Casing (13 3/8’’ at 6,000 ft)
Burst Design:

37. Intermediate Casing (13 3/8’’ at 6,000 ft)
Example
Intermediate Casing (13 3/8’’ at 6,000 ft)
Collapse Design:

38. Intermediate Casing (13 3/8’’ at 6,000 ft)
Example
Intermediate Casing (13 3/8’’ at 6,000 ft)
Collapse Design:

39. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Pf = 9.5/11 ppg
Pff = 16.5 ppg
Pf = 11/14 ppg

40. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Burst Design:
Internal Loads: Assuming that a leak occurs in the tubing at surface and that the closed in tubing head pressure (CITHP) is acting on the inside of the top of the casing.
This pressure will then act on the column of packer fluid. The 9 5/8’’ casing is only exposed to these pressure down to the Top of Liner (TOL). The 7’’ liner protects the remainder of the casing.
Pf = 9.5/11 ppg
Pff = 16.5 ppg
Pf = 11/14 ppg

41. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Burst Design:
Max. Pore Pressure at the top of the production zone = 14 x x 11,250 = 8,190 psi
CITHP (at surface) = P at the top of perforation – P due to column of gas (0.15 psi/ft)
CITHP = 8190 – 0.15 x 11,250 = 6,503 psi
Pressure at Top of Liner = CITHP + hydrostatic column of packer fluid
Pressure at Top of Liner = 6, x x 9,500 = 10,751 psi
Pf = 9.5/11 ppg
Pff = 16.5 ppg
Pf = 11/14 ppg

42. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Burst Design:
External Loads: Assuming that the minimum pore pressure is acting at the liner depth and zero pressure at surface.
Pore pressure at the Top of Liner = 9.5 x x 9,500 = 4,693 psi
External pressure at surface = 0 psi
Pf = 9.5/11 ppg
Pff = 16.5 ppg
Pf = 11/14 ppg

43. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Burst Design:

44. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Burst Design:

45. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Collapse Design:
Internal Loads: Assuming that the casing is totally evacuated due to gas-lifting operations
Internal pressure at surface = 0 psi
Internal pressure at Top of Liner (TOL) = 0 psi
External Loads: Assuming that the maximum pore pressure is acting on the outside of the casing at the TOL.
Pore pressure at the TOL = 11 x x 9,500 = 6,916 psi
Pf = 9.5/11 ppg
Pff = 16.5 ppg
Pf = 11/14 ppg

46. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Collapse Design:
6916 psi

47. Production Casing (9 5/8’’ at 10,000 ft)
Example
Production Casing (9 5/8’’ at 10,000 ft)
Collapse Design:
Summary of Collapse Loads
6,916

48. Example

49. Example

50. Example

51. Example

52. Example
A well is being planned for a location in Jefferson Parish, LA. The minimum length of surface casing required to protect the freshwater aquifers is 2000ft. Design the surface casing for the proposed well. To achieve a minimum cost design, consider the use of a combination string. However, do not include any section shorter than 500 ft to reduce the logistical problem of shipping and unloading the casing in the proper order in which it is run in to hole. Assume only casing shown in the Table 7.6 is available.
The design shows that OD of the casing is 13 3/8’’ and to be set at 4,000 ft.

53. Example
For burst considerations, use an injection pressure that is equivalent to a mud density of 0.3 lbm/gal greater than the fracture gradient and a safety factor of 1.1. Also assume that any gas kick is composed of methane. Normal formation pressure for the area is psi/ft. Formation temperature in degrees Rankine: ( D)
For collapse considerations, assume that a normal pressure, lost circulation zone could be encountered as deep as the next casing seat, that no permeable zones are present above the lost circulation zone, and use the safety factor of 1.1.
For tension considerations, use a minimum overpull force of 100,000 lbf or a safety factor of 1.6, whichever is greater.

54. Example

55. Example

56. Example
Solution:
The fracture gradient at 4,000 ft is 14.1 lbm/gal mud. For an injection pressure:
Pi = 0.052( )(4,000) = 2,995 psig.
The gas gradient for methane:
rg = psi/ft

57. Example

58. Example
Thus, the surface casing pressure for the design loading conditions:
2,995 – 0.055(4,000) = 2,775 psig
The external pressure at the casing seat:
(0.465)(4,000) = 1,860 psig
The pressure differential to burst the casing: (2,995 – 1,860) = 1,135 psig
With a safety factor of 1.1, the burst design pressure at 4,000 ft = 1,249 psig
The burst design pressure at surface: 2,775 x 1.1 = 3,053 psig

59. Burst Design Summary of burst loads
The H-40 has the burst pressure rating of 1,730 psi (Barlow’s equation). This casing can be used at the depth shallower than:
(3,053 – 1,730)(4,000)/(3,053 – 1,249) = 2,933 ft
The J-55 has the burst pressure rating of 2,730 psi. This casing can be set below
(3,053 – 2,730)(4,000)/(3,053 – 1,249) = 2,933 ft
All other casings listed have burst pressure ratings more than the design requirements
Depth
External Load
Internal Load
Net Load
Design Load (SF = 1.1)
Surface
2,775
3,053
@ 4,000 ft
1,860
2,995
1,135
1,249

60. Collapse Design
The external pressure of the collapse design based on the 9.3 lbm/gal mud:
(0.052)(9.3)(4,000) = 1,934 psig.
The internal pressure for the collapse design based on the maximum loss in the fluid level.
The internal pressure at 3,959 ft is zero and the internal pressure at 4,000 ft is
(0.052)(13.7)(41) = 29 ft
External pressure at 3,959 ft: (0.052)(9.3)(3,959) = 1,915 psi

61. Collapse Design Summary of collapse loads
The bottom section of casing will be composed of C-75, 68-lbm/ft casing.
Depth
External Load
Internal Load
Net Load
Design Load (SF = 1.1)
Surface
3,959 ft
1,915
2,107
4,000 ft
1,934 29
1,905
2,096

62. Collapse Design
To determine the minimum possible length of C-75, 68-lbm/ft casing, we consider the free body diagram below:

63. Force balance: Fa = 68L1 – p1As + p2DAs2 The cross sectional area:
Collapse Design
Force balance: Fa = 68L1 – p1As + p2DAs2
The cross sectional area: