1. Running & Landing Casing
Casing Design Workshop

2. Chapter 8 Outline Handling Casing Transport to Location On Location
Communicate Design to Rig Supervisor
Pipe Measurements

3. Outline Cont. Running Casing Getting Pipe to Rig Floor Stabbing
Filling Casing
Makeup Torque
Thread Locking
Casing Handling Tools
Getting Casing to Bottom
Crossover Joints

4. Outline Cont. Landing Practices Wellhead Equipment for Casing
Freeze Point
Maximum Hanging Weight
Wellhead Equipment for Casing

5. Video Links for Cementing Casing & Centralizers
Cementing Offshore Drilling
Casing Centralizer Placement

6. Video Link for Running Casing
Running Casing Animation

7. Transport to Location Prevent damage Loading and unloading sequence
Thread protectors
Stripping
Secured with straps
Protection from environment
Unloading procedures
Stripping on pipe racks
Loading and unloading sequence
Get it correct

8. On Location Minimum movement or relocation
Drift for internal diameter & obstructions
Remove thread protectors and clean threads and protectors
Visually inspect threads
Lubricate threads with proper lubricant (especially offshore)
Reinstall protectors (depending on handling facilities and methods)
Do not set equipment on casing on pipe racks

9. Moving Casing to Rig Floor
Use safe handling methods
If thread protectors not reinstalled
Use rubber clamp-on protectors on pin
Do not use hooks in pipe ends
Do not allow casing to slide out of V-door
Pin must be protected at all times

10. Pipe Measurements Who is responsible for accurate casing measurements
Company representative ! Always!
Not the responsibility of the rig crew !
Joints should be numbered (paint marker)
Talley book should be orderly, neat, and systematic so errors are easily spotted
Double check the addition !
Chalk numbers wash off or rub off

11. Cross-over Joints Check all cross-over joints
Correct threads
Measure and mark with identification
Proprietary threads cut by licensed machine shop or manufacturer
Check the grade of the tube
Isolate to separate area or place in string in proper position
Always have redundant cross-over joints on location

12. ST&C to LT&C ST&C pin will make up in LT&C coupling
LT&C pin will not make up into an ST&C coupling
Use a dedicated cross-over joint
LT&C coupling as a cross-over ?
Avoid if possible
ST&C coupling often difficult to remove
May damage pin when removing ST&C coupling
Fortunately most casing sizes and types are now made in either ST&C or LT&C so this is not a common problem. But it still occurs occasionally. LT&C coupling as a cross-over has been common practice for many years, but is a bad practice unless it installed at a pipe facility with proper equipment. Never wait until it is the next joint in the running process as delays or damage could jeopardize getting the string to bottom.

13. Stabbing Casing Stabbing board Stabbing arm
Stable
Properly positioned
Stabbing arm
Guide on bottom of elevator to prevent damage
Wind can cause stabbing problems
Do not rush the stabbing procedure
Some proprietary connections require stabbing guides

14. Filling Casing Fill casing as it is run Verify fill visually
Large diameter pipe requires large capacity fill line
Self-fill and differential-fill float equipment
Can allow cuttings and other objects in casing and plug float equipment
Avoid when possible, and never use in unconsolidated formation environments
A plugged float is a disaster in cementing. If it occurs prior to cementing, significant measures in both time and expense will be required (including possibly perforating the casing to place the cement and holding pressure on the casing while the cement sets). If it plugs while cementing, the cement job is over. Remaining cement will have to be drilled out and possibly the casing will have to be perforated to perform additional cementing.
Avoiding circulating out large volumes of air is worth the time to fill the pipe, especially if you will properly size the line working with the rig contractor. Well control incidents have occurred from circulating out air pockets improperly. JEB

15. Make-up Torque Determine proper makeup torque for connections
Rig casing tong line at 90°to tong arm for proper torque reading
Use only approved thread lubricants on clean threads
Proper number of turns can also be measured

16. Thread Lubricant Apply to box, not pin Do not use DP or DC dope
Standard is API Modified
Proprietary threads – check manufacturer
Environmental Considerations
Special formulations available
Some threads specially coated for self lube
Friction factor – specified relative to API Mod, adjust make-up torque accordingly
Always check manufacturer’s recommendations on lubricant and torque for proprietary connection

17. Thread Locking
Prevents back-off of lower joints during drill-out of float equipment
Polymer compound
Used on bottom joints & float equipment
Inexpensive and easy to use
Lock mill end of connections?
In the event casing has to be pulled before reaching bottom?
Welding? (never on N80 or higher grade!)
Relying on mill end of connection to not back off is chancy. Better to thread lock mill end too – best done at a pipe facility beforehand.
Do not be concerned about the old rule of thumb, “Do not thread lock anything longer than can be stood back in the derrick.” If you have
To pull casing back out of the hole thread locked joints is the least of your problems (use heat to break down the polymer).

18. Casing Handling Tools Spider Elevator Sets on rig floor
Slip type (integral or manual removable)
Wrap-around (must open for each joint)
Elevator
Attached to traveling block bails
Slip type (always integral)
Wrap-around type (must open for each joint)

19. For first few joints only !
Manual Casing Slips
This is crucial to avoid a fishing job for a few joints of casing. JEB
For first few joints only !

20. Wrap-around Spider

21. Wrap-around Spider

22. 500 Ton Elevator

23. 1000 Ton Elevator

24. More Elevators
Internal Grip
350 ton

25. 1000 Ton Spider

26. Compact Spiders
Fit into rotary table bowl (with rotary drive bushing removed).

27. Compact Spider

28. Precautions
High capacity tools open very easily with light casing load
Care must be taken to prevent accidental opening
Some air systems prevent opening if the other component is already open
Good practice:
start string in hole with low capacity tools
switch to high capacity once there is sufficient casing weight to prevent accidental opening
The casing seat before going into open-hole is often used as a place to swap out low-capacity for high-capacity equipment. JEB

29. Getting to Bottom If casing stops before reaching bottom
Circulate? Will that cause differential sticking?
Pull out and lay down casing?
Thread damage when pulling out?
Locked threads?
Have a contingency plan before starting in hole
If casing stops close to bottom ?
check pipe measurements
If you’re 40’ or 80’ off-bottom, you likely are off on your joint count. Check the location thoroughly. JEB

30. Highly Deviated Wells
Pipe beyond a critical inclination point (70°) must be pushed in hole
Friction calculations are essential before running pipe
Hook load decreases as casing nears bottom
crit  70
force required
This also appears in cased-hole sections along with open-hole. Cuttings can accumulate in the cased hole portions between degrees. JEB

31. Reducing Friction Increase Lubricity (reduce m )
Oil muds
Special additives
Plastic beads
Calcium carbonate
Graphite
Etc.
Reduce Contact Force (reduce N )
Lighter casing below critical angle
Good centralizers
Float portion of casing (ERD wells)

32. Pressure Containment Annular BOP Install proper size rams Test rams !
OK for some very low pressure applications
Not sufficient for most applications
Install proper size rams
Test rams !

33. BOP Rams Must Fit Casing !
This was one of the first oil-field photos to “go viral”. You don’t want to have the incident that gets global “viral” attention. JEB

34. Landing Practices (Slip-type Hangers)
How much string weight should be applied to casing hanger?
No standard practice
Probably as many practices as there are companies
Considerations:
Prevent buckling above freeze point to reduce casing wear
Prevent buckling in un-cemented areas; can cause failure

35. Freeze Point ? A point at which the pipe is fixed down hole
Usually taken to be the top of cement
Actual freeze point is never known

36. Neutral Point ?
The point at which the “effective” axial load goes from tension to compression
Not known, can be estimated from calculations
This is not the same point as the neutral point as defined on the true axial loads which has no meaning for buckling

37. Common Landing Practices
Same load on hanger as hook load
Tension in all casing above freeze point
Neutral point at the freeze point
Some percentage of hook load on hanger (e.g. 80%, 75% etc.) Why?
Hanging weight sometimes reduced to avoid too much compression load on top of conductor/surface pipe.
No choices for mandrel type hangers

38. Slip Type Hangers

39. Maximum Hanging Weight
Weight of the casing on slip type hangers causes radial compressive stress on the casing: verify that the hanging weight will not cause the casing to collapse.
Longer slip elements may be necessary

40. Maximum Hanging Weight
Safety factor? 2.0?
Taper of slip segment is measured from vertical
Compare result to the biaxial collapse rating of the casing
See example in Chapter 8
One company using this formula specifies a safety factor of 2

41. Example (Chapter 8)
From our continuing example the 7” production casing has the following data:
Buoyed casing string weight at surface: 340,000 lb
Type of 7” casing at surface: 29 lb/ft, P-110, Collapse rating: psi
Hanger taper: 25° Hanger slip length: 10 in.
Using a safety factor of 2.0, determine if the entire buoyed weight of the string can be hung on a hanger
The biaxial collapse rating of the casing with 340,000 lb tension is calculated from the formulas of the previous chapter and is: 8090 psi
Well below the reduced collapse value of 8090 psi with a safety factor of 2.0

42. Wellhead Equipment Casing Heads Casing Spools Casing Hangers
Slip-on Weld
Threaded
Casing Spools
Casing Hangers
Slip type
Mandrel type
Precautions

43. Video Clip on Wellhead Equipment
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Well Completion : Casing Head
Optional:
Wellhead instillation.wmv

44. Casing Head – Slip-on Weld
Conductor is cut off, surface casing is cut off and head welded to surface casing
Most popular
Requires cutting & welding
May include a base plate to weld to conductor instead of surface casing

45. Casing Head - Threaded
Landing joint & coupling removed and head threaded onto pipe
Coupling spacing critical
Coupling removal problems
Requires cement to surface
Possible slumping problem with poor cement

46. Casing Spool For additional strings of casing
Spool body pressure rating and lower flange are compatible to the casing string below the spool
Upper flange is rated to be compatible with casing string that will hang in the spool

47. Casing Hanger – Slip Type
Installed on casing above head and slipped into bowl
Often requires BOP removal
Allows adjustment of hanging tension
Requires cutting casing

48. Dangers of Slip Type Hangers
Removal of BOP to install hanger/pack-off or to weld hanger is always a hazardous operation because of potential gas migration.

49. Casing Hanger – Mandrel Type
Threads onto casing and landing joint and lowered into head prior to cementing
Simple, no moving parts
Cannot adjust landing tension
Reciprocate during cementing? NO!
One-piece types (surface applications only)
Circulate cementing returns through casing head side outlet
Fluted types (subsea applications)
Pack-off and locking device must be installed before hanger is in safe mode

50. Two-Piece Mandrel Type
Attached to casing
Run on landing joint w/run tool
Usually fluted with separate pack-off for cementing
Mandrel type (fluted) is only choice for subsea

51. Precautions Valves required on side outlets
Pressure gage required on each head or spool
Maximum service pressure (MSP) and test pressure
Never use the test pressure for selection
Use only MSP in selection

52. Running and Landing Practices
Running casing is intense and non-stop
Correct measurements are crucial
Install and test proper BOP rams
Assume that operations cannot stop once begun
Everything ready and functioning before start
Have contingency plans
Precautions for slip-type hangers
Set hanger without removing BOP if possible
Allow adequate cement setting time before removing BOP
Check for any flow before removing BOP
Never assume a slight flow is heat expansion