1. Casing Point Selection
Casing Design Workshop

2. Chapter Objectives
Acquire knowledge of the casing point selection process
Select casing points for an example well

3. Chapter Outline
Depth Selection Process
Data
Example

4. Casing Design Procedure
You Are Here
Select casing depths
Select casing sizes
Calculate collapse and burst loads
Make preliminary casing selection
Calculate axial loads (tens./compr.)
Adjust preliminary selection for axial loads
Calculate combined load effects
Adjust and make final selection
This is the first appearance of the design procedure. Explain the procedure here.

5. Casing String Depths How do we know where to set these casing strings?
How many casing strings do we need?

6. Chapter Content Casing Points A Note on Fracture Pressures
Determining Parameters
Conductor Casing Depth
Surface Casing Depth
Intermediate Casing Depth
A Note on Fracture Pressures

7. Casing Depth Criteria Regulations
Accepted practice based on successful local experience
Formation pore pressures
Formation fracture pressures
Formation lithology
Borehole stability problems

8. Overview of Casing Intervals Video Clip
Running Casing

9. Conductor Casing One or two conductor strings
Provide borehole integrity for drilling surface hole
Support wellhead (in some cases)
Typical Depths: 50 ft to 500 ft
Criteria for Depth Selection:
Common practice in area
Soil tests

10. Surface Casing Provides initial pressure control
Protects fresh water aquifers
Supports wellhead and subsequent casing strings when conductor is cut off
Depth Selection Criteria:
Regulations
Pore pressures & fracture pressures
Depth of next casing string

11. Intermediate Casing Provides borehole integrity and pressure control
Required mud densities exceed fracture pressures of shallower zones
Required mud densities less than pore pressures of shallower zones
Depth Selection Criteria:
Pore pressures & fracture pressures
Borehole stability problems
Depth of next casing
Regulations (rarely)

12. Production Casing
Provides full pressure protection for the entire wellbore
A conduit for the tubing
A pressure backup for the production tubing
Depth Selection Criteria:
Depth of producing interval
Possible future completions in wellbore

13. Liners & Tie-backs
Liners and tie-backs are extensions of other casing strings
Depth selection criteria:
Same or similar to the string they are extending
Usually pore pressure and fracture pressure are most significant factors
Borehole stability issues
Regulatory considerations (add to permanent presentation)

14. Pore and Fracture Pressures
Plot the pore pressure and fracture pressures
Great opportunity to supplement with Geoscience modules on pore pressure, fracture pressure and calculation of each from seismic and petrophysical data

15. Video Clips on Pore Pressure and Fracture Gradient (BL)
C CCR Pore Pressure and Fracture Gradient
Formation pressure of Well control Top 17 Facts
Fracture pressure of Well control Top 8 Facts

16. Insert from Geoscience (Basic/Foundation)
Pore Pressure Definition from Geoscience
Pore Pressure Derivation from Seismic
Pore Pressure Derivation from Petrophysics
This is a placeholder for Basic-Foundational Modules with “dig deeper” from other courses
Need new material from others JEB

17. Insert from Geoscience (Basic/Foundation)
Fracture Pressure Definition from Geoscience
Fracture Pressure Derivation from Seismic
Fracture Pressure Derivation from Petrophysics
This is a placeholder for Basic-Foundational Modules with “dig deeper” from other courses
Need new material from others

18. Considerations for “safety margin” (BL)
Factors that control the safety margin include:
Kick tolerance
Kick intensity
Kick volume
Equivalent Circulating Density
Swab pressures
Surge pressures
Well barrier practices
New slide to add to over-all presentation and discussion in manual
Not in manual. I’ve been using this one JEB

19. Video Clips w/Reminders (BL)
Operational Considerations for Safety Margin
Pipe surge/swab of Well control Top 11 Facts
Insufficient mud (fluid) density of Well control Top 5 Facts
Not keeping the hole full of Well control Top 5 Facts
Not in manual. I’ve been using this one JEB

20. Insert from BDT, WDE and/or DP (Basic/Foundation)
Definition and calculation of ECD from BDT or WDE or DP
Definition and calculation of swab pressure from BDT or WDE or DP
Definition and calculation of surge pressure from BDT or WDE or DP
This is a placeholder for Basic-Foundational Modules with “dig deeper” from other courses
Need new material from others JEB

21. Add Safety Margins
The margins used here are arbitrary (usually include ECD, surge pressures, swab pressures, kick tolerance etc.), there are no standards. (See later slide for criteria). One can also use different margins for formation pore pressure and formation fracture pressure. I used 0.5 ppg here in both cases as a convenience to avoid getting myself repeatedly confused.

22. Example Selecting Depths
Start at the bottom of the chart
The maximum mud weight at bottom must not exceed the fracture gradient at any point in the hole
At all points above about 1700 ft the maximum mud weight at bottom exceeds the fracture pressure (plus safety margin)
Select a casing point at 1700 ft

23. Determine Casing Depths

24. Comments That example was straight forward and easy
Most wells drilled in the world are exactly like that – simple and easy
Many are not

25. Another Example (Abnormal Pressure)
Over pressured zones. Also cases where the pressure decreases with depth. And for some cases there are zones pressured from previous underground blowouts or behind-pipe cross flow, as well as depleted zones.

26. Example This well requires three strings of casing (plus conductor):
Production casing: 14,000 ft ft
Intermediate casing: 10,500 ft
Surface casing: 3,000 ft
There are alternatives with a production liner or a production liner and tie-back

27. Alternatives
This needs a voice-over to explain the trade-offs between intermediate and liner vs tie-back and liner. I usually introduce the concept of Pmean optimization. This requires understanding P10, P50, P90, Swanson’s Mean and our well plan objective is to “lower the Pmean”. This needs some thought. JEB

28. Considerations for Alternatives Selection (BL)
If you select the Intermediate/Liner scenario, you must always run a casing caliper log and evaluate the results
If the results are questionable, either a patch or a tie-back are required and need to be readily available for deployment
Occasionally, the liner/tieback is selected to improve the primary cement job and/or the cement job back to surface
Describe example of reverse cementing job in Madden 22,000’

29. Lowering Pmean Alternatives (BL)
P10 is the cost that occurs 10% of the time
P50 is the cost that occurs 50% of the time
P90 is the cost that occurs 90% of the time
More can go wrong than can go right. P90 is always skewed in comparison to P90. The delta with P50 is not equal
This is modelled by using Swanson’s mean:
Pmean = 0.3*P *P *P90

30. Example of Distribution Skew (BL)

31. Example of Lowering Pmean (BL)
10% of the time, a two-string casing design worked which resulted in a lower suspended cost
Otherwise, much money was spent fighting to maintain well control, often requiring a third string
By committing to a conservative 3-string design, the P90 was significantly reduced
The resulting Pmean pointed to always use the conservative 3- string design

32. Data Sources The biggest difficulty is getting good data
Pore pressures
Actual pressure measurements (production, kicks, DST, etc.)
Log data (resistivity, conductivity, acoustic)
Known gradients in area
Fracture Pressures
Actual measurements (leak-off tests, frac tests)
Lost circulation problems
Some log data (acoustic)

33. Safety Margins Over-Balance Margin Fracture Margin Data uncertainty
Negative pressure (swab)
Fracture Margin
Data Uncertainty
Positive pressure surge (running DP and casing)
ECD (equivalent pressure)
Kick margin

34. Kick tolerance calculations (BL)
Show an example of 0.5 shoe
Show an example of 0.5 interval TD influence on the shoe
Show an example of 0.5 interval TD plus a given kick size density difference influence on the shoe
Show an example of solving for a “kick intensity” value for a given kick size honoring the pore pressure/fracture gradient window for the interval
Add slide to presentation and discussion section to manual
Not in manual. I’ve been using this slide JEB

35. Kick Tolerance Example (BL)
At 10,500’, 0.5 ppge is 273 psi
At 14,000’, 0.5 ppge is 364 psi
364 10,500’ is 0.67 ppge, with 14.8 ppg mud, that equals ppge, 0.2 ppge less than the frac gradient
Assuming a 20 bbl kick with 0.1 psi/ft gas gradient with 4-1/2” drillpipe in an 8-1/2” hole, the gas column is 400’ and the SICP is 631 psi
631 10,500’ is 1.16 ppge, with 14.8 ppg mud that equals ppge which exceeds the frac gradient
Solving for the kick size for 0.5 ppge intensity allows a 8 bbl kick without breaking down the shoe
Not in manual, I’ve been using this slide JEB

36. Well Barrier Philosophy (BL)
Well Life-Cycle Containment of Fluids and Pressure
Primary Barrier Definition—in contact with reservoir fluids/pressures, e.g. hydrostatic head of drilling fluid
Secondary Barrier Definition—last line of defense if the primary fails, e.g. BOP, wellhead or cement
Number of Barriers, ideally two for all operations
Testing of Well Barriers, ideally in the direction of flow

37. Well Barrier Elements (BL)

38. Well Barrier Philosophy (Basic/Foundation)
Create discussion on Well Barrier philosophy for inclusion in manual and add appropriate slides to presentation.
This will be a “dig deeper” that doesn’t exist elsewhere and the module on Well Barriers will be pointed to by other disciplines when required.

39. Precautions About Frac Pressure
“Fracture pressures” often come from a number of sources
They do not always measure the same thing
The most reliable point is “leak-off”. Once fracture has occurred, the “initial fracture” peak will never be achieved. The “fracture closure” point is repeatable, but conservative. You may set an unnecessary string of casing using it. All three are used, but the dominant choice is “leak-off”. “Stop pump” is variable from test to test and not indicative of rock strength. JEB

40. Formation Integrity Test Considerations (BL)
Formation integrity test of Well control Top 13 Facts
Rock has low tensile strength, but it still must be overcome in order to fracture a formation. Once fractured, it is fractured permanently; there is no tensile strength left in that area. It will always reopen at the same fracture but with less pressure than originally. The insitu stress field, which governs the closing pressure, now also governs the opening pressure and unlike the tensile strength of the rock it is independent of the orientation of the borehole. Unconsolidated formations have little or no tensile strength; naturally fractured formations have none. These formation fracture pressures are independent of borehole orientation and the fracture will open and close at the same pressure at all times. Summary: When a formation with tensile strength is fractured it has lost some fracture strength permanently; fracturing an unconsolidated formation does not generally weaken it .

41. Fracture Pressures Leak-off pressure is usually not the frac pressure*
Actual frac pressure depends on hole inclination*
Once fracture is initiated it will reopen at the fracture closure pressure which is lower than the initial fracture*
Fracture closure pressure is independent of inclination
Sands usually fracture at lower pressure than nearby shales
Rock has low tensile strength, but it still must be overcome in order to fracture a formation. Once fractured, it is fractured permanently; there is no tensile strength left in that area. It will always reopen at the same fracture but with less pressure than originally. The insitu stress field, which governs the closing pressure, now also governs the opening pressure and unlike the tensile strength of the rock it is independent of the orientation of the borehole. Unconsolidated formations have little or no tensile strength; naturally fractured formations have none. These formation fracture pressures are independent of borehole orientation and the fracture will open and close at the same pressure at all times. Summary: When a formation with tensile strength is fractured it has lost some fracture strength permanently; fracturing an unconsolidated formation does not generally weaken it .
* except in unconsolidated or naturally fractured formations

42. Formation Lithology Good Casing Seat Poor Casing Seat Impermeable
High fracture resistance
Examples – shales, nonporous carbonates
Poor Casing Seat
High permeability
Weak fracture resistance or unstable
Examples – unstable shales, permeable and unconsolidated sands, salt zones, etc.

43. Casing Seat Pressure Test
Seat Integrity Test (after drill out)
Test casing seat to equivalent pressure of maximum mud density to be used below
Formation Integrity Test (Open-hole)
Above test may suffice unless it is in a non-permeable zone (e.g. shale)
If a sand zone is below casing seat shale then may need to test sand zone too
Remember – sands generally fracture at lower pressures than adjacent shales
If the fracture fluid can enter the pore spaces the formation generally fractures at a lower pressure than an impermeable one because the fracture fluid pressure in the pore spaces give a mechanical advantage not seen if the pressure cannot get inside the formation.

44. Depth Selection Example
We will carry the last example forward into the following chapters to use for our design examples:
Conductor: ft
Surface Casing: 3,000 ft
Intermediate Casing: 10,500 ft
Production Casing: 14,000 ft
Depth ft
Frm Press ppg equiv
Mud Dens ppg
Frac Press ppg equiv
Kick Marg ppg equiv
Temp °F
8.4
8.5 — 74
3000
8.7
9.2
12.3
11.8
128
10,500
13.6
14.1
15.7
15.2
263
14,000
14.8
15.3
16.2
326

45. What We Learned? Determining factors for selecting casing depth
What are they?

46. Final Thought on Best Practice
We used pore pressures and fracture pressures to illustrate our procedure
Which is the better procedure?
Pore Pressures and Fracture Pressures
Local Experience
Why?
Local experience is almost always the better. Pore pressure and fracture pressures are usually approximate at best.