2. 2
Tripping…Why ?
Because 75 % of kick occurs during it.
Types Of Tripping:-
1-Trip In / Run In Hole (RIH):-
To connect pipe together and lower the connected length into
the borehole.
2-Trip Out / Pull Out Of Hole (POOH):-
To pull/remove the drillstring from the wellbore.
Types of POOH:-
Wet: We POOH With Mud inside the string.
Dry: We POOH Without Mud inside the string.
Tripping
5. 5
In (Dry) Tripping:
Volume = Metal Displacement(bbl./ft.) x Length(ft.)
Example:
What’s Volume Required to fill hole if we Pull 5 stand
Drill Pipe Dry?
If Metal Disp. Of Drill Pipe = 0.008 (bbl./ft.),Drill Pipe
Capacity =0.01776 (bbl./ft.) , stand = 90 ft. approx.
Answer: Volume required =0.008 x5x90 = 3.6 bbl.
Tripping
8. 8
Tripping
What’s the Trip Tank?
Tank in the rig with small Capacity (25-45)bbl.
Importance:-
It used to
1-Fill the hole with the equivalent volume of
Metal displacement by trip sheet Calculations.
2-Monitor the well during the trips.
Usually We Fill The hole each 5 stand
*But you’ve to check the pressure drop to avoid kick.
9. 9
How to monitor the well by trip tank?
1-We calculate the volume required to fill the hole in
trip sheet.
2-We start Pump The Mud for ex. 11.6 bbl.
If we have a returned mud before finish pumping 11.6 bbl.
It’s indication of kick occurs.
If we haven’t a returned mud after finish pumping 11.6
bbl.
It’s indication of Loss Circulation.
If we have returned mud @ 11.6bbl………O.K
Tripping
11. 11
KICKS OCCUR WHEN
“ UNDERBALANCE ”
Causes of Kick
Formation Pressure > Hydrostatic Pressure
12. 12
• Failure to keep the hole full
• Low density fluid
• Swabbing
• Surge
• Lost circulation
• Human error / Lack of crew training
• Abnormal pressure
Causes of Kick
21. 22
Effect of Pipe Slugging
FLOW
LINE
RIG
FLOOR
AFTER SLUG HAS
U-TUBED
BACKFLOW TO
TRIP TANK
= VOLUME OF
EMPTY PIPE
FLOW
LINE
RIG
FLOOR
BEFORE SLUG HAS
U-TUBED
FLOW
LINE
RIG
FLOOR
HEAVY SLUG KEEPS
MUD LEVEL INSIDE PIPE
BELOW RIG FLOOR
(Pulling ‘DRY’)
22. 23
Maintain accurate trip logs
How to avoid the kick?
A-Maintain Accurate Trip Sheet
B-Great Concern While POH Wet Trip.
C-Great Concern While POH With BHA.
D-Great Concern while RIH With CSG.
E-Calculation Of Pressure Drop Per Feet
More of 75% of Blow outs incident occur While Tipping .
Failure to keep the hole full
23. 24
• Failure to keep the hole full
• Low density fluid
• Swabbing
• Surge
• Lost circulation
• Human error / Lack of crew training
• Abnormal pressure
Causes of Kick
29. 30
• Failure to keep the hole full
• Low density fluid
• Swabbing
• Surge
• Lost circulation
• Human error / Lack of crew training
• Abnormal pressure
Causes of Kick
31. 32
Main causes:
– Pull pipe too fast
– Balled Up Bit/BHA
– High Viscosity mud
– Tight annulus
– May be associated with drag
All these make it more difficult for mud to move
past the bit to fill space created by pulling drill
string.
Swabbing
32. 33
Surface indications of swabbing
• Swabbing can be recognized by
– incorrect hole fill
– Monitoring the trip tank is of vital
importance
Swabbing
33. 34
Actions to be taken if swabbing is observed
The acknowledged procedure is:-
– Flow check
– If negative, run back to bottom
– Circulate bottoms up (consider taking returns via
the choke)
Swabbing
34. 35
PSI
HP =5000 psi
Swabbing
As The String Is Pulled
Upwards A Reduction In
The BHP Causes
Swabbed Gas To Inter
The Well Bore.
Swabbing pressure=200 psi
BHP = 5000 - 200 = 4800 psi
35. 36
• Failure to keep the hole full
• Low density fluid
• Swabbing
• Surge
• Lost circulation
• Human error / Lack of crew training
• Abnormal pressure
Causes of Kick
36. 37
Surg pressure-200 psi
Surging
Temporary increase of fluid
hydrostatic while tripping
in as mud tries to move up
around the bit
Surge Pressure
BHP = 5000+200= 5200 psi
PSI
HP = 5000 psi
37. 38
Main causes:
– Run the pipe too fast
– High Viscosity mud
– Tight annulus
All these make it more difficult for mud to move
up around the BHA and created by Run drill
string.
Surge Pressure
39. 40
What do we mean by porosity?
Porosity is the empty (or VOID) space within a rock where fluid can be.
Porosity is measured in percent, the higher the porosity, the more fluid in the
formation.
Formations may have high or low porosity, but most formations will have
some porosity.
Porosity
41. 43
Permeability is the ability of a formation (or any material) to
allow fluid to flow.
For example, polythene has no permeability, whereas
material such as denim has a high permeability.
Permeability is measured in millidarcies.
Formations may vary widely in their permeability.
A formation may have no permeability because of the nature
of the formation itself, or because it is enclosed in a “trap”.
What is Permeability?
44. 46
• Failure to keep the hole full
• Low density fluid
• Swabbing
• Surge
• Lost circulation
• Human error / Lack of crew training
• Abnormal pressure
Causes of Kick
48. 50
• Failure to keep the hole full
• Low density fluid
• Swabbing
• Surge
• Lost circulation
• Human error / Lack of crew training
• Abnormal pressure
Causes of Kick
49. 51
Human Error
• Lack of Training
Drills, Class room Training
• Poor Communication
• Poor Planning
50. 52
• Human Error - Not keeping the mind on the
job! Most blowouts occur with some form of
human error. Through proper training and
work habits, the incidents of human error can
be reduced.
• Not filling the hole properly:
• Swab and Surge
• Fluid dilution
Human Error
51. 53
• Failure to keep the hole full
• Low density fluid
• Swabbing
• Surge
• Lost circulation
• Human error / Lack of crew training
• Abnormal pressure
Causes of Kick
52. 54
• FORMATION FLUID GRADIANT IS
GREATER THAN RESSURE GRADIANT
OF SEA WATER.
WHAT IS ABNORMAL PRESSURE?
• 99.99+% OF FORMATION FLUIDS ARE WATER
• FORMATION WATER EQUALS
8.9 PPG (AVERAGE) = 0.465 PSI/FT
• IF FORMATION FLUIDS ARE SQUEEZED THEN
FLUID PRESSURE INCREASES.
54. 56
Abnormal Pressure
Surface
4000’ TVD
Well A
FPA = 1860 psi
FPA = 0.465 psi/ft x 4000’
Lower Part of Anticline
Well B
3000’ TVD
Upper Part of Anticline
FPB = 1860 - (0.1 psi/ft x 1000’)
FPB = 1760 psi
Gas
Oil / Water
EMWA = 1860 / (0.052 x 4000)
EMWA = 9.0 ppg
EMWB = 1760 / (0.052 x 3000)
EMWB = 11.3 ppg
1-Gas Cap
55. 57
• As shown in the above slide, at 4000’ the
formation pressure at the gas-water contact is
normal and equal to 0.465 psi/ft x 4000’ = 1860
psi. However, at the top of the structure (3000’),
the formation is over pressured and
approximately equal to 1760 psi.
• Note: the pressure at 4000’ (1860 psi) less a
1000’ gas column (1000’ x 0.1 gas gradient)
equals 1760 psi.
• The mud weight required at 3000’ to balance this
formation is 1760/(0.052 x 3000’) = 11.3 ppg.
Abnormal Pressure
1-Gas Cap
56. 58
PROBLEM:
• Drilling into a gas cap may require higher mud
weights than for other wells in the same
reservoir. The gas cap is 1000’. Assuming the
same pressure gradient.
Abnormal Pressure
1-Gas Cap
57. 59
SOLUTION:
• Development wells - Review reservoir top
mapping with Geology and calculate required
mud weights.
• Exploration wells - Review reservoir top
mapping with Geology/Geophysisist and
attempt to identify existence of gas cap on
seismic.
Abnormal Pressure
1-Gas Cap
58. 60
Surface
4000’ TVD
Well A
FPA = 1860 psi
FPA = 0.465 psi/ft x 4000’
Lower Fault Block
Well B
3000’ TVD
Upper Fault Block
FPB = 1860 psi
EMWB = 11.9 ppg
Gas
Oil / Water
EMWB = 1860 / (0.052 x 3000)
EMWA = 1860 / (0.052 x 4000)
EMWA = 9.0 ppg
2-Faulting
Abnormal Pressure
59. 61
PROBLEM:
• Drilling into a faulted situation may require
higher mud weights than for other wells in the
same reservoir. In this case, the upper fault
block has the same formation pressure as the
lower fault block this will produce a higher
needed mud weight for the upper fault block
than anticipated.
2-Faulting
Abnormal Pressure
60. 62
SOLUTION:
• Development wells - Review reservoir top
mapping with Geology and calculate required
mud weights.
• Exploration wells - Review reservoir top
mapping with Geology/Geophysisist and
attempt to identify existence of gas cap on
seismic.
2-Faulting
Abnormal Pressure
62. 64
PROBLEM:
Under compacted formations, with sufficient
permeability may kick when penetrated.
SOLUTION:
• Observe and act upon signs of drilling into
transition zone above.
Increased ROP Cuttings size Increased torque
Increased drag Connection gas
Abnormal Pressure
3-Undercompacted Formation
63. 65
9,300’ 12,300’
Normal Gradient at 9300’
FP= .465 psi/ft x 9,300’
FP= 4,325 psi or 9.0 ppg
Artesian Effect
FP= 0.465 psi/ft x 12,300’
FP= 5,720 psi or 11.9 ppg
4- Artesian Effect
Abnormal Pressure
64. 66
• The artesian effect comes from a reservoir that
is in communication with a column of water at
a higher elevation than mean ground level.
This column of water is charging the reservoir
which produces higher than expected
formation pressure.
4- Artesian Effect
Abnormal Pressure
66. 68
PROBLEM:
Applying EOR in the Reservoir Area which is
results from poor communication between
company Departments. (Geology, Drilling,
Reservoir)
SOLUTION:
• Review reservoir extension with
Geology/Geophysisist, communicate with the
other department to make sure there’s no EOR
applied on the same reservoir.
5- EOR Technology
Abnormal Pressure
67. 69
Failure to keep the hole full
Low density fluid
Swabbing
Surge
Lost circulation
Human error / Lack of crew training
Abnormal pressure:
• Anticline gas cap
• Uplift / Faulting
• Under compaction
• Artesian effect
• Enhanced oil recovery (EOR)
Causes of Kick
Editor's Notes
13
16
15
Swabbing is a temporary drop in BHP as the string is pulled upwards.
This drop in pressure is caused by the friction of the mud moving downwards past the pipe.
This lecture starts by examining the causes of kicks and then transitions into Detection of Kicks.
The artesian effect comes from a reservoir that is in communication with a column of water at a higher elevation than mean ground level. This column of water is charging the reservoir which produces higher than expected formation pressure.
