This document provides an overview of well control procedures. It discusses causes of kicks such as swabbing or pumping light mud that can lead to underbalance. Primary well control relies on mud hydrostatic pressure, while secondary control uses a blowout preventer. Tertiary control involves pumping substances to stop downhole flow. Methods for killing a well are also presented, including the driller's method, wait and weight, volumetric, and bullheading. Kick detection equipment like the pit volume totalizer and flow indicator are also outlined.

1. Click to edit Master subtitle style
Well Control
AAPG SU SC
Check every slide as some slides may include nether notes.

2. Outline
 Introduction
 Causes of Kicks
 Primary, Secondary and Tertiary well control
 Blowout Preventer stack
 Kick Detection Equipment
 killing a well

3. Outline
 Introduction
 Causes of Kicks
 Primary, Secondary and Tertiary well control
 Blowout Preventer stack
 Kick Detection Equipment
 killing a well

4. Introduction
Well control is the procedure of maintaining pressure on open
formation (that is exposed to the wellbore) to prevent or direct the
flow of formation fluids into the wellbore.
Or it’s to avoid this situation

5. • Overbalance
Mud Hydrostatic Pressure > Formation Pressure
• Underbalance
Mud Hydrostatic Pressure < Formation Pressure (Possible Kick!)
Introduction (cont.)

6. Outline
 Introduction
Causes of Kicks
 Primary, Secondary and Tertiary well control
 Blowout Preventer stack
 Kick Detection Equipment
 killing a well

7. Blowout
 Kicks:
• Any influx of formation fluids (oil, gas or water) in
the borehole is known as a kick.
• When a kick is taken, primary control
has been lost.
• An uncontrolled kick at the surface is called a
blowout.
Causes of Kicks
Kick

8. Kicks occur when “underbalance is found”
Underbalance is caused by :
• Increase in Formation Pressure.
• Mud Hydrostatic Reduction.
Causes of Kicks (cont.)

9. What causes Mud Hydrostatic to drop?
Pressure = Mud Wt X Constant X TVD
Reduce mud weight Reduce length
of mud column
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? ?
? ?
Causes of Kicks (cont.)

10. 1- Running into bubbles
Causes of Kicks (cont.)

11. 2- Circulating hole clean
Causes of Kicks (cont.)

12. 3- Swabbing
Causes of Kicks (cont.)

13. 4- Pumping Light Mud
Causes of Kicks (cont.)
Bottom Hole Pressures
psi

14. 5- Loss of Barite
Causes of Kicks (cont.)
Pit Hole

15. 6- Lost circulation
Causes of Kicks (cont.)
Well Under Control
(Normal Condition)

16. 6- Lost circulation
Causes of Kicks (cont.)
Pressure Exert On
Upper Formation

17. 7- Pull Out of The Hole Dry
Causes of Kicks (cont.)
Rig Floor
Flowline

18. 8- Pull Out of The Hole Wet
Causes of Kicks (cont.)
Rig Floor
Flowline

19.  Kick Prevention
Causes of Kicks (cont.)
 Monitor trips; in and out.
 Circulate bottoms up if in doubt of hole condition.
 Monitor well at all times.
 Trip carefully in and out.
 Pump out if tight hole.
 Circulate through choke if a lot of gas is expected.
 Keep mud in good shape.
 Always keep hole full.
 Double check effect of lightweight mud/pills.
 Pump good cement.

20. Outline
 Introduction
 Causes of Kicks
 Primary, Secondary and Tertiary well control
 Blowout Preventer stack
 Kick Detection Equipment
 killing a well

21. Primary, Secondary and Tertiary well control
You must have an idea of primary, secondary and tertiary well
control and the equipment used to detect the kicks or any
other problem.
Primary Control
Mud Weight
Secondary Control
BOPs
Tertiary Control
Control &Recovery

22. Primary, Secondary and Tertiary well control (cont.)
The well control system is designed to:
1. Detect a kick
2. Close-in the well at surface
3. Remove the formation fluid which has flowed into the well
4. Make the well safe

23. 1- Primary well control
 Mud Hydrostatic Pressure:
Mud Hydrostatic Pressure > Formation Pressure

24. 2- Secondary well control
 BOP (Blowout Preventer)
 Secondary control is activated only
to restore the primary well control.

25. 3- Tertiary well control:
• Tertiary control involves pumping substances into the wellbore to try
to physically stop the flow down hole.
• This may involve pumping cement with a high risk of having to
abandon the well afterwards.
• However, there is another method that may be employed, called a
Barite Plug …

26. 3-Tertiary well control (cont.)
Barite Plug:
• A barite plug is set by mixing a heavy slurry of barite in water or
diesel oil. It has to be kept moving while mixing and pumping.
• Once the slurry is in position down hole and pumping stops, the
barite rapidly settles out to form an impermeable mass that will
hopefully stop the flow of formation fluid.

27. Outline
 Introduction
 Causes of Kicks
Primary, Secondary and Tertiary well control
 Blowout Preventer stack
 Kick Detection Equipment
 killing a well

28. Blowout Preventer stack
The primary function of the BOP is to form
a rapid and reliable seal around the drill
string or across the empty hole, so as to
control down hole pressures.
Note: it is installed after the surface casing,
before this a diverter is installed.

29. Blowout Preventer stack (cont.)
There are two types of preventers:
1. Bag-type preventer (or annular preventer):
• Contains a large rubber seal, which is circular if
viewed from above and conical if viewed from the
side. This is held inside a steel chamber.
• Below the rubber element is a hydraulically operated
piston with a matching conical shape on top to fit the
rubber underside.

30. Blowout Preventer stack (cont.)
2. Ram-type preventer:
• The other type of preventer uses a pair of large steel rams that shut under
high hydraulic pressure, with great force.
• These rams are interchangeable and are of different types:
Fixed pipe ram
Variable bore pipe ram
Blind rams
Shear rams
Blind-Shear rams
Casing shear rams

31. • Normally, a BOP stack would have at least one bag preventer and two
ram preventers.
• Stacks for deeper wells might have up to four ram preventers and two
annular preventers.
• The ram preventers generally have a higher pressure rating and are
always installed below the bag preventers.
• If only two ram preventers are used, the bottom set will normally be
blind-shear rams, and the upper set will be pipe rams.
• One reason for placing the blind rams on the bottom is that if the
pipe rams or annular leaks, it is possible to close the blind rams below
and fix the leak above.
Blowout Preventer stack (cont.)

32.  Choke Valves:
Below the rams are pipes that come out to the side. These
are called side outlets and are used to allow flow out of or
into the annulus during well killing operations.
Blowout Preventer stack (cont.)

33.  BOP Control System:
also known as the Accumulator or
the Koomey Unit
Energy stored in this unit to operate
the BOP
A reserve hydraulic fluid tank
A set of cylinders holding fluid under
high pressure
Two manifolds
Blowout Preventer stack (cont.)

34.  BOP Control System:
Two pressure regulator that feeds fluid
 From high pressure to low
 From low pressure to high
A set of valves
A valve
 controls the opening and closing of the bag preventer
Two sets of pumps to maintain system pressure
Blowout Preventer stack (cont.)

35.  Subsea BOP systems:
• attached to the top of the surface casing
at the seabed.
• contains extra control systems when
compared to a surface BOP.
Blowout Preventer stack (cont.)

36. Outline
 Introduction
 Causes of Kicks
 Primary, Secondary and Tertiary well control
 Blowout Preventer stack
 Kick Detection Equipment
 killing a well

37. Kick Detection Equipment
There are two main kick detection systems that give a direct indication
of a kick:
1. Pit volume totalizer
2. Flow indicator

38. Kick Detection Equipment (cont.)
 The pit volume totalizer PVT:
• It provides a readout showing the
total volume of drilling fluid held on
the surface.
• If this total increases, and the
increase is not due to the mud
engineer adding chemicals or fresh
mud to the system, a kick is
occurring.

39.  The flow indicator:
• This system consists of an instrument
attached to a paddle that sits in the flow
line from the annulus. This paddle is
pushed up by the returning mud stream. If
the flow rate increases, an alarm will
sound.
• However, the paddle-type flow indicator is
prone to false alarms because of cuttings
and other debris that may stick to the
paddle or build up underneath it.
Kick Detection Equipment (cont.)

40.  Kick Warning Signs
1.ROP changes
• Less overbalance
• Softer rock
2.Hole condition
• Squeezing rock
• Torque / Drag / Fill
3.Data from Mud
• Gas
• Cuttings
• Temperature
Kick Warning Signs & Indicators
• Chlorides
• Shale Property
• Trip Monitor
Nocked
or packed off cutting
Drilled cuttings

41. Major Warning Signs:
• Improper fill up or displacement during trips
• Connection gas
• Increased background gas
• Increased drilling rate ( known as Drilling Break or Fast Break)
• Flowline mud temperature increase
• Increased chloride content of mud
• Increased drill string torque
• Increased drill string drag
• Increased number and size of cuttings
• Decreasing shale density
Kick Warning Signs & Indicators (cont.)

42.  Surface Kick Indicators
• Excess flow from the well when tripping
• Return flow rate increase when pumping
• Pit gain
• Flow from well with pumps off
Kick Warning Signs & Indicators (cont.)

43. Outline
 Introduction
 Causes of Kicks
 Primary, Secondary and Tertiary well control
 Blowout Preventer stack
 Kick Detection Equipment
killing a well

44. Killing a well
First, how to shut-in the well:
 Reason for Shut In:
1- To prevent blowout.
2- To allow pressure reading to be taken for
kill mud
 Shut In Methods
1. Hard (Drilling / Trapping)
2. Soft (Drilling / Trapping)
Hard Vs.
- Quicker
- Less to Remember
- Smaller Influx
Soft
- Slower & Reduces Water Hammer Effect
- Checks if choke line is Clean
- Larger Influx

45. Killing a well (cont.)
Simplifying the Initial Phase of Killing the well
Driller’s Method Wait and Weight
Volumetric Bullheading

46. A- The Driller’s Method:
 The Driller`s method is one of the oldest well killing methods and it was
developed for shallow vertical wells.
 As time moved on, wells got deeper and went from vertical into more
inclined pathways.
 The method got further developed to overcome the new challenges
related to deviated well paths.
Killing a well (cont.)

47. A- The Driller’s Method Procedure:
 Removing Kick:
1. Kick detection
2. Stop mud pumps and rotation of the drill string rotation
3. Close the BOP
4. Monitor the shut-in pressure until it levels out – the wellbore
pressure is equal to formation pressure
5. Then open choke line and circulate the kick out through the choke
line to the separator/flare
Killing a well (cont.)

48. A- The Driller’s Method Procedure:
Another option is to reverse kill or bullhead, this is done by forcing the
kick back into the formation again.
Killing a well (cont.)

49. SIDPP
SICP
0
psi
psi
0
Mud PumpA- The Driller’s Method Procedure:
- Two Circulation's:
1st Clean Out Influx
2nd Circulate Kill Mud
- After 1st Circulation
SIDPP = SICP
Killing a well (cont.)
First CirculationSecond Circulation

50. B- Wait and Weight Method
•The Wait and Weight method kills the kick faster and keeps wellbore
and surface pressures lower than any other method.
•Requires good mixing facilities, full crews, and more supervision than
most other methods.
•Fluid weight is increased before circulation begins, hence the name
Wait and Weight.
Killing a well (cont.)

51. B- Wait and Weight Method Procedures:
1. Shut-in well after kick.
2. Record kick size and stabilize SIDPP and SICP, calculate kill fluid
density.
3. Pits are weighted up as other calculations are performed.
4. Once pits are weighted, start circulating kill weight fluid by
gradually bringing up the pump up to the kill rate while using the
choke to maintain constant casing pressure at the shut-in value.
 Remember to hold pump rate constant.
Killing a well (cont.)

52. B- Wait and Weight Method Procedures:
5. Follow pressure chart/graph as kill fluid is pumped down the string
to bit.
6. Once kill fluid is at the bit/end of string, FCP should be realized.
7. Maintain constant FCP circulating pressure until the kill fluid
completely fills the well.
8. Shut down pump and check for flow, Close choke and check
pressures.
9. If no pressure is noted, open choke , open BOP.
Killing a well (cont.)

53. 0 psi
0
Mud Pump
psiCasing
Pressure
Drillpipe
Pressure
B- Wait and Weight Method Procedures:
- One Circulation
- Pump kill mud from the start
Killing a well (cont.)

54. C- Volumetric Method :
• The volumetric method is a way of allowing controlled expansion of
gas during migration.
• The Volumetric method is based on the assumption that the influx is
gas that migrates upwards in the well. It cannot be used if the influx
fluid is either salt water or oil.
Killing a well (cont.)

55. C- Volumetric Method:
• The reasons for using this method instead of another kill method are based
on different variables in the well. Some of them are listed below:
1. If there are no drill string in the well
2. If the drill bit or the drill string has been plugged with some kind of
debris
3. Hole collapse can be a reason – this prevents circulation
4. If there has been a power failure and mud pumps along with
emergency pumps are down
5. If there is a long way between drill string and bottom of the well
6. Not able to circulate due to drill string has been cut and dropped
into the well
Killing a well (cont.)

56. C- Volumetric Method Procedures:
• In this method the choke is opened and closed in steps to bleed of the
inflow gas. It is performed by staying within the designated pore and
fracture pressures together with a safety margin.
• As gas moves up and pressure in the well increases, the choke is opened to
bleed off and reduce the well pressure and it is then closed when the
pressure drops to a certain level.
• This procedure is maintained until the gas is completely out of the well.
Killing a well (cont.)

57. D- Bullheading Method Procedures:
• Operators sometimes have to look at different alternatives to solve
critical well control problems. When conventional method of
circulating down the drill string and up the annulus no longer is an
option, an alternative is to use a technique called bullheading.
• This method is performed with the use of pumps in a closed in well,
the influx fluids are then pushed- and forced back down into the
weakest point of the exposed open hole interval.
Killing a well (cont.)

58. D- Bullheading Method Procedures:
• Bullheading is done by adding some pressure, in this way the wellbore
pressure gets overbalanced compared to the reservoir pressure and the
formation fluids are pushed back into the formation. The pressure
acting on the bottom during a bullheading operation is
PBH = Pres + Pover
PBH = Bottom hole pressure Pres = Reservoir pressure
Pover = Overpressure
Killing a well (cont.)

59. D- Bullheading Method Procedures:
• The over pressure is dependent to the reservoir properties
(permeability and porosity) and the influx concentration.
• The higher the properties in the reservoir are (high permeability and
porosity) the lower the overbalance pressure needs to be in order to
force the influx back into the formation.
Killing a well (cont.)