This document provides an overview of basic well control procedures including: - Kick detection and control methods like primary prevention and secondary detection and control - Shut-in procedures such as hard, soft, and specialized shut-ins - Well kill procedures including calculating initial and final circulating pressures, the wait-and-weight/engineer's method, and providing an example pump schedule. It describes the key objectives and considerations for safely controlling a well when kicks occur and bringing the well pressure to a controlled state.

1. 8. BASIC WELL CONTROL
Habiburrohman abdullah 1

2. Basic Well Control
• Origin of overpressure
• Kick recognition
• Shut-in procedure
• Kill Procedure
2

3. Kick Detection and Control
• Primary well control involves efforts at
preventing formation fluid influx into the
wellbore.
• Secondary well control involves detecting an
influx and bringing it to the surface safely.
3

4. Basic Well Control
Two primary objectives:
1. To kill the well safely
2. To minimize borehole stresses
4

5. Blow Out Preventer (BOP)
5

6. Successful Well Control
• Keep the BHP constant throughout using the
choke.
6

7. Slow Pump Rate
• The pump rate at which the system pressure
loss is recorded for purposes of well control is
called the slow pump rate, slow pump
pressure, kill rate, or reduced circulating
pressure
• Also called slow pump rate, slow pump
pressure, kill rate, reduced circulating
pressure or slow circulating rate
7

8. Slow Pump Rate: When To Take
• Every tour
• After repairing the pumps or when the liner is
changed
• When the mud properties are changed
• Every 500 ft of new hole drilled
• BHA changes
• When the bit nozzles are changed
8

9. SIDPP
• Shut-in DP Pressure is the measure of the
difference between the formation pressure
and the hydrostatic column of the mud in the
drillstring.
• Gives a direct reading of the formation
pressure
9

10. Formation Pressure / Kill MW
• FP (ppg) = (SIDPP / (0.0519 x TVD)) +
Original MW
• BHP = ((SIDPP x 19.23) / TVD) + Original
MW
10

11. SICP
• Shut-in Casing Pressure is the measure
of the difference between the formation
pressure and the hydrostatic column of
the fluids in the annulus during a kick.
• Not an good indicator of the formation
pressure.
FP = HPmud + HPkick + SICP
11

12. Pressure at the Casing Shoe
• Pcsg = SICP + 0.052 x MW x Casing
shoe TVD
12

13. U Tube
Annulus side
Kick
DP side
SIDPP + HPmud =
SICP + HPmud + HPkick =
Fm Pressure
13

14. Materials to Weight Up Mud
• Barite
• Ilmenite
• Fe oxide (Hematite)
• Galena
14

15. Materials to Weight Up
Completion Fluids
• KCl
• NaCl
• CaCl2
• CaBr2
• ZnBr
15

16. Barite
• The amount of barite necessary to increase
the MW to the kill MW is:
Sx/100 bbl mud = 1490 x ((Kill MW – Old
MW)/(35.8 – Kill MW) Or
100-lb sx of barite = (Mud vol x 14.7 x (KMW
– OMW)) / (35 – KMW)
• The volume of increase caused by weighting
up:
(100 x (Kill MW – MW)) / (35.8 – Kill MW) Or
Vol incr = sx of Barite / 14.7
16

17. Shut-In Procedures
• Hard shut-in
• Soft shut-in
• Shut-in while tripping
• Shut-in with diverter in use
• Shut-in while running casing
17

18. Hard Shut-in
• Assure beforehand the choke manifold line is
open to preferred choke and choke is in
closed position.
• After a kick is indicated, pick up the string and
position tool joint above rotary table.
• Shut off pump.
• Flow check.
• If flow is verified, shut the well in by closing
the BOP using annular preventer.
• Open the HCR valve (hydraulically controlled
remote valve) to the choke manifold. 18

19. Hard Shut-in
• Close the choke if open.
• Notify supervisor (company drilling
supervisor, toolpusher or rig manager).
• Read and record SIDPP, SICP, pit gain, TVD
and time.
• Rotate the drillstring through the closed
annular preventer if feasible.
• Prepare to implement kill procedures.
19

20. Soft Shut-in
• Assure beforehand choke manifold line is
open to preferred choke and choke in in open
position.
• After kick is indicated, pick up string &
position tool joint above rotary table.
• Shut off pump.
• Flow check.
• If flow is verified, open the HCR.
• Close the BOP using the annular preventer.
20

21. Soft Shut-in
• Close the choke if open.
• Notify supervisor (company drilling
supervisor, toolpusher, rig manager).
• Read and record SIDPP, SICP, pit gain, TVD
and time.
• Rotate the drillstring through the closed
annular preventer if feasible.
• Prepare to implement kill procedures.
21

22. Shut-in While Tripping
• Set the slips below the tool joint.
• Stab a full opening valve (TIW) and close it.
• Open the HCR and close the BOPs and
choke.
• Pick up and stab the kelly/TDS or pump-in
line.
• Open the safety valve.
• Notify the supervisors.
• Read and record SIDPP, SICP, pit gain, TVD
of the well, TVD of the bit and time.
• Prepare to implement kill procedures. 22

23. Shut-in with Diverters in Use
• When a shallow kick occurs a full opening
diverter valve is opened to divert the flow
away from the rig.
• The low pressure annular is then closed.
23

24. Shut-in While Running Casing
• Lower the casing until the swage and a valve
can be stabbed.
• Close the casing rams or annular preventer.
• Stab the swage and valve.
• Notify the supervisors.
• Read and record the pressures, TVDs, pit
gain and time.
• Prepare to implement kill procedures.
24

25. Well Kill Procedures
• Kill equations
• 3 Major Kill Procedures
• Other Kill Procedures
25

26. Initial Circulating Pressure (ICP)
• ICP = system pressure loss at kill rate +
SIDPP
Note:
• When we start to circulate, the DP will increase due to the
friction loss and the pressured drop across the bit.
• BHP = HSPDP + Circulating DPP – DP press loss
• In order to utilize the DP gauge we have to know the DP press
loss. The DP press loss = SPP
• Circulating DPP = BHP – HSPDP + SPP
• Since SIDPP =BHP – HSPDP
• Circ DPP = SIDPP + SPP 26

27. Final Circulating Pressure (FCP)
• FCP = System pressure loss x (Kill MW/Old
MW)
• Note:
• As the KMW is circulated through the bit the circ DP Press will
decrease until the KMW will reach the bit. At the bit the SIDPP
will be zero. The circ DP pressure with the KMW at the bit is the
FCP.
27

28. ICP and FCP Relationship
• In a vertical well the circulating drillpipe
pressure will decrease linearly from the ICP
to the FCP.
28

29. Major Kill Procedures
• Engineer’s or Wait and Weight Method
• Driller’s or Two Circulation Method
• Concurrent or Circulate and Weight Method
29

30. Introduction To Kick Killing
Procedures
• Introduction
The purpose of any well kill procedure is to maintain the BHP constant at a level
equal to or slightly greater than the FP. Since the drill pipe pressure is a direct
bottom hole pressure indicator, the drill pipe pressure can be manipulated in a
systematic manner, and the well can be controlled.
• There are three well kill procedures in common usage. These are:
Wait and Weight Method – After the well is shut-in, the surface mud system is
weighted up to the required kill mud weight. The kill mud is then pumped and the
well is killed in one complete circulation. This method is also called the
Engineer’s or the One Circulation Method.
Driller’s Method – After the well is shut-in and the readings are recorded,
pumping is begun immediately. The influx is pumped from the wellbore without
any prior weighting up of the mud. Once the influx has been pumped from the
well, the well is shut-in, and the surface mud system is weighted up to the kill
mud weight. The lighter mud is then displaced by the kill mud. This method is
sometimes called the Two Circulation Method.
Concurrent Method – After the well is shut-in, pumping is begun immediately
and the mud weight is raised while the kick is being circulated out. The use of
this method may require several circulations before the well is fully killed. This
method is also called the Circulate and Weight Method. 30

31. Engineer’s Method: Procedure
1. Shut-in well and record SIDPP, SICP, pit gain
2. Compute kill MW and compute pump sked. Build kill mud
3. Hold casing press constant and bring pump to kill rate (DPP =
ICP)
4. Follow pump schedule when displacing DP. The choke
opening is varied as required to keep the drill pipe pressure
regulated.
5. Once DP filled, poss. to shut-in well, SIDPP = 0
6. Hold casing press constant using choke and bring pump to kill
rate, (DPP = FCP)
7. Hold at FCP until kill mud at surface
8. Shut down pumps, shut-in well. Check for remaining pressure.
9. If no more pressure, crack choke and FLC.
10. If no flow, open BOP. The well is dead.
31

32. 32
32

33. Pressure Schedule For Drillpipe
• Calculate the number of strokes required to
displace the drillpipe with the kill mud
• Calculate ICP and FCP
• Plot the mud volume (bbls or strokes) along
the horizontal axis and the DP pressures
along the vertical axis
• The plot can be completed by plotting the ICP
at 0 strokes and connecting it to the FCP at
the number of strokes required to displace
the drill pipe.
33

34. Pump Schedule: Problem 1
• Assume the following:
– SIDPP = 500 psi
– Kill rate pressure = 1000 psi
– Original MW = 10 ppg
– Kill MW = 11 ppg
– Strokes to displace DP = 500 strokes
• Problem: Fill in the drill pipe pressure
schedule.
34

35. Pump Schedule: Problem 1
35
Strokes Pumped DP Pressure
0
100
200
300
400
500

36. Pump Schedule: Solution
• ICP = Kill rate pressure + SIDPP
– ICP = 1000 psi + 500 psi = 1500 psi at 0
strokes
• FCP = (Kill rate pressure x Kill MW) /
Original MW
– FCP = (1000 psi x 11 ppg) / 10 ppg = 1100
psi after 500 strokes
36

37. Pump Schedule: Solution
37
Strokes Pumped DP Pressure
0 1500
100
200
300
400
500 1100

38. Pump Schedule: Solution
• Drill pipe decrease per stroke = (ICP –
FCP) / Strokes to displace DP with kill
mud
– Drill pipe decrease per stroke = (1500 psi –
1100 psi) / 500 strokes = 0.8 psi /stroke
38

39. Pump Schedule: Solution
39
Strokes Pumped DP Pressure
0 1500
100 1420
200 1340
300 1260
400 1180
500 1100
Note: This method eliminates any errors that may occur as a result of reading drill
pipe pressures from a graph incorrectly.

40. Pump Schedule: Solution
2000
1900
1800
1700
1600
1500
1400
1300
1200
1100
• ICP = Kill rate pressure + SIDPP = 1000 psi + 500 psi = 1500 psi at 0 strokes
• FCP = (Kill rate pressure x Kill MW) / Original MW = (1000 psi x 11 ppg) / 10 ppg = 1100
psi after 500 strokes
• Plot 1500 psi at 0 strokes and plot 1100 psi at 500 strokes. Connect the two points.
40
DP Pressure Schedule
1000
0 100 200 300 400 500 600
Strokes Pumped
Pressure, psi

41. Driller’s Method
• TWO complete circulations
– Circulate kick out of hole using old
mud
– Circulate old mud out of hole using
kill weight mud
41

42. Driller’s Method: Procedure
1. Shut-in well and record SIDPP, SICP, pit gain
2. Compute kill MW
3. Hold choke pressure constant and pump at kill rate
4. Hold DP pressure steady at ICP until kick out of
hole
5. Shut-in well and build kill MW
6. Hold casing pressure steady and pump at kill rate
7. DP pressure is allowed to decline as per pump
sked. Once DP full, observe FCP
8. Keep pumping at kill rate and constant FCP until kill
mud at surface.
9. Shut down pumps, shut-in well. Check for remaining
pressure.
10. If no more pressure, crack choke and FLC.
11. If no flow, open BOP. The well is dead.
42

43. Concurrent Method: Procedure
1. Shut-in well using preferred shut-in
procedure and record the SIDPP, SICP and
the amount of pit gain
2. Hold casing press constant and bring pump
to kill rate (DPP = ICP)
3. Follow schedule when displacing DP
4. Once DP filled, shut-in well, SIDPP = 0
5. Hold casing press constant and bring pump
to kill rate, (DPP = FCP)
6. Hold at FCP until kill mud at surface
7. Shut down pumps, shut-in well, check if well
is dead
8. If not repeat steps 2 to 9. 43

44. Major Kill Procedures: Conclusion
• The Wait and Weight Method using the
proper kill weight results in the least
amount of casing pressure and the
least borehole stresses.
• The Concurrent Method allows lower
casing pressure values than the Driller’s
Method.
• Overkilling the well has no tangible
benefit.
44

45. Other Calculations
• Height of the Influx
• Identification of Influx
• Choke Line Friction (CLFP)
• MASCP
45

46. Height Of Influx
• Pit level gain < ann. vol. around the DC:
Length of kick, ft = kick volume (bbls) /
((Hole ID2 – DCOD2) x 0.000971)
• Pit level gain > ann. vol. around the DC:
Length of kick, ft = Length of DC +
((kick volume – DC ann. vol.) / ((Hole
ID2 – DPCOD2) x 0.000971))
46

47. Identification Of Influx Density
• Influx Density, ppg = MW, ppg – ((SICP-SIDPP)/(
Height of influx, ft x 0.0519))
Note:
• The influx may either be gas, oil, water or a combination of the three. The
calculation is an approximation at best because the hole may not be gauge and
the pit gain may not be necessarily accurately noted.
• The formula for determining the gradient of the influx fluid is:
Influx gradient = Mud gradient in DP– ((SICP-SIDPP)/Height of influx)
Height of influx = bbls gained / annulus volume, bbls/ft
Influx density (ppg) = Influx gradient / 0.52
• As a general rule, an influx with an equivalent mud weight of 1 to 3 ppg is
assumed to be gas, 3 to 5 ppg is assumed to be a mixture of gas and water or
gas and oil, and 5 to 7 ppg is assumed to be either oil, water or an oil-water
mixture. 47

48. Identification Of Influx
As a general rule:
• 1 to 3 ppg EMW is assumed to be gas
• 3 to 5 ppg EMW is assumed to be a
mixture of gas and water or gas and oil
• 5 to 7 ppg EMW is assumed to be
either oil, water or an oil-water mixture
48

49. Influx Identification: Problem 1
• Identify the type of influx assuming the
following:
–TVD = 10000 ft
–MW in DP = 12 ppg
–Hole ID = 9.875 in
–DP OD = 5 in
– SIDPP = 520 psi
– SICP = 650 psi
– Pit Gain = 40 bbls 49

50. Influx Identification: Solution
• Mud gradient = 12 ppg x .052 = 0.624
psi/ft
• Annulus volume, bbl/ft = ((9.875)2 – (5)2)
/ 1029 = 0.70 bbls/ft
• Length of influx, ft = 40 bbls / 0.70
bbls/ft = 571 ft
50

51. Influx Identification: Solution
• Gradient of influx, psi/ft:
• = 0.624 psi/ft –((650 psi – 520 psi) / 571 ft)
• = 0.624 psi/ft – (130 psi/571 ft)
• = 0.624 psi/ft – 0.228 psi/ft = 0.396 psi/ft
• Influx density, ppg = 0.396 psi/ft / .052 = 7.61
ppg
• The influx would probably be oil or water. The
comparatively high weight means that not
much gas is associated within the influx.
51

52. Choke Line Friction (CLFP)
• Used to determine the amount by which
the casing pressure is to be adjusted to
maintain BHP = FP when starting the
pumps on a kill operation. We reduce
the SICP by the amount of CLFP to
make allowances for the back pressure
imposed by the CLFP.
52

53. Maximum Allowable Shut-in Casing
Pressure
• Surface pressure acting ontop of the current
hydrostatic pressure that will exceed the
measured fracture pressure at the casing
seat.
• MASCP = 0.0519 x (FGmin – MW) x Dwf
• Where,
MASCP = psi
FGmin = Fracture Gradient of weakest formation, ppg
MW = ppg
Dwf = TVD of weakest formation
53

54. END
54