1. Well Control Principles
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2. Well Control Principles
Primary Well Control
Secondary Well Control
Tertiary Well Control
Hydrostatic Pressure
Formation Pressure
Porosity And Permeability
Kill Mud Density
Indications of Increasing Formation Pressure

3. Well Control Principles
The function of Well Control can be subdivided into 3 main categories:
Primary Well Control: is the use of the fluid to prevent the influx of formation fluid into the well bore.
Secondary Well Control: is the use of the BOP to control the well if Primary WC can not be maintained.
Tertiary Well Control: squeeze back, cement ...

4. when Hydrostatic Pressure = Formation Pressure
The Well is Balanced:
when Hydrostatic Pressure = Formation Pressure
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5. The Well is Under Balanced:
when Hydrostatic Pressure < Formation Pressure

6. The Well is Over Balanced:
when Hydrostatic Pressure > Formation Pressure

7. Hydrostatic Pressure
Because the pressure is measured in psi and depth is measured in feet, it is convenient to convert Mud Weight from ppg to a pressure gradient in psi/ft.
The conversion factor is 0.052
Fluid Density (ppg) x = Pressure gradient (psi/ft)
Hydrostatic Pressure is the pressure exerted by a column of fluid at rest, and is calculated by multiplying the gradient of the fluid by the True Vertical Depth at which the pressure is being measured:
Fluid gradient (psi/ft) x TVD = Hyd. Pressure(psi)

8. T V D
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You have to consider the vertical height or depth of the fluid column, the shape of the hole doesn’t matter.

9. Normal Formation Pressure
Normal formation pressure is equal to the hydrostatic pressure of the water occupying the pore spaces from the surface to the subsurface formation.
Native fluid is mainly dependent on its salinity and is often considered to be: psi/ft
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10. Abnormal Formation Pressure
Abnormal formation pressures are any formation pressures that are greater than the hydrostatic pressure of the water occupying the pore spaces.
Commonly caused by the under-compaction of shale’s, clay-stone or faulting...
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11. Subnormal Pressure: is defined as any formation pressure that is less than “normal” pressure.
It can be due to reservoir depletion,fault …
Transition Zone: is the formation in which the pressure gradient begins to change from a normal gradient to a subnormal gradient or, more usually, to an abnormal gradient.

12. UNDERCOMPACTED SHALES / SAND.
UNCONSOLIDATED
SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES
SAND WITH COMMUNICATION TO SURFACE
SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED
ENCLOSED SAND LENS WITH FORMATION FLUID

13. GAS CAP Ph Pabnormal = Pf-Pg Pf Pg NORMAL FORMATION PRESSURE ABOVE CAP
ROCK =0.465 PSI/FT Ph
Pabnormal = Pf-Pg Pf Pg
GAS PRESSURE
GRADIENT = 0.1 PSI/FT
COMMUNICATION BETWEEN FLUID AND GAS

14. SURCHARGED FORMATIONS

15. NATURALLY SURCHARGED FORMATIONS
FAULT ZONE Pf Pf

16. ARTESIAN WELL NORMAL FORMATION PRESSURE AT THE WELL
UNTILL BELOW THE CAP
ROCK
LAKE
HYDROSTATIC
PRESSURE
FROM
FORMATION
WATER
COLUMN
POROUS SANDSTONE
BELOW CAP ROCK

17. SURFACE EROSION ENCLOSED FORMATION LEVEL CHANGEPf H2 Pf Pf

18. Porosity & Permeability
The essential properties of reservoir rocks are:
- Their porosity and permeability.
The porosity provides the storage space for fluids and gases and is
the ratio of the pore spaces in the rock to the bulk volume of the rock.
This is expressed as a percentage. Reservoir rocks commonly have
porosity’s ranging from 5% to 30%.
Formation permeability is a measure of how easy the fluid will flow
through the rock. Permeability is expressed in Darcys, from a few
milliDarcys to several Darcys.
These properties will determine how much and how quick a kick will enter into the well. Kicks will enter a wellbore faster from rocks having high permeability.
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19. Pores are connected for the Permeability
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Tiny openings in rock are pores Porosity
Pores are connected for the Permeability

20. Formation Pressure SIDPP + Hydrostatic pressure = Formation Pressure
When the well is shut in, Formation Pressure can be found with the following formula:
SIDPP + Hydrostatic pressure = Formation Pressure
SICP + Influx Hyd + Mud Hyd = Formation Pressure
SICP +
Mud Hydrostatic
Influx Hydrostatic =
SIDPP +
Mud Hydrostatic =
Formation Pressure

21. KICK INDICATORS

22. - Flow from Well (pumps off)
POSITIVE KICK SIGNS
Positive Indications of a kick:
- Flow from Well (pumps off)
- Increase in Flow from Well (pumps on)
- Pit Volume Gain

23. KICKS WHILE TRIPPING Incorrect Fill or Return Volumes - Swabbing
- Surging
If any deviation, the FIRST action will be to install a fully open safety valve and make a Flow-Check.
Remember: It is possible that the well will not flow even if an influx has been swabbed in.

24. That the well MIGHT be going under-balanced
KICKS WHILE DRILLING
Early Warning Signs
That the well MIGHT be going under-balanced

25. Indications of Increasing Formation Pressure
Increase in Drilling Rate
Change in D - Exponent
Change in Cutting size and shape
Increase in Torque and Drag
Chloride Trends
Decrease in Shale Density
Temperature Measurements
Gas Cut Mud
Connection Gas
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26. Increase in Drilling Rate:
While drilling normally pressured shale and assuming a fairly constant bit weight, RPM, and hydraulic program, a normal decrease in penetration rate can be expected. When abnormal pressure is encountered, differential pressure and shale density are decreased causing a gradual increase in penetration rate.
ROP
Depth

27. Increase in Torque and Drag
Increase in torque and drag often occurs when drilling under balanced through some shale intervals.
There is a build up of cuttings in the annulus and this may be a sign that pore pressure is increasing.
Torque
Depth

28. Change in “d” Exponent:
“d” is an indication of drill ability and ROP, RPM, WOB, bit size are used to calculate its value.
Trends of “d” normally increase with depth, but in transition zones, it may decrease with lower than expected value.
“d”
Depth

29. Change in cutting size and shape
Normally pressured shale: cuttings are small with rounded edges, generally flat.
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Abnormally pressured shale: cutting are long and splintery with angular edges.
As differential between the pore pressure and bottom pressure is reduced, the cuttings have a tendency to “explode” of bottom.

30. Chloride Trends:
The chloride content of the mud filtrate can be monitored both going into and coming out of the hole.
A comparison of chloride trends can provide a warning or confirmation signal of increasing pore pressure.
Chloride
Depth

31. Decrease in Shale Density:
Shale density normally increases with depth but decreases as abnormal pressure zones are drilled.
When first deposited, shale has a high porosity. During normal compaction, a gradual reduction in porosity occurs with an increase of the overlaying sediments.
Shale
Density
Depth

32. Temperature Measurements:
The temperature gradient in abnormally pressured formations is generally higher than normal.
Temp.
Depth

33. Gas Cut Mud
The presence of gas cut mud does not indicate that the well is kicking ( gas may have been entrained in the cutting ). However, the presence of gas cut mud must be treated as an early warning sign of a potential kick.
- Gas cut mud only slightly reduces mud column pressure, when it is close to surface.
- Drilled cuttings from which the gas comes may compensate for the decrease.

34. Connection Gas
Connection gas are detected at the surface as a distinct increase above the background gas, as bottom up is circulated after a connection.
Connection gases may indicate a condition of near balance.
If connection gas is present, limiting its volume by controlling the drilling rate should be considered.

35. SYSTEM PRESSURE LOSSES

36. Objectives Identify the different pressures losses in the system
Identify which one influence bottom hole pressure
Convert this pressure to an equivalent mud weight

37. Mud System Pressure Losses
Pumping through a pipe with a mud pump at 80 spm, with gauges mounted on the discharge of the pump and at the end of the pipe.
The gauge on the pump reads 100 psi.
The gauge on the end of the pipe reads 0 psi.
It can be assumed from this information that the 100 psi drop in pressure through the pipe is the result of friction losses in the pipe as the fluid is pumped through it.
100 psi
0 psi
80 SPM

38. Mud System Pressure Losses
500 psi
100 psi
400 psi
0 psi
80 SPM

39. Mud System Pressure Losses
1000 psi
900 psi
100 psi
80 SPM
400 psi
500 psi
500 psi
0 psi

40. Mud System Pressure Losses
2300 psi
100 psi
2200 psi
1800 psi
400 psi
1300 psi
500 psi
80 SPM
0 psi

41. Mud System Pressure Losses
2600 psi
2500 psi
0 psi
100 psi
80 SPM
Annular
Pressure
Losses
400 psi
300 psi
2100 psi
500 psi
1600 psi
1300 psi
300 psi

42. Mud System Pressure Losses
APL EXAMPLE
0 psi
0 psi
A well has been drilled to 10,000 ft.
The mud weight is 10 ppg.
To find our Hydrostatic pressure we use the following formula;
Mud Wt x x TVD 10 x x 10,000 = 5,200psi.
The gauge on the drawing shows bottom hole hydrostatic pressure.
0 psi
0 SPM
10,000 ft TVD
MUD WT = 10 ppg
0 psi
0 psi
5200 psi

43. Mud System Pressure Losses
APL EXAMPLE
2600 psi
100 psi
2500 psi
2100 psi
400 psi
1600 psi
500 psi
1300 psi
0 psi
5500 psi
300 psi
If we now start to circulate at 80 spm through our system with the same pressure losses as before.
As you can see from this example the bottom hole pressure has increased by 300 psi.
This increase is due to the Annular Pressure Losses (APL) acting down on the bottom of the well and is usually called “Bottom Hole Circulating Pressure” (BHCP)
80 SPM
10,000 ft TVD
MUD WT = 10 ppg

44. Equivalent Circulating Density
The APL while circulating has the same effect on bottom hole pressure as increasing the mud weight.
This theoretical increase in mud weight is called the Equivalent Circulating Density or Equivalent Mud Weight.
It can be calculated by using the following formula:
_____APL(psi) __ + Original Mud Weight
TVD x 0.052

45. Summary:
Annular Pressure Losses are the pressure losses caused by the flow of fluid up the annulus and are the only losses in the system that affect BHP.
Equivalent Circulating Density is the effective density at any depth created by the sum of the total hydrostatic plus the APL.

46. Exercise - Pressure Gradient? - Hydrostatic Pressure?
300 psi
600 psi
800 psi
1200 psi
450 psi
- Pressure Gradient?
- Hydrostatic Pressure?
- Pump 40 spm?
- A P L?
- ECD at 40 SPM?
40 SPM
MUD WT = 12 ppg
MD = 9,550 ft
TVD = 8,000 ft

47. EFFECTS ON PRESSURES

48. MUD WEIGHT CHANGE 2600 psi 80 spm Mud wt 10 ppg
A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi.
It is decided to increase the mud weight to 11 ppg.
80 spm
Mud wt 10 ppg

49. MUD WEIGHT CHANGE 2860 psi 80 spm Mud wt 11 ppg
It is a good drilling practice to calculate the new circulating pressure before changing the mud weight.
The way we calculate this change in pressure is to use the following formula;
New Mud ppg x Old psi.
Old Mud ppg
11 ppg x 2600 = 2860psi
10 ppg
The new pump pressure would be approximately 2860 psi.
2860 psi
80 spm
Mud wt 11 ppg

50. Final Circulating Pressure
The formula that was just used to calculate the pressure change due to a change in mud weight, is also the formula used to calculate the Final Circulating Pressure.
Kill Mud wt x Slow circulating rate press .
Old Mud wt

51. PUMP STROKE CHANGE
2600 psi
A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi.
It is decided to increase the pump speed from 80 spm to 100 spm.
80 spm
Mud wt 10 ppg

52. PUMP STROKE CHANGE 4063 psi 100 spm Mud wt 10 ppg
It is a good drilling practice to calculate the new circulating pressure before changing the pump speed.
The way we calculate this change in pressure is to use the following formula;
New SPM Old psi x Old SPM
2600 x 100 spm spm = 4063 psi
The new pump pressure would be approximately 4063 psi.
4063 psi
100 spm
Mud wt 10 ppg

53. Preparation
and
Prevention

54. Preparation and Prevention
Barite and Mud chemical stocks
Equipment line up for shut-in
Slow circulating rates
M A A S P
Well Control Drills
Flow Checks
Safety Valves and Float Valves

55. FLOWPATH
LINE UP FOR
HARD SHUT IN

56. FLOWPATH HARD SHUT IN 2 3 4 1 5 Pick off bottom and position string
Stop pumps & Rotation
Close BOP (Ram or Annular)
Open hydraulic side outlet valve
Observe pressure 1 2 3 4 5

57. FLOWPATH
LINE UP FOR
SOFT SHUT IN

58. FLOWPATH SOFT SHUT IN 2 3 4 1 5 6 Pick off bottom and position string
Stop pumps & Rotation
Open hydraulic side outlet valve
Close BOP (Ram or Annular)
Close remote hydraulic choke
Observe pressure 1 2 3 4 5 6

59. Slow Circulating Rate
A Slow Circulating Rate ( SCR) is the reduced circulating pump rate that is used when circulating out a kick.
It is called Dynamic Pressure Losses ( PL ) on the kick sheet

60. Slow Circulating Rate
Well Control Operations are conducted at reduced circulating rates in order to:
Minimise Excess of annulus pressure
Allows for more controlled choke adjustments
Allows for the weighting up and degassing of the mud and disposal of the influx
Reduce the chance of choke erosion
Reduce risk of over pressuring system if plugging occurs

61. SCR’s pressure for each pump will be taken:
Slow Circulating Rate
SCR’s pressure for each pump will be taken:
If practical, at the beginning of every tour
Any time the mud properties are changed
When a bit nozzle is changed.
When the BHA is changed.
As soon as possible after bottoms-up from any trip
At least every 1000 feet (305m) of new hole

62. Slow Circulating Rate
A minimum of 2 (two) circulating rates should be obtained for all pumps.
The pressure must be recorded using the gauges that will be used during well kill operations
The SCR pressure will be recorded on the IADC report

63. Formation Strength Test or LOT
A leak off test (LOT) determines the pressure at which the formation begins to take fluid.
This test is conducted after drilling out about 10 to 15 ft of new hole below the shoe.
Such a test will establish the strength of the formation and the integrity of the cement job at the shoe.
The test pressure should not exceed 70% of the minimum yield of the weakest casing.

64. L O T
Use a high pressure, low volume pump ( bbl/min.) such as a cement pump or a test pump using intermittent or continuous method of pumping.
Rig pumps are not suitable to perform leak off tests.
The objective of the above test is not to fracture the formation, but rather to identify the “formation intake pressure”.
This “intake pressure” is identified as that point where a deviation occurs between the trends of the final pump pressure curve and the static pressure curve. Once the formation intake pressure has been reached, further pumping should be avoided.

65. L O T
The total pressure applied at the shoe is the sum of the surface pressure from the pump and the hydrostatic pressure for the shoe depth.
This total pressure is applied to the formation.
Surface Casing Pressure
+ Hydrostatic Pressure =
Pressure at Shoe

66. L O T This total pressure is applied to the formation. 720 psi 720 psi+
1498 psi
ppg
3,000’
2218 psi
This total pressure is applied to the formation.

67. The Maximum Available Fluid Density (MAMW).
This is the total pressure, represented as fluid density, above which leak off or formation damage may occurs with no pressure on surface.
2218 psi
0 psi
3,000’
MAMW = 14.2 ppg
MAMW=
3000 x 0.052

68. The fracture gradient of the formation will be:
Fracture gradient = MAMW x 0.052
Fracture Gradient = 14.2 x 0.052
= psi/ft
therefore:
MAMW = Fracture Gradient / 0.052
2218 psi
0 psi
3,000’

69. Maximum Allowable Annular Surface pressure
M A A S P
MAASP is defined as the surface pressure which, when added to the hydrostatic pressure of the existing mud column, results in formation breakdown at the weakest point in the well.
This value is based on the Leak Off Test data.

70. On Kill Sheet Write leak off test pressure here
Write mud weight used for the test
Calculate maximum allow mudweight
and Insert here
Calculate current MAASP and insert here

71. Drills
Pit drill
Trip drill
Abandonement drill
Strip drill

72. Actions
Upon
Taking a Kick

73. Causes for the Loss of Primary Well Control
Kick Size and Severity
Kick Detection
Recording Pressures
Drilling With Oil Base Mud
Hard Shut-in
Soft Shut-in
Height and Gradient of a Kick

74. Causes for the loss of Primary Well Control
Failure to Fill The Hole Properly While Tripping
Swabbing / Surging
High pulling speed
Mud properties
Tight annulus clearance
Well Geometry
Formation Properties
Lost Circulation
Insufficient Drilling Fluid Density
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75. Kick Size and Severity
Minimizing kick size is fundamental for the safety of a Well Control operation.Smaller Kicks: Provide lower choke or annulus pressure both upon initial closure and later when the kick is circulated to the choke.
Controllable Parameters: You can influence on:
Degree of underbalance Mud Weight
Length of reservoir exposed ROP + Kick detection time
Time well remains underbalanced Kick detection + shut-in time
Wellbore diameter Hole size
Non-controllable Parameters
Formation permeability and type of influx

76. Kick Detection While Drilling:
Drilling breaks: They will be flow checked. Circulating B/up is advisable if F/C is negative. Tool pusher must be informed for all.
Increase in flow rate: First positive indicator.
Increase in pit volume: Positive indicator. Anyone influencing the active system must communicate with the Driller.
Variation in Pump speed and Pressure: (“U-tube”)
Well flowing during a Connection: ECD to ESD
Change of drilling fluid properties: Gas cut or fluid contaminated.
While Tripping:
Improper fill-up: swabbing or surging
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77. Shut- in Procedure: HARD SHUT-IN
Stop rotation
Pick up the drill string to shut-in position (subsea to hang off position)
Stop the pump
Flow check
If the well flows
Close BOP
Open remote control choke line valve
Notify Tool Pusher and OIM
Record time, SIDPP, SICP and pit gain

78. Shut- in Procedure: SOFT SHUT-IN
Stop rotation
Pick up the drill string to shut-in position (Subsea to hang off position)
Stop the pump
Flow check
If the well flows
Open remote control choke line valve
Close BOP
Close choke
Notify Tool Pusher
Record time, SIDPP, SICP and pit gain

79. Close-in Methods specified by American Petroleum Institute
Soft close-in procedure
For a soft close-in, a choke is left open at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system, with the exception of one choke line valve located near the blow out preventer. When the soft close-in procedure is selected for closing in a well the:
1 choke line valve is opened.
2 Blow out preventer is closed.
3 Choke is closed.
This procedure allows the choke to be closed in such a manner to permit sensitive control and monitoring of casing pressure buildup during closure.
Hard close-in procedure
For a hard close-in, the chokes remain closed at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system with the exemption of the choke(s) itself and one choke line valve located near the blow out preventer stack. When the hard close-in procedure is selected for closing in a well, the blow out preventer is closed. If the casing pressure cannot be measured at the well head, the choke line valve is opened with the choke or adjacent high pressure valve remaining closed so that pressure can be measured at the choke manifold. This procedure allows the well to be closed in the shortest possible time, thereby minimising the amount of additional influx of kicking fluid to enter the well bore.

80. Surface Pressure After Shut-in

81. OIL BASE MUD

82. Drilling with OBM

83. Gas Influx in WBM or in OBM
Water Base Mud
Easier to detect
Higher migration rate
Gas stay as a separate phase
On bottom bigger kick size
Higher casing pressure
Expansion:
- Slow first then Fast
Oil Base Mud
More difficult to detect
Lower migration rate
Gas go into solution
On bottom smaller kick size
Smaller casing pressure
Expansion:
- none first then very fast at the bubble point

84. Height and Gradient of a Kick

85. Well Kill
Techniques

86. Driller’s Method
Wait and Weight Method
Volumetric Method

87. Well Kill Techniques

88. Driller’s Method : 1 st Circulation
The original mud weight is used to circulate the influx
- Reset the stroke counter.
- Bring the pump up to kill speed while holding the casing pressure constant.
- Maintain DP pressure constant until the influx is circulated out from the well
BHP

89. Driller’s Method : 1 st Circulation
The maximum shoe pressure is when the top of the influx reaches the shoe

90. Driller’s Method : 1 st Circulation
When the influx is passing the casing shoe, the shoe pressure will decrease.

91. Driller’s Method : 1 st Circulation
When the influx is above the casing shoe, the shoe pressure will remain constant.

92. Driller’s Method : 1 st Circulation
- Surface casing pressure is increasing as the influx is circulated up the well.
- Pit volume is raising.

93. Driller’s Method : 1 st Circulation
- The maximum surface casing pressure is reached when the top of the influx is at surface.
- It will be the maximum increase in pit level.

94. Driller’s Method : 1 st Circulation
- As the influx is passing through the choke, the surface casing pressure will decrease.
- The pit volume will decrease.

95. Driller’s Method : 1 st Circulation
If all the influx is successfully circulated from the well and the pump is stopped,
SIDPP = SICP

96. Driller’s Method : 2 nd Circulation
- Line up the kill mud.
- Reset the stroke counter.
- Bring the pump up to kill speed while holding the casing pressure constant.
- Reset the stroke counter after pumping the surface line volume.
- Keep the casing pressure constant until KMW reach the bit.
( Or follow the calculated DP pressure drop schedule from ICP to FCP.)
Pit volume has increased due to the weighting material added in the system.

97. Driller’s Method : 2 nd Circulation
When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.

98. First Circulation Drill Pipe Casing Driller’s Method Driller’s Method
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99. Second Circulation Drill Pipe Casing Driller’s Method Driller’s Method
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100. Driller’s Method Advantages: Disadvantages:
- Can start circulating right away
- Able to remove influx even if not enough barite on board
- Less chance of gas migration
- Less calculation
Disadvantages:
- Higher surface pressure
- In certain situation, higher shoe pressure
- Two circulation, more time through the choke

101. Wait and Weight -The kill mud weight is used to circulate the influx
-Reset the stroke counter
- Bring the pump up to kill speed while Holding the casing pressure constant.
- Reset the stroke counter after pumping the surface line volume.
-Pump kill mud from surface to bit while following a calculated DP pressure drop schedule.
BHP

102. Wait and Weight
When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.

103. One Circulation Only
Wait
&
Weight
Drill Pipe
Wait
&
Weight
Casing

104. Wait & Weight Method Advantages: Disadvantages:
- Can generate lower pressure on formation near the casing shoe
- In most situation generate less pressure on surface equipment
- With a long open hole, less chance to induce losses
- One circulation, less time spent circulating through the choke
Disadvantages:
- Longer waiting time prior to circulate the influx
- Cutting could settle down and plug the annulus
- Gas migration might become a problem
- Need to have enough barite to increase the mud weight
- More Calculations

105. Differences between W&W and Driller’s methods
h'i
h'i
W & W Method
Gas at Casing Shoe,
kill mud in drill string hm hm
Drillers Method
Gas at Casing Shoe

106. Differences between W&W and Driller’s methods
h'i
h''i
W & W Method
Gas at Casing Shoe,
Kill mud in annulus hm
Drillers Method
Gas at Casing Shoe hm
hkm

107. Gas Behavior No gas expansion
Free gas expansion
No gas expansion
Volume to bleed off to maintain BHP constant

108. Free Gas Expansion
Gas may be swabbed into a well and remain at TD. The influx will expand as it moves up the annulus when circulation is started. The amount of expansion can easily be calculated. If undetected, free gas expansion can cause a serious well control problem.

109. Free Gas Expansion
A column of 10,000ft of mud, Gm=0.5psi/ft compresses one barrel of gas at TD.
The pressure in the gas is;
10,000 x 0.5 = 5,000 psi
Multiply P x Vg to find the constant.
D=10,000ft
Gm = 0.5 psi/ft
Gas D
10,000 P
5,000 Vg 1
5,000
CST

110. Free Gas Expansion
The gas has risen so that the top of the bubble is at 5,000ft from the surface.
The pressure in the gas is;
5,000 x 0.5 = 2,500 psi
Using the constant, the volume of gas is found:
5,000 / 2,500 = 2 barrels
D=5,000ft
Gm = 0.5 psi/ft D
10,000
5,000
5,000
2,500 P Vg 1 2
5,000
5,000
PVg

111. Free Gas Expansion
The top of the bubble is at 2,500ft from the surface.
The pressure in the gas is;
2,500 x 0.5 = 1,250 psi
The volume of gas is found:
5,000 / 1,250 = 4 barrels
D=2,500ft
Gm = 0.5 psi/ft D
10,000
5,000
2,500 P
5,000
2,500
1,250 Vg 1 2 4
PVg
5,000
5,000
5,000

112. Free Gas Expansion At 1,250ft from the surface. Pressure;
1,250 x 0.5 = 625 psi
Volume of gas;
5,000 / 625 = 8 barrels
D=1,250ft
Gm = 0.5 psi/ft D P Vg
PVg
10,000
5,000 1
2,500 2
1,250 4
625 8

113. Free Gas Expansion D P Vg PVg 10,000 5,000 1 2,500 2 1,250 4 625 8
Gm = 0.5 psi/ft D P Vg
PVg
10,000
5,000 1
2,500 2
1,250 4
625 8
14.7
341

114. No Gas Expansion Gm = 0.52 psi/ft 0 psi 5,200 psi
1 bbls
10,000 ft
5,200 psi
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Gm = 0.52 psi/ft
1 bbl gain

115. No Gas Expansion Gm = 0.52 psi/ft 0 psi 1,300 psi 5,200 psi 6,500 psi
1 bbls
1 bbls
10,000 ft
5,200 psi
6,500 psi
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Gm = 0.52 psi/ft
1 bbl gain
1 bbl gain

116. No Gas Expansion Gm = 0.52 psi/ft 0 psi 1,300 psi 2,600 psi 5,200 psi
1 bbls
5,000 ft
7,500 ft
1 bbls
1 bbls
10,000 ft
5,200 psi
6,500 psi
7,800 psi
________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
Gm = 0.52 psi/ft
1 bbl gain
1 bbl gain
1 bbl gain

117. No Gas Expansion Gm = 0.52 psi/ft 0 psi 1,300 psi 2,600 psi 3,900 psi
1 bbls
1 bbls
5,000 ft
7,500 ft
1 bbls
1 bbls
10,000 ft
5,200 psi
6,500 psi
7,800 psi
9,100 psi
________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
Gm = 0.52 psi/ft
1 bbl gain
1 bbl gain
1 bbl gain
1 bbl gain

118. No Gas Expansion Gm = 0.52 psi/ft 0 psi 1,300 psi 2,600 psi 3,900 psi
1 bbls
2,500 ft
1 bbls
1 bbls
5,000 ft
7,500 ft
1 bbls
1 bbls
10,000 ft
5,200 psi
6,500 psi
7,800 psi
9,100 psi
10,400 psi
________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
Gm = 0.52 psi/ft
1 bbl gain
1 bbl gain
1 bbl gain
1 bbl gain
1 bbl gain

119. Volume to bleed off to keep BHP constant
500 psi
1800 psi
0 ft
2,500 ft
5,000 ft
5700 psi
4400 psi
1.3bbls
7,500 ft
1bbls
P1V1 = P2V2
V2 = 5700 x 1 / 4400
V2 = 1.29 bbls
2500 x .52 = 1300 psi
1 bbls
10,000 ft
5,700 psi
7000 psi
5,700 psi
________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
Gm = 0.52 psi/ft
1 bbl gain
1 bbl gain
1.3 bbl gain

120. Volume to bleed off to keep BHP constant
500 psi
1800 psi
0 ft
2,500 ft
3100 psi
4400 psi
1.84bbls
5,000 ft
1.3bbls
P1V1 = P3V3
V3 = 5700 x 1 / 3100
V3 = 1.84 bbls
1.3 bbls
7,500 ft
5000 x .52 = 2600 psi
10,000 ft
5,700 psi
7,000 psi
5,700 psi
________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
Gm = 0.52 psi/ft
1.3 bbl gain
1.3 bbl gain
1.84 bbl gain

121. Volume to bleed off to keep BHP constant
500 psi
1800 psi
0 ft
3100 psi
1800 psi
2,500 ft
1.8bbls
3.16bbls
P1V1 = P4V4
V4 = 5700 x 1 / 1800
V4 = 3.16 bbls
1.8 bbls
5,000 ft
7,500 ft
7500 x .52 = 3900 psi
10,000 ft
5,700 psi
7,000 psi
5,700 psi
________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
Gm = 0.52 psi/ft
1.84 bbl gain
1.84 bbl gain
3.16 bbl gain

122. Volume to bleed off to keep BHP constant
500 psi
1800 psi
1800 psi
500 psi
0 ft
P1V1 = P5V5
V5 = 5700 x 1 / 500
V5 = 11.4 bbls
3.16 bbls
11.4bbls
2,500 ft
3.16 bbls
5,000 ft
7,500 ft
10000 x .52 = 5200 psi
10,000 ft
5,700 psi
7,000 psi
5,700 psi
________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
Gm = 0.52 psi/ft
3.16 bbl gain
3.16 bbl gain
11.4 bbl gain

123. WELL # 1 HOLE SIZE HOLE DEPTH TVD/MD CASING 9-5/8” TVD/MD
DRILL PIPE CAP.
HEAVY WALL DRILL PIPE
CAPACITY
DRILL COLLARS 6-1/4”
DRILLING FLUID DENSITY
CAPACITY OPEN HOLE/COLLARS
CAPACITY OPEN HOLE/DRILL PIPE-HWDP
CAPACITY CASING/DRILL PIPE
FRACTURE FLUID DENSITY
SIDPP
SICP
PUMP DISPLACEMENT
RRCP 30 SPM
PIT GAIN
8-1/2 INCH
FEET
9875 FEET
BBL/FEET
600 FEET
BBL/FEET
880 FEET
BBL/FEET
14.0 PPG
BBL/FEET
BBL/FEET
BBL/FEET
16.9 PPG
530 PSI
700 PSI
BBL/STRK
650 PSI
10.0 BBL
DRILLERS METHOD:
The well drilled is a vertical well and the well has reach a total depth of ft where a overpressure zone is penetrated resulting in a 10 bbl influx into the wellbore.
The well was shut in using Hard Shut In method on Upper Pipe Rams and the above mentioned information were obtained and Kill Sheet filled out for using Drillers Method to circulate out the influx and regain control over the well.
Internal strokes from surface to bit: strokes
Total annulus from bit to surface: strokes
Open hole from bit to shoe: 620 strokes
Kill fluid density: ppg
Initial circulation pressure psi
Final circulation pressure: psi
Initial MAASP with drilling fluid density: psi
New MAASP with kill fluid density: psi
Height of influx: ft
Total circulation time w/ 30 spm: min

124. DRILLERS METHOD SHUTTING IN WELL 1st CIRCULATION DP CSG 1489 530 700
1489
SHUTTING IN
WELL
MAASP
530
700 O C
DRILLERS METHOD:
While drilling at ft a flow increase was observed and the well shut in using Hard Shut In method:
Position drill string.
Shut down pumps and rotating.
Close Upper Pipe Rams.
Open Hyd. Side Outlet Valve.
Observe pressure.
DP pressure stabilized at 530 psi.
CSG pressure stabilized at 700 psi.
BHP increased from Ph 8398 psi to 8928 psi. ( Ph + SIDPP)
Shoe pressure increased from Ph 7189 psi to 7889 psi. ( Phshoe + SICP)
Pit gain measured to 10 bbl.
7189
7889
Ph= 8398 psi
Pf= 8928 psi

125. DRILLERS METHOD REACHING ICP KEEP CONSTANT CASING PRESSURE
1st CIRCULATION DP
CSG 30
1489
REACHING
ICP
KEEP CONSTANT
CASING PRESSURE
WHILE BRINGING
PUMPS UP
PUMPS UP AND
PRESSURE STABILISED
DRILL PIPE PRESSURE 22
MAASP
1180
700 O C
DRILLERS METHOD:
While keeping constant casing pressure the pumps are slowly brought up to slow circulating rate, in this case 30 SPM. When the pumps are running at 30 SPM and pressures have stabilized the ICP pressure on the drill pipe gauge is keep constant.
ICP= SIDPP + RRCP
530 psi psi = 1180 psi
Shoe pressure = Phshoe + SICP
7189 psi psi = 7889 psi
MAASP = Max Shoe Pressure - Phshoe
8678 psi psi = 1489 psi
7889
BHP= 8928 PSI
Pf= 8928 psi

126. DRILLERS METHOD GAS IN OPEN HOLE CONSTANT DRILL PIPE PRESSURE
1st CIRCULATION DP
CSG 30
GAS IN OPEN HOLE
CONSTANT
DRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSURE
INCREASE
SHOE PRESSURE
MAASP CONSTANT
1489
310
MAASP
1180
740 O C
7929
DRILLERS METHOD:
Situation after pumping 310 strokes:
Drill Pipe Pressure is kept constant while gas is being pumped up through the open hole section. The gas is expanding allowing the pressure inside bubble to decrease.
Casing pressure increasing due to the expanding gas is displacing drilling fluid.
CSG P = BHP - (Phmud + Phgas) 740 psi
Shoe pressure is increasing with same value as the casing pressure.
Shoe P = Phshoe + Csg P psi
MAASP remains constant due to no change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

127. DRILLERS METHOD GAS REACH SHOE CONSTANT DRILL PIPE PRESSURE
1st CIRCULATION DP
CSG 30
GAS REACH SHOE
CONSTANT
DRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSURE
INCREASE
SHOE PRESSURE
INCREASE TO MAX
MAASP CONSTANT
1489
470
MAASP
1180
775 O C
DRILLERS METHOD:
Situation after pumping 470 strokes:
Drill Pipe Pressure is kept constant while gas is being pumped up through the open hole section and the top of the gas bubble reach the shoe. The gas is expanding allowing the pressure inside bubble to decrease.
Casing pressure increasing due to the expanding gas is displacing drilling fluid.
CSG P = BHP - (Phmud + Phgas) 775 psi
Shoe pressure is increasing with same value as the casing pressure.
Shoe P = Phshoe + Csg P psi
MAASP remains constant due to no change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
7964
BHP= 8928 PSI
Pf= 8928 psi

128. DRILLERS METHOD GAS MOVES INSIDE CASING CONSTANT DRILL PIPE PRESSURE
1st CIRCULATION DP
CSG 30
GAS MOVES INSIDE
CASING
CONSTANT
DRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSURE
INCREASE
SHOE PRESSURE
DECREASE
MAASP INCREASING
1685
620
MAASP
1180
785 O C
7718
DRILLERS METHOD:
Situation after pumping 620 strokes:
Drill Pipe Pressure is kept constant while gas is being pumped from the open hole section until all the gas is inside the casing so the open hole section is displaced to original drilling fluid. The gas is expanding allowing the pressure inside bubble to decrease.
Casing pressure increasing due to the expanding gas is displacing drilling fluid.
CSG P = BHP - (Phmud + Phgas) 785 psi
Shoe pressure is constantly decreasing from gas reach the shoe until all gas is inside casing.
Shoe P = BHP - Phopen hole psi
MAASP start increasing from the first gas enter the casing due to change in Ph inside the casing
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

129. DRILLERS METHOD GAS MOVING INSIDE CASING CONSTANT DRILL PIPE PRESSURE
1st CIRCULATION DP
CSG 30
GAS MOVING INSIDE
CASING
CONSTANT
DRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSURE
INCREASE
SHOE PRESSURE
MAASP INCREASING
2020
2300
MAASP
1180
1120 O C
7718
DRILLERS METHOD:
Situation after pumping 2300 strokes:
Drill Pipe Pressure is kept constant while gas is being pumped up inside the casing between shoe and surface. The gas is expanding allowing the pressure inside bubble to decrease.
Casing pressure increasing due to the expanding gas is displacing drilling fluid.
CSG P = BHP - (Phmud + Phgas) psi
Shoe pressure remains constant from the moment all gas is inside the casing.
Shoe P = BHP - Phopen hole psi
MAASP increasing with the same value as the Csg P due to change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

130. DRILLERS METHOD GAS REACH CHOKE CONSTANT DRILL PIPE PRESSURE
1st CIRCULATION DP
CSG 30
GAS REACH CHOKE
CONSTANT
DRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSURE
INCREASE TO MAX
SHOE PRESSURE
MAASP
2480
4800
MAASP
1180
1580 O C
DRILLERS METHOD:
Situation after pumping 4800 strokes:
Drill Pipe Pressure is kept constant while gas is being pumped up inside the casing and the top of the gas bubble reach the choke. The gas is expanding allowing the pressure inside bubble to decrease.
Casing pressure increasing due to the expanding gas is displacing drilling fluid and when top of the gas bubble reach the choke casing pressure is increased to max.
CSG P = BHP - (Phmud + Phgas) psi
Shoe pressure remains constant from the moment all gas is inside the casing.
Shoe P = BHP - Phopen hole psi
MAASP increasing with the same value as the Csg P due to change in Ph inside the casing and will reach max value when gas at choke.
MAASP = Max Shoe Pressure - Phshoe psi
7718
BHP= 8928 PSI
Pf= 8928 psi

131. DRILLERS METHOD GAS OUT OF WELL CONSTANT DRILL PIPE PRESSURE
1st CIRCULATION DP
CSG 30
GAS OUT OF WELL
CONSTANT
DRILL PIPE PRESSURE
CASING PRESSURE
DECREASING TO SIDPP
SHOE PRESSURE
MAASP DECREASING
TO ORIGINAL VALUE
1489
5400
MAASP
1180
530 O C
7718
DRILLERS METHOD:
Situation after pumping 5400 strokes:
Drill Pipe Pressure is kept constant while gas is being pumped out of the well through the choke.
Casing pressure decreasing while drilling fluid is displacing gas in the well bore and will reach SIDPP when all the gas is out of the well.
CSG P = BHP - Phmud psi
Shoe pressure remains constant while the gas is displaced from the well bore due to no change in Phopen hole.
Shoe P = BHP - Phopen hole psi
MAASP decreasing with same value as the Casing Pressure and will reach initial MAASP when the annulus is displaced to original drilling fluid.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

132. DRILLERS METHOD START PUMPING KILL MUD 14.9 PPG CASING PRESSURE
2nd CIRCULATION DP
CSG 30
START PUMPING
KILL MUD 14.9 PPG
CASING PRESSURE
CONSTANT
SHOE PRESSURE
MAASP CONSTANT
1489
5400
MAASP
1180
530 O C
7718
DRILLERS METHOD:
Kill mud is being mixed to 14.9 ppg and 2nd circulation is started.
Casing pressure is kept constant while kill fluid fills the drill string.
CSG P = BHP - Phmud psi
Drillpipe pressure decreasing while kill fluid fills the drill string.
DP P = RRCP + (BHP - Phmud)
Shoe pressure remains constant while kill mud fills the drill string due to no change in Phopen hole.
Shoe P = BHP - Phopen hole psi
MAASP remains constant while kill mud fills the drill string.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

133. DRILLERS METHOD KILL FLUID INSIDE DRILL PIPE CASING PRESSURE CONSTANT
2nd CIRCULATION DP
CSG 30
KILL FLUID INSIDE
DRILL PIPE
CASING PRESSURE
CONSTANT
DRILL PIPE PRESSURE
DECREASING
SHOE PRESSURE
MAASP CONSTANT
1489
6306
MAASP
936
530 O C
7718
DRILLERS METHOD:
Situation after pumping 6306 strokes:
Casing pressure is kept constant while kill fluid fills the drill string.
CSG P = BHP - Phmud psi
Drillpipe pressure decreasing while kill fluid fills the drill string.
DP P = RRCP + (BHP - Phmud) psi
Shoe pressure remains constant while kill mud fills the drill string due to no change in Phopen hole.
Shoe P = BHP - Phopen hole psi
MAASP remains constant while kill mud fills the drill string.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

134. DRILLERS METHOD KILL MUD REACH BIT CONSTANT CASING PRESSURE
2nd CIRCULATION DP
CSG 30
KILL MUD REACH
BIT
CONSTANT CASING
PRESSURE
DRILL PIPE PRESSURE
DECREASING TO FCP
SHOE PRESSURE
CONSTANT
MAASP CONSTANT
1489
7212
MAASP
692
530 O C
7718
DRILLERS METHOD:
Situation after pumping 7212 strokes:
Kill fluid reach the bit.
Casing pressure is kept constant while kill fluid fills the drill string.
CSG P = BHP - Phmud psi
Drillpipe pressure decreasing while kill fluid fills the drill string and when kill fluid reach the bit pressure is FCP or RRCP w/14.9 ppg mud.
DP P = RRCP w/14.9 ppg psi
Shoe pressure remains constant while kill mud fills the drill string due to no change in Phopen hole.
Shoe P = BHP - Phopen hole psi
MAASP remains constant while kill mud fills the drill string.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

135. DRILLERS METHOD KILL MUD REACH SHOE DRILL PIPE PRESSURE CONSTANT
2nd CIRCULATION DP
CSG 30
KILL MUD REACH
SHOE
DRILL PIPE PRESSURE
CONSTANT
CASING PRESSURE
DECREASING
SHOE PRESSURE
MAASP CONSTANT
1489
7832
MAASP
692
469 O C
7657
DRILLERS METHOD:
Situation after pumping 7832 strokes:
Kill fluid at shoe.
Drillpipe pressure is kept constant while kill fluid displace original mud in annulus.
DP P = RRCP w/14.9 ppg psi
Casing pressure decreasing as kill fluid moves up the annulus to the shoe.
CSG P = BHP - Phmud psi
Shoe pressure decreasing as kill fluid moves up the annulus to the shoe with same value as the decrease in Csg P.
Shoe P = BHP - Phopen hole psi
MAASP remains constant while kill fluid moves up the annulus to the shoe.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

136. DRILLERS METHOD KILL MUD INSIDE CASING DRILL PIPE PRESSURE CONSTANT
2nd CIRCULATION DP
CSG 30
KILL MUD INSIDE
CASING
DRILL PIPE PRESSURE
CONSTANT
CASING PRESSURE
DECREASING
SHOE PRESSURE
MAASP DECREASING
1253
10202
MAASP
692
233 O C
7657
DRILLERS METHOD:
Situation after pumping strokes:
Kill fluid inside casing.
Drillpipe pressure is kept constant while kill fluid displace original mud in annulus.
DP P = RRCP w/14.9 ppg psi
Casing pressure decreasing as kill fluid moves up the annulus.
CSG P = BHP - Phmud psi
Shoe pressure remains constant while kill fluid is displacing original mud inside the casing due to no change in Ph open hole.
Shoe P = BHP - Phopen hole psi
MAASP decreasing as kill fluid is displacing original mud inside the casing with same value as the drop in casing pressure.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

137. DRILLERS METHOD KILL MUD AT SURFACE DRILL PIPE PRESSURE CONSTANT
2nd CIRCULATION DP
CSG 30
KILL MUD AT
SURFACE
DRILL PIPE PRESSURE
CONSTANT
CASING PRESSURE
DECREASING TO ZERO
SHOE PRESSURE
MAASP DECREASING
TO NEW MAASP w/KMW
1020
12600
MAASP
692 O C
7657
DRILLERS METHOD:
Situation after pumping strokes:
Kill fluid at the choke.
Drillpipe pressure is kept constant while kill fluid displace original mud in annulus.
DP P = RRCP w/14.9 ppg psi
Casing pressure decreasing as kill fluid moves up the annulus and will reach 0 psi when kill fluid reach the choke.
CSG P = BHP - Phmud 0 psi
Shoe pressure remains constant while kill fluid is displacing original mud inside the casing due to no change in Ph open hole.
Shoe P = BHP - Phopen hole psi
MAASP decreasing as kill fluid is displacing original mud inside the casing with same value as the drop in casing pressure.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

138. WELL # 1 HOLE SIZE HOLE DEPTH TVD/MD CASING 9-5/8” TVD/MD
DRILL PIPE CAP.
HEAVY WALL DRILL PIPE
CAPACITY
DRILL COLLARS 6-1/4”
DRILLING FLUID DENSITY
CAPACITY OPEN HOLE/COLLARS
CAPACITY OPEN HOLE/DRILL PIPE-HWDP
CAPACITY CASING/DRILL PIPE
FRACTURE FLUID DENSITY
SIDPP
SICP
PUMP DISPLACEMENT
RRCP 30 SPM
PIT GAIN
8-1/2 INCH
FEET
9875 FEET
BBL/FEET
600 FEET
BBL/FEET
880 FEET
BBL/FEET
14.0 PPG
BBL/FEET
BBL/FEET
BBL/FEET
16.9 PPG
530 PSI
700 PSI
BBL/STRK
650 PSI
10.0 BBL
WAIT & WEIGHT METHOD:
The well drilled is a vertical well and the well has reach a total depth of ft where a overpressure zone is penetrated resulting in a 10 bbl influx into the wellbore.
The well was shut in using Hard Shut In method on Upper Pipe Rams and the above mentioned information were obtained and Kill Sheet filled out for using W&W Method to circulate out the influx and regain control over the well.
Internal strokes from surface to bit: strokes
Total annulus from bit to surface: strokes
Open hole from bit to shoe: 620 strokes
Kill fluid density: ppg
Initial circulation pressure psi
Final circulation pressure: psi
Initial MAASP with drilling fluid density: psi
New MAASP with kill fluid density: psi
Height of influx: ft
Total circulation time w/ 30 spm: min

139. WAIT & WEIGHT METHOD SHUTTING IN WELL MIXING KILL MUD 14.9 PPG DP CSG
1489
SHUTTING IN
WELL
MIXING KILL MUD
14.9 PPG
MAASP
530
700 O C
7189
7889
WAIT & WEIGHT METHOD:
While drilling at ft a flow increase was observed and the well shut in using Hard Shut In method:
Position drill string.
Shut down pumps and rotating.
Close Upper Pipe Rams.
Open Hyd. Side Outlet Valve.
Observe pressure.
DP pressure stabilized at 530 psi.
CSG pressure stabilized at 700 psi.
BHP increased from Ph 8398 psi to 8928 psi. ( Ph + SIDPP)
Shoe pressure increased from Ph 7189 psi to 7889 psi. ( Phshoe + SICP)
Pit gain measured to 10 bbl.
Ph= 8398 psi
Pf= 8928 psi

140. WAIT & WEIGHT METHOD REACHING ICP KEEP CONSTANT CASING PRESSUREDP
CSG 30
REACHING
ICP
KEEP CONSTANT
CASING PRESSURE
WHILE BRINGING
PUMPS UP
PUMPS UP AND
PRESSURE STABILISED
KEEP DRILL PIPE
PRESSURE ON
SCHEDULE
1489 22
MAASP
1180
700 O C
7889
WAIT & WEIGHT METHOD:
While keeping constant casing pressure the pumps are slowly brought up to slow circulating rate, in this case 30 SPM. When the pumps are running at 30 SPM and pressures have stabilized change to ICP and then keep DP pressure on schedule.
ICP= SIDPP + RRCP
530 psi psi = 1180 psi
Shoe pressure = Phshoe + SICP
7189 psi psi = 7889 psi
MAASP = Max Shoe Pressure - Phshoe
8678 psi psi = 1489 psi
BHP= 8928 PSI
Pf= 8928 psi

141. WAIT & WEIGHT METHOD GAS IN OPEN HOLE DRILL PIPE PRESSURE DECREASINGDP
CSG 30
GAS IN OPEN HOLE
DRILL PIPE PRESSURE
DECREASING
CASING PRESSURE
INCREASING
GAS EXPANDING
SHOE PRESSURE
MAASP CONSTANT
1489
310
MAASP
1097
740 O C
7929
WAIT & WEIGHT METHOD:
Situation after pumping 310 strokes:
The gas is expanding allowing the pressure inside bubble to decrease.
Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped.
DP P = ICP - (310 x 27) psi
100
Casing pressure increasing due to the expanding gas is displacing drilling fluid.
CSG P = BHP - (Phmud + Phgas) 740 psi
Shoe pressure is increasing with same value as the casing pressure.
Shoe P = Phshoe + Csg P psi
MAASP remains constant due to no change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

142. WAIT & WEIGHT METHOD GAS REACH SHOE DRILL PIPE PRESSURE DECREASINGDP
CSG 30
GAS REACH SHOE
DRILL PIPE PRESSURE
DECREASING
CASING PRESSURE
INCREASING
GAS EXPANDING
SHOE PRESSURE
INCREASE TO MAX
MAASP CONSTANT
1489
470
MAASP
1053
775 O C
7964
WAIT & WEIGHT METHOD:
Situation after pumping 470 strokes:
The gas is expanding allowing the pressure inside bubble to decrease.
Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped.
DP P = ICP - (470 x 27) psi
100
Casing pressure increasing due to the expanding gas is displacing drilling fluid.
CSG P = BHP - (Phmud + Phgas) 775 psi
Shoe pressure is increasing with same value as the casing pressure and reach max. value when gas reach the shoe.
Shoe P = Phshoe + Csg P psi
MAASP remains constant due to no change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

143. WAIT & WEIGHT METHOD GAS MOVES INSIDE CASING DRILL PIPE PRESSUREDP
CSG 30
GAS MOVES INSIDE
CASING
DRILL PIPE PRESSURE
DECREASING
CASING PRESSURE
INCREASING
GAS EXPANDING
SHOE PRESSURE
MAASP INCREASING
1685
620
MAASP
1013
785 O C
7718
WAIT & WEIGHT METHOD:
Situation after pumping 620 strokes:
The gas is expanding allowing the pressure inside bubble to decrease.
Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped.
DP P = ICP - (620 x 27) psi
100
Casing pressure increasing due to the expanding gas is displacing drilling fluid.
CSG P = BHP - (Phmud + Phgas) 785 psi
Shoe pressure is decreasing while gas moves from below the shoe until all gas inside the casing.
Shoe P = BHP - Phopen hole psi
MAASP start increasing from the first gas enter the casing due to change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

144. WAIT & WEIGHT METHOD KILL MUD AT BIT GAS INSIDE CASINGDP
CSG 30
KILL MUD AT BIT
GAS INSIDE CASING
DRILL PIPE PRESSURE
DECREASE TO FCP
CASING PRESSURE
INCREASING
GAS EXPANDING
SHOE PRESSURE
CONSTANT
MAASP INCREASING
1950
1812
MAASP
692
1050 O C
7718
WAIT & WEIGHT METHOD:
Situation after pumping 1812 strokes:
The gas is expanding allowing the pressure inside bubble to decrease.
Drill Pipe Pressure is kept on schedule with 27 psi drop per 100 strokes pumped and reach FCP when kill fluid at bit.
DP P = ICP - (1812 x 27) psi
100
Casing pressure increasing due to the expanding gas is displacing drilling fluid.
CSG P = BHP - (Phmud + Phgas) psi
Shoe pressure constant due to no change in Phopen hole
Shoe P = BHP - Phopen hole psi
MAASP increasing with the same value as the Csg P due to change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

145. WAIT & WEIGHT METHOD KILL MUD AT SHOE GAS INSIDE CASINGDP
CSG 30
KILL MUD AT SHOE
GAS INSIDE CASING
DRILL PIPE PRESSURE
CONSTANT
CASING PRESSURE
INCREASING
GAS EXPANDING
SHOE PRESSURE
DECREASING
MAASP INCREASING
1980
2432
MAASP
692
1080 O C
7641
WAIT & WEIGHT METHOD:
Situation after pumping 2432 strokes:
The gas is expanding allowing the pressure inside bubble to decrease.
Drill Pipe Pressure constant at FCP after kill fluid reach the bit.
DP P = FCP psi
Casing pressure increasing due to the expanding gas is displacing drilling fluid, but slower due to kill fluid is displacing original mud.
CSG P = BHP - (Phmud + Phgas + Phkill mud) 1080 psi
Shoe pressure decreasing as kill fluid moves up the annulus to the shoe.
Shoe P = BHP - Phopen hole psi
MAASP increasing with the same value as the Csg P due to change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

146. WAIT & WEIGHT METHOD KILL MUD INSIDE CASING GAS REACH CHOKEDP
CSG 30
KILL MUD INSIDE
CASING
GAS REACH CHOKE
DRILL PIPE PRESSURE
CONSTANT
CASING PRESSURE
INCREASING
GAS EXPANDING
SHOE PRESSURE
MAASP INCREASING
2178
4800
MAASP
692
1278 O C
7641
WAIT & WEIGHT METHOD:
Situation after pumping 4800 strokes:
The gas is expanding allowing the pressure inside bubble to decrease.
Drill Pipe Pressure constant at FCP after kill fluid reach the bit.
DP P = FCP psi
Casing pressure increasing due to the expanding gas is displacing drilling fluid, but slower due to kill fluid is displacing original mud.
CSG P = BHP - (Phmud + Phgas + Phkill mud) 1278 psi
Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole.
Shoe P = BHP - Phopen hole psi
MAASP increasing with the same value as the Csg P due to change in Ph inside the casing.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

147. WAIT & WEIGHT METHOD KILL MUD INSIDE CASING GAS OUT OF WELLDP
CSG 30
KILL MUD INSIDE
CASING
GAS OUT OF WELL
DRILL PIPE PRESSURE
CONSTANT
CASING PRESSURE
DECREASING
SHOE PRESSURE
MAASP DECREASING
1204
5360
MAASP
692
180 O C
7641
WAIT & WEIGHT METHOD:
Situation after pumping 5360 strokes:
Drill Pipe Pressure constant at FCP after kill fluid reach the bit.
DP P = FCP psi
Casing pressure decreasing while gas is displaced out of the well bore.
CSG P = BHP - (Phmud + Phkill mud) 180 psi
Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole.
Shoe P = BHP - Phopen hole psi
MAASP decreasing while gas is displaced out of the well bore.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

148. WAIT & WEIGHT METHOD KILL MUD AT SURFACE DRILL PIPE PRESSURE CONSTANTDP
CSG 30
KILL MUD AT
SURFACE
DRILL PIPE PRESSURE
CONSTANT
CASING PRESSURE
DECREASING TO ZERO
SHOE PRESSURE
MAASP DECREASING
TO NEW MMASP w/KMW
1027
7200
MAASP
692 O C
7641
WAIT & WEIGHT METHOD:
Situation after pumping 7200 strokes:
Drill Pipe Pressure constant at FCP after kill fluid reach the bit.
DP P = FCP psi
Casing pressure decreasing to 0 psi while kill fluid displace original mud out of the well bore.
CSG P = BHP - Phkill mud 0 psi
Shoe pressure remains constant after kill fluid enter casing due to no change in Phopen hole.
Shoe P = BHP - Phopen hole psi
MAASP decreasing while kill fluid displace original mud out of the well bore.
MAASP = Max Shoe Pressure - Phshoe psi
BHP= 8928 PSI
Pf= 8928 psi

149. WELL # 1 HOLE SIZE HOLE DEPTH TVD/MD CASING 9-5/8” TVD/MD
DRILL PIPE CAP.
HEAVY WALL DRILL PIPE
CAPACITY
DRILL COLLARS 6-1/4”
DRILLING FLUID DENSITY
CAPACITY OPEN HOLE/COLLARS
CAPACITY OPEN HOLE/DRILL PIPE-HWDP
CAPACITY CASING/DRILL PIPE
FRACTURE FLUID DENSITY
SIDPP
SICP
PUMP DISPLACEMENT
RRCP 30 SPM
PIT GAIN
8-1/2 INCH
FEET
9875 FEET
BBL/FEET
600 FEET
BBL/FEET
880 FEET
BBL/FEET
14.0 PPG
BBL/FEET
BBL/FEET
BBL/FEET
16.9 PPG
530 PSI
700 PSI
BBL/STRK
650 PSI
10.0 BBL

150. GMD = ------------------------- GMR = -------------------------
VOLUMETRIC METHOD
MIGRATION DISTANCE
GMD =
P2 - P1
MUD GRADIENT
MIGRATION RATE/HRS
GMR =
GMD x 60
T2 - T1

151. VOLUMETRIC METHOD KEY POINT: Ph Ph
EVERY BARREL OF MUD IN THE WELLBORE REPRESENT
A CERTAIN AMOUNT OF HYDROSTATIC PRESSURE Ph Ph

152. VOLUMETRIC METHOD CHOKE PRESSURE PRESSURE/BARREL WORKING RANGE 50 PSI
SICP + SAFETY FACTOR + WORKING RANGE
PRESSURE/BARREL
PSI/BBL = =
WORKING RANGE
50 PSI
VOLUME TO BLEED =
3.36 BBL =
MUD GRADIENT
W.R.
CAPACITY
PSI/BBL
14 x 0.052 50
14.88

153. VOLUMETRIC METHOD PA P2 - P1 GMD = -------------------------- MWG
10000 ft
12.5 ppg
300 psi
6500 psi
GAS
GMD =
GMR =
Where: GMD = Gas migration distance
MWG = Mud gradient
P1 = Surface pressure at time T1
P2 = Surface pressure at time T2
GMR = Gas migration rate ( feet per hour)
T1 = Time 1 (hour)
T2 = Time 2 (hour)
P2 - P1
MWG
GMD
T2 - T1

154. VOLUMETRIC METHOD PA P2 - P1 GMD = -------------------------- MWG
10000 ft
12.5 ppg
300 psi
6500 psi
GAS
GMD =
GMR =
Where: GMD = Gas migration distance
MWG = Mud gradient
P1 = Surface pressure at time T1
P2 = Surface pressure at time T2
GMR = Gas migration rate ( feet per hour)
T1 = Time 1 (hour)
T2 = Time 2 (hour)
P2 - P1
MWG
GMD
T2 - T1

155. VOLUMETRIC METHOD

156. VOLUMETRIC METHOD PA Pa BHP BOP KILL LINE GAS S I C P P1 P3 Vm
HALLIBURTON
BOP PA
KILL LINE
GAS S I C P P1 P3 Vm
BLEED OFF
LUBRICATE 1 2 3 4 5 6
BHP Pa

157. VOLUMETRIC METHOD BLEED OFF LUBRICATE Gas bubble pressure
Bottom hole pressure
Annular pressure
Drill pipe pressure
TIME
PRESSURE

158. Bull heading
Involves forcing formation fluids back into the formation using surface hydraulics
Usually considered if:
1 Formation fluid cannot be safely handled on surface (eg with H2S)
2 If anticipated formation pressures exceed what can be safely handled
Method usually employed as a last resort

159. Tertiary well control Methods
Cement Plug
Barite plug
Gunk plug

160. Shallow Gas Evaluation & Planning Drill a pilot hole
Heavy mud in ready(1-2 ppg higher)
Controlled ROP
Use of Viscous pills instead of weighted pills
High circulation rates
Float in string

161. Diverting Shallow Gas Open vent line Close Diverter
Switch suctions to heavy mud
Increase pump speed to maximum
Circulate heavy mud round
Flow check
If still positive continue pumping.( if mud finished continue with water)
INTERLOCKED

162. Well Control
Complications

163. Well Control Complications

164. WELL CONTROL COMPLICATIONS

165. Lost Circulation
Formation breakdown
Fractures and Fissures
Bad cement

166. Loss Circulation Categories: Seepage losses (<2bbl/Hr)
Partial losses (5-50 bbl/Hr)
Severe losses (>50bbl/Hr)
Complete losses (unable to maintain fluid level at surface with desired mud weight)

167. Hydrates
Hydrates
________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

168. Hydrates What are hydrates?
Hydrates are a solid mixture of water and natural gas (commonly methane).
Once formed, hydrates are similar to dirty ice .

169. Hydrates Why are they important?
Hydrates can cause severe problems by forming a plug in Well Control equipment, and may completely blocking flow path.
One cubic foot of hydrate can contain as much as 170 cubic feet of gas.
Hydrates could also form on the outside of the BOP stack in deepwater.

170. Hydrates Where do they form? In deepwater Drilling
High Wellhead Pressure
Low Wellhead temperature

171. Hydrates How to prevent hydrates?
Good primary well control = no gas in well bore
Composition of Drilling Fluid by using OBM or Chloride (Salt) in WBM.
Well bore temperature as high as possible
Select proper Mud Weight to minimize wellhead pressure.
injecting methanol or glycol at a rate of gal per minutes on the upstream side of a choke

172. Hydrates

173. Wet And Dry Tripping

174. Tripping Dry
When a length of pipe is pulled from the hole, the mud level will fall.

175. The trip tank is then used to fill up the hole.
Tripping Dry
The volume of fall is equal to the volume of steel pulled from the hole.
The trip tank is then used to fill up the hole.
If 1 barrel of steel is removed from the hole, then using the trip tank, we have to add 1 barrel of mud.

176. 1- Calculate the volume of steel pulled: Length x Metal Displacement
Tripping Dry
1- Calculate the volume of steel pulled:
Length x Metal Displacement
Example:
DP Metal Disp = bbls/ft
Length Pulled 93 feet
Volume Of Steel Pulled:
93 x = bbls

177. Tripping Dry 2- Fill up the hole:
You must pump barrel of mud from the trip tank.
You must investigate ( flow check) if more mud or less mud is needed.

178. It will drop inside the pipe and in the annulus.
Tripping Dry
3- NO FILL UP:
If you fail to fill up the hole, the mud level will drop by the volume of steel pulled.
It will drop inside the pipe and in the annulus.

179. Tripping Dry 3- NO FILL UP: Example: DP Capacity: 0.01776 bbl/ft
Volume Of Steel Pulled:
93 x = bbls
DP Capacity: bbl/ft
Annular Capacity: bbl/ft
The mud will drop inside the pipe and the annular:
= bbl/ft

180. Tripping Dry 3- NO FILL UP: Example Cont’d:
The volume of drop is bbls and will drop in a volume of
bbl / ft,
then the length of drop will be:
0.711 / = feet.
If 93 feet (1 stand) are pulled with no fill up, the mud level will drop by 10.4 feet.

181. Tripping Wet
When a length of pipe is pulled from the hole, the mud level will fall.

182. The trip tank is then used to fill up the hole.
Tripping Wet
The volume of fall is equal to the volume of steel pulled from the hole plus the volume of mud inside this pipe.
The trip tank is then used to fill up the hole.
If 3 barrels of steel and mud are removed from the hole, then using the trip tank, we have to add 3 barrels of mud.

183. 1- Calculate the volume of steel pulled: Length x Metal Displacement
Tripping Wet
1- Calculate the volume of steel pulled:
Length x Metal Displacement
Example:
DP Metal Disp = bbls/ft
Length Pulled 93 feet
Volume Of Steel Pulled:
93 x = bbls

184. 2- Calculate the volume of mud pulled:
Tripping Wet
2- Calculate the volume of mud pulled:
Length x DP Capacity
Example:
DP Capacity = bbls/ft
Length Pulled 93 feet
Volume Of Mud Pulled:
93 x = 1.65 bbls

185. 3- Calculate the total volume of steel and mud pulled:
Tripping Wet
3- Calculate the total volume of steel and mud pulled:
= 2.36 barrels

186. Tripping Wet 4- Fill up the hole:
You must pump 2.36 barrels of mud from the trip tank.
You must investigate ( flow check) if more mud or less mud is needed.

187. It will drop inside the annulus.
Tripping Wet
5- NO FILL UP:
If you fail to fill up the hole, the mud level will drop by the volume of steel and mud pulled.
It will drop inside the annulus.

188. Tripping Wet 5- NO FILL UP: Example: Annular Capacity: 0.0504 bbl/ft
Volume Of Steel and Mud Pulled:
93 x ( ) = 2.36 bbls
Annular Capacity: bbl/ft
The mud will drop inside the annular by:
2.36 / = 46.9 feet

189. It is usefull to pump a slug before tripping.
Pumping a Slug
It is usefull to pump a slug before tripping.
The slug weight being heavier than the mud, a length of pipe will be empty.
The HP is not reduced because the heavier mud will compensate for the empty pipe.

190. The total HP is the same on both sides of the pipe.
Pumping a Slug
The total HP is the same on both sides of the pipe.
HP kmw
HP mud
HP mud

191. Pumping a Slug Example:
If 20 bbls of 12 ppg slug are pumped in a 10,000 ft hole containing 10 ppg mud, what will be the height of empty pipe?
DP capacity = bbl/ft
1- Calculate the height of the slug:
20 / = 1126 ft

192. Pumping a Slug 2- Calculate the HP of the slug:
1126 x 12 x = psi
702.6 psi

193. Pumping a Slug 2- Calculate the HP of the mud in the annulus:
10,000 x 10 x = 5,200 psi
702.6 psi
5,200 psi

194. Pumping a Slug
3- The total hydrostatic beeing the same on both sides, calculate the HP of the mud below the slug:
5, = psi
702.6 psi
5,200 psi
psi

195. Pumping a Slug
4- Calculate the height of mud needed to give psi as a HP:
TVD = / ( 10 x ) = feet
1,126 ft
10,000 ft ft

196. Pumping a Slug 4- Calculate the height of empty pipe
10, ,126 = ft
225.2 ft
1,126 ft
10,000 ft ft