1. Oil-Field Hydraulics Chapter 8 Shut-in Procedures
PTRT 1321
Oil-Field Hydraulics
Chapter 8
Shut-in Procedures

2. Introduction Serve several purposes A few abbreviations
Stop the influx of formation fluid into the well bore
Protect the crew and rig
Provide an opportunity to organize and plan the kill procedure
Allow shut-in work string and casing pressures to be determined
A few abbreviations
Shut-in drill pipe pressure – SIDPP
Shut-in tubing pressure – SITP
Shut-in work string pressure – SIWSP
In this book the term SITP is used for all three

3. Introduction (cont)
IF well casing is set and adequately cemented in competent formation, usually the well can be shut in safely when a kick occurs
Shut-in procedures differ whether or not the work string is near bottom
Off shore procedures are listed but we will not discuss them here

4. Shut-in Procedure - I Surface BOP stack - Typical on land rigs
Fluid is being circulated
Work string is at bottom
Several different procedures are possible
Important that everyone involved knows ahead of time which procedures will be used
Example procedure uses a soft shut-in
Flow line through choke open
Then shut in well

5. Shut-in Procedure - I Stop rotating – sound alarm
Pick up work string far enough to ensure a tool joint or coupling is not in a ram BOP (if lower kelly cock is present make sure it clears the rotary table)
Stop the pumps
Check for flow
If well flows open the choke-manifold valve to allow flow to pit
Close the BOP (usually the annular preventer)
Close the choke slowly while watching casing pressure. (What to do if MASP is exceeded should already have been discussed and decided.)
When the choke is closed allow a few minutes then record the SITP.
Record SICP
Record the pit-level increase

6. Shut-in Procedure - II Surface BOP stack - Typical on land rigs
Fluid is NOT being circulated
Work string is OFF bottom
Several different procedures are possible
Important that everyone involved knows ahead of time which procedures will be used
Example procedure uses a soft shut-in
Flow line through choke open
Then shut in well

7. Shut-in Procedure - II Set the work string on slips – sound alarm
Install and make up a full-opening safety valve in the work string (valve should be in the open position)
Close the work string safety valve
Open the choke-manifold valve to allow flow to pit
Close the BOP (usually the annular preventer)
Close the choke slowly while watching casing pressure. (What to do if MASP is exceeded should already have been discussed and decided.)
Install an inside BOP and release the valve on the work string safety valve
Pick up and make up the kelly
Open the work string safety valve
Start the pump and open the inside BOP by increasing pressure slowly in ¼ bbl increments (pressure should be linear with volume)
With the inside BOP open, record the SITP.
Record SICP
Record the pit-level increase

8. Hard and Soft Shut-in Procedures
Often depends on the preference of the operator
Hard shut in means closing the BOP without first opening the alternate flow path through the choke line
Hard shut in keeps the kick influx to a minimum and simplifies the procedures
Increases the likelihood of formation break down
Soft shut in is the reverse

9. Hard Shut-in
Choke and the remote choke-manifold (HCR), or failsafe, valves are set closed during normal operations
When a kick occurs
Close the preventer (adjust closing pressure as needed)
Open the HCR (or fail-safe valves)
Allow pressure to stabilize and then record SITP and SICP
Read and record the pit-level increase
Casing pressure cannot always be recorded because the choke-line valves are closed. May result in MASP being exceeded without operator knowledge
Hard shut in does NOT cause hydraulic hammer and damage to the well bore even if gas is in the kick fluids

10. Soft Shut-in Choke is set full open during normal operations
When a kick occurs
Open the HCR (or fail-safe valves)
Close the annular preventer
Close the drilling choke
Adjust closing pressure on BOP
Allow pressure to stabilize and then record SITP and SICP
Read and record the pit-level increase
More steps and more time
Preferred to hard shut in by some due to inability to read SICP

11. Kick Fluid Density and SICP
Generally best to assume that the kick consists of gas
Gas = 1.5 ppg to 3.0 ppg
Oil = 5.0 ppg to 7.0 ppg
Saltwater = 8.6 ppg to 10.0 ppg
If the well is shut in on a gas kick SICP is generally greater that a saltwater kick of equal volume
Where:
SICP = shut-in casing pressure
FP = formation pressure
HP = hydrostatic pressure from top of kick to surface
Pf = pressure of the kick fluid

12. Example: TVD = 13,750 ft Circulating fluid weight of 12.0 ppg
Annular volume = bbl/ft
Formation pressure = 9,180 psi
A 30 bbl kick occurs with gas having weight of 2.15 ppg
Example:
Pressure gradient of circulating fluid
Fluid rise from kick
Hydrostatic pressure of remaining fluid
Pressure gradient of kick fluid
Hydrostatic pressure of kick fluid

13. Difference between gas and saltwater kicks
As gas rises to surface it must expand as pressure decreases
SICP increases
Pit level increases
Saltwater does not expand as it comes to the surface
No appreciable pit level or SICP increase

14. Density estimate for kick fluids
Where:
Di = density of influx, ppg
FW = original fluid weight, ppg
SICP = shut-in casing pressure, psi
SITP = shut-in tubing pressure, psi
L = height of influx in the annulus, ft

15. Example: Circulating fluid weight = 9.6 ppg
SITP = 400 psi, SICP = 700 psi
Pit gain is 15 bbl (volume of the kick)
Annular volume = bbl/ft
Example:
Fluid rise from kick
Fluid weight after influx
Density of kick fluid

16. SITP = 400 psi
SICP = 700 psi
9.6 ppg
8.89 ppg
649 ft
0.71 ppg