Part 3: Calculations

Version: Apr - 20

[193]
[194]
 Contents
1. Static and Dynamic Pressures.................................................... 197
Bottom-hole pressure Change ............................................... 197
Dynamic Pressure.................................................................. 205
2. Leak-Off Test ............................................................................ 207
3. Tripping .................................................................................... 211
4. Slug............................................................................................ 217
5. Volumetric Method/Stripping.................................................... 219
6. Various ...................................................................................... 223
7. Model Answers .......................................................................... 229

[195]
[196]
1. Static and Dynamic Pressures

Bottom-hole pressure Change

1.1 When drilling a 26 inch surface hole at 1200 feet True Vertical Depth (TVD),
the formation pressure is measured as exactly 601 psi.
How would you describe this formation pressure?

a. Above normal
b. Below normal
c. Normal

1.2 If the gas/water contact in a normally pressured reservoir is at 3950 feet, what
is the pressure at the top of the reservoir at 3470 feet? (There is a gas gradient
0.1 psi/ft, formation water gradient of 0.464 psi/ft.

a. 1350 psi
b. 1630 psi
c. 1785 psi
d. 1870 psi

[197]
1.3 There is a total power loss.
Partial losses are measured at 10 bbl/hour
Capacity of Annulus and Pipe contents – 0.073 bbl/ft
Drilling fluid density – 10.8 ppg
What will be the reduction in Bottom Hole Pressure (BHP) after 3 hours if the
hole cannot be filled?

a. 231 psi
b. 300 psi
c. 420 psi
d. 77 psi

1.4 Calculate bottom hole pressure using the information below:

Well Measured Depth (MD) 18575 feet
Well True Vertical Depth (TVD) 16281 feet
Shoe True Vertical Depth (TVD) 12875 feet
Maximum Allowable drilling fluid density 17.8 ppg
Current drilling fluid density 14.7 ppg

a. 11917 psi
b. 12445 psi
c. 14199 psi
d. 9842 psi

[198]
1.5 A well 10400 ft. TVD is filled with 9.2 ppg. brine.

The plan is to run in the hole to 5100 ft. TVD, 5400 ft. MD and displace with
drill water 8.4 ppg.
What is hydrostatic pressure at 10400 ft. when the drill water is circulated back
to surface?

a. 5452 psi.
b. 4640 psi.
c. 4763 psi.
d. 4975 psi.

1.6 Pressure recorders located below the drill stem test tools show that the swab
pressure is 250.
Drilling fluid density in the hole is 10 ppg. .
Top of reservoir is at 9500 feet.
If the well does not flow when the pipe is static, what would the reservoir
pressure have to be at this swab pressure?

a. 3800 psi.
b. 5800 psi.
c. 4690 psi.
d. 4940 psi.

1.7 A well is of TVD 5000 FT and MWT 9.8 PPG.

The cutting inside the annulus increased the mud weight by 0.2 PPG.
What is the final BHP if the pumps were stopped?

…………………… psi

[199]
 1.8 When drilling at 11111 ft. MD, 10780 ft. TVD, formation pressure is expected to
be 6334 psi.
A 200 psi trip margin must be included in the drilling fluid density.
What drilling fluid density is required?

……………………. ppg.

1.9 Formation pressure at 14650 ft. TVD is balanced by 12.3 ppg drilling fluid.

A 200 psi trip margin must be included in the drilling fluid density.

What drilling fluid density is required?

a. 12.0 ppg.
b. 12.1 ppg.
c. 12.5 ppg.
d. 12.6 ppg.

1.10 Before pulling out of hole, the drilling fluid density is increased by 0.5 ppg
trip margin.
With this trip margin, calculate the increase in Bottom Hole Pressure (BHP).

Well Data:

Well depth (TVD): 8300 ft

Well depth (MD): 8900 ft
Drilling fluid density without trip margin: 11.2 ppg
Drill pipe capacity: 0.01782 bbl/ft
Drill pipe metal displacement: 0.00751 bbl/ft

……………………………………..psi

[200]
1.11 The driller fails to fill the hole when pulling out of the well.
The drilling fluid level drops 580 feet causing the well to flow.

Current drilling fluid density: 11.9 ppg.

True Vertical Depth (TVD): 9500 feet

What is the Bottom Hole Pressure (BHP) when the well starts to flow?

…………………………………….psi

1.12 While drilling, there are severe losses. After the pumps are stopped, the
drilling fluid level drops far below the flowline.
The well is then filled to the top with water.

Drilling fluid density: 11.3 ppg

Water density: 8.6 ppg
Volume of water filled into the annulus is 200 feet.

What is the decrease in hydrostatic Bottom Hole Pressure (BHP)?

a. 118 psi
b. 207 psi
c. 28 psi
d. 89 psi

1.13 Calculate the fluid density if the fluid gradient is 0.884 psi/ft

…………………… ppg

[201]
1.14 What is the reduction in Bottom Hole Pressure (BHP) if the drilling fluid level
dropped by 800 feet with a density of 10.5 ppg?

…………………… psi

1.15 How much will the Bottom Hole Pressure (BHP) decrease if the annular fluid
drops by 100 feet? The Drilling fluid density is 15 ppg.

……………………psi

1.16 Calculate bottom hole hydrostatic pressure using the information below:

Well Measured Depth (MD): 18575 feet

Well True Vertical Depth (TVD): 16281 feet
Shoe True Vertical Depth (TVD): 12875 feet
Maximum allowable drilling fluid density: 17.8 ppg
Current drilling fluid density: 14.7 ppg

a. 11917 psi
b. 12445 psi
c. 14199 psi
d. 9842 psi

[202]
1.17 On a trip out of hole, the hole was filled correctly while pulling drill pipe.
The hole fill was stopped and the complete BHA was pulled dry

Hole size: 12 ¼ inch

Casing shoe depth: 1500 feet
Length of BHA: 400 feet
Internal capacity of BHA: 0.009 bbl/ft
Internal capacity of casing: 0.146 bbl/ft
Steel displacement of BHA: 0.070 bbl/ft
Capacity between BHA and Casing: 0.067 bbl/ft
Drilling fluid density: 10 ppg

What is the expected decrease in Bottom Hole Pressure (BHA)?

a. 100 psi
b. 188 psi
c. 205 psi
d. 210 psi

1.18 A well is drilled to a depth of 8200 ft. TVD and the current density of the
drilling mud is 12.5 ppg.
What is the Bottom Hole Pressure (BHP) if 580 psi pressure is applied from
surface with BOP closed?

a. 4750 psi.
b. 5076 psi.
c. 5330 psi.
d. 5910 psi.

[203]
[204]
Dynamic Pressure
1.19 A vertical well is 6020 feet deep and filled with 11.5 ppg mud.
While circulating at 80 SPM the friction losses in the well system are as follows:

200 psi pressure loss through surface equipment.

680 psi pressure loss in drill string.
1570 psi pressure loss through bit nozzles.
110 psi pressure loss in annulus.

What is the Bottom Hole Pressure (BHP) when the pumps are running at 80 SPM?

……………………psi

1.20 At 40 SPM with 10 ppg fluid, the pump pressure is 1000 psi.
What is the pump pressure if the rate is decreased to 25 SPM and the fluid
density is increased to 11.4 ppg?

a. 390 psi
b. 445 psi
c. 550 psi
d. 710 psi

[205]
[206]
2. Leak-Off Test
2.1 Calculate the MAASP using the information below:

Well Data:
Hole depth (MD): 13600 ft.
Hole depth (TVD): 12800 ft.
Casing shoe depth (MD): 9100 ft.
Casing shoe depth (TVD): 8600 ft.
Drilling Fluid density: 11.5 ppg.
Formation strength gradient: 0.928 psi/ft.

……………………………. psi

2.2 Calculate the MAASP using the following information:

Well Data:

Casing shoe depth (TVD): 8000 ft.

Maximum allowable drilling fluid density: 19 ppg.
Density of drilling fluid in hole: 12 ppg.

………………………………. psi.

2.3 13 inch surface casing is set and cemented at 3126 ft. TVD.
The cement is drilled out together with 15 ft. of new hole, using 10.2 ppg. drilling
fluid and a leak off pressure of 670 psi measured.
What is the maximum allowable annulus surface pressure with 11.4 ppg. drilling
fluid at 6500 ft. TVD?

………………………………. psi.

[207]
2.4 Calculate the formation strength at the casing shoe using the following
information?

Well Data:
Casing Shoe Depth (TVD) 6000 ft
Drilling Mud Density 12 ppg
MAASP 1300 psi

……………………psi

2.5 Calculate the maximum allowable mud weight using the following:

Well Data:
Casing shoe depth: 8000 ft, TVD
Leak off test pressure at pump: 1500 psi
Density of drilling mud in hole: 10.4 ppg

……………………ppg

2.6 After conditioning the well with 12 ppg mud, the Driller does a Leak-Off Test
(LOT) at 5000 feet True Vertical Depth (TVD), and records a LOT pressure of
875 psi.
Calculate the maximum allowable mud density.

a. 17.1 ppg
b. 13.2 ppg
c. 14.5 ppg
d. 15.3 ppg

[208]
2.7 Given that the Formation strength is 1900 psi, the Casing shoe TVD is 2000 ft,
the Annulus Pressure Losses (APL) is 250 psi.

Calculate the maximum mud density that can be used/circulated, without

causing mud losses.

……………………ppg

2.8 After a leak-off test using 10.3 ppg test fluid, casing shoe fracture pressure is
calculated at 5730 psi.

Maximum anticipated Annular Pressure Loss (APL) at drilling rate for the
section is 350 psi
Casing Shoe True Vertical Depth (TVD) is 8640 feet

What is the maximum drilling fluid density that can be circulated without losses?

…………………… ppg

2.9 The deepest casing shoe in a well is set at 5675 feet MD, 5125 feet TVD.

If the mud density is increase by 1.2 ppg, how will this affect MAASP?

a. It will be 320 psi higher.

b. It will be 320 psi lower.
c. It will be 354 psi higher.
d. It will be 354 psi lower.

[209]
2.10 Leak-off Test Data:

CSG. Shoe MD: 6090 ft.

CSG. Shoe TVD: 5560 ft.
Surface Leak off pressure at 6090 ft.: 380 psi
Drilling fluid density: 12.8 ppg

Drilling continues after the leak off test, and later there is a kick.

Kick Data:

Hole depth MD: 7810 ft

Hole depth TVD: 6315 ft
SIDPP: 140 psi
SICP: 180 psi
Pit gain: 8 bbl.
Drilling fluid density: 13.5 ppg

Calculate the working margin between the MAASP and the initial shut in
casing pressure.

a. 18 psi
b. 47 psi
c. 87 psi
d. No margin

[210]
3. Tripping
3.1 What is the bottom hole hydrostatic pressure reduction when pulling 1000 ft. of
5" drill pipe dry without filling the hole (no mud returning to the well)?

Well Data:

Casing capacity: 0.1522 bbl./ft.

Drill pipe capacity: 0.0178 bbl./ft. Drill pipe steel
displacement: 0.0076 bbl./ft.
Mud density: 11 ppg

a. 51 psi
b. 61 psi
c. 30 psi
d. 101 psi

3.2 Well Data:

Current drilling fluid density: 10 ppg
Metal displacement: 0.0075 bbl./ft.
Pipe Capacity: 0.0178 bbl./ft.
Casing Capacity: 0.0758 bbl./ft.
Stand length: 93 ft.

What is the drop in hydrostatic pressure if 10 stands of pipe are pulled ‘dry’
from the well?

…………………… psi

[211]
3.3 Well Data:
Current fluid density: 10 ppg
Metal displacement: 0.0075 bbl./ft.
Pipe capacity: 0.0178 bbl./ft.
Casing capacity: 0.0758 bbl./ft.
Stand length: 93 ft.

What is the drop in hydrostatic pressure if 10 stands of pipe are pulled ‘wet’
from the well?

……………………psi

3.4 A vertical well is drilled to a depth of 8000 ft.

Overbalance: 160 psi
Mud gradient: 0.73 psi/ft.
Casing capacity: 0.157 bbl./ft.
Drill pipe metal displacement: 0.008 bbl./ft.

How many complete stands can the Driller pull dry before the overbalance is
lost?
(One stand equals 90 ft.)

a. 45 stands
b. 46 stands
c. 47 stands
d. 48 stands

[212]
3.5 Given the following data:

Hole TVD: 8680 ft.

5’’ Drill Pipe Capacity: 0.0778 bbl/ft.
6.5’’ Drill collar Capacity: 0.0077 bbl/ft. BHA length: 774 FT
Surface line Capacity 12 BBLs
Mud Pump Displacement 0.12 BBL/stroke.
Pump Speed (rate) 30SPM

A kick was taken after pulling 930 ft. of 5’’ drill pipe off bottom.

How long would it take to circulate the Heavy Mud From the active pumps to the bit?

……………………minutes

3.6 Given the following data:

Hole TVD: 8680 ft.

5’’ Drill Pipe Capacity: 0.0778 bbl/ft.
6.5’’ Drill collar Capacity: 0.0077 bbl/ft. BHA
length: 774 FT
Surface line Capacity 12 BBLs
Mud Pump Displacement 3.6 bbl/min.
Pump Speed (rate) 30 SPM

A kick was taken after pulling 930 ft. of 5’’ drill pipe off bottom.

How long would it take to circulate the Heavy Mud From the active pumps to the bit?

……………………minutes
[213]
3.7 A well is shut in with bit 10 stands 930 ft. off bottom.
What is the bit to shoe strokes if a pump capacity of 0.12 bbl./stroke is used to
circulate the well?

Well Data:
Well depth: 9750 ft. MD (8560 ft. TVD)
Casing Shoe: 8076 ft. MD (7076 ft. TVD)
Bottom Hole Assembly (BHA) length: 744 ft.
Open Hole (OH) / BHA Capacity: 0.102 bbl./ft.
OH/Drill pipe (DP) Capacity: 0.132 bbl./ft.

a. 471 strokes
b. 609 strokes
c. 632 strokes

3.8 A well is shut in with bit 10 stands 930 ft. off bottom.
What is the pump to bit strokes if the pump capacity of 0.12 bbl./stroke is used
to circulate the well?

Well data:
Well depth: 9750 ft. MD (8560 ft. TVD)
Bottom Hole Assembly (BHA) length: 744 ft.
Capacity of HP surface line: 12 bbl.
BHA Capacity: 0.0078 bbl./ft.
Drill pipe (DP) Capacity: 0.0178 bbl./ft.

a. 1159 strokes
b. 1246 strokes
c. 1346 strokes

[214]
3.9 The Driller pulls three stands of drill collars from a well (dry).

Drill collar capacity: 0.0073 bbl/ft

Drill collar metal displacement: 0.0370 bbl/ft
How many barrels of drilling fluid should the Driller pump into the well?
(One stand = 90’)

……………………bbl.

3.10 Calculate the volume of drilling fluid required to fill the hole per stand when
pulling ‘wet’, with no drilling fluid returns to the well.

Well Data:
Drill Pipe Capacity: 0.0178 bbl./ft.
Drill Pipe Metal Displacement: 0.0082 bbl./ft.
Average Stand Length: 93 ft.

a. 0.76 bbl.
b. 1.65 bbl.
c. 2.42 bbl.
d. 9.28 bbl.

[215]
[216]
4. Slug
4.1 A driller prepares to pull out of the hole and line up to the slug pit.

The driller then pumps a 20 bbl heavy slug, followed by 10 bbl of drilling fluid
from the active pit.

Well Data:
Depth of hole (TVD): 9200 ft.
Drilling fluid density: 12.2 ppg.
Heavy slug density: 14.5 ppg
Drill pipe capacity: 0.01776 bbl./ft.
Surface line volume: 6 bbl.

How far will the fluid level in the string drop when the well has equalized?

a. 1143 feet
b. 183 feet
c. 213 feet
d. 263 feet

4.2 The Driller pumps a 25 bbl. Heavy slug with a density of 12 ppg before pulling
out of the hole from 10500 ft. True Vertical Depth (TVD). The level in the pipe
decreases falls by 215 ft.

What is the change in Bottom Hole Pressure (BHP) if the original drilling fluid
density was 10.4 ppg?

a. 0 psi
b. 1180 psi
c. 140 psi
d. 20 psi
[217]
[218]
5. Volumetric Method/Stripping
5.1 A vertical well is shut in after there is a gas influx.

The kill operation is delayed, and the influx starts to migrate.

Because of this migration, both drill pipe pressure and casing pressure increase by 300 psi.

Well Data:
Well depth: 10000 ft.
Casing shoe depth: 6000 ft.
Drilling fluid density: 11.7 ppg
Open hole/drill pipe capacity: 0.060 bbl./ft.
Casing/drill pipe capacity: 0.065 bbl./ft.

NOTE: Assume there is only drill pipe in the well.

Kick Data:
Original shut in stabilized drill pipe pressure: 800 psi
Original shut in stabilized casing pressure: 1050 psi
Original kick volume: 30 bbl.

How many barrels of drilling fluid should be bled from the well to arrive at the
original bottom hole pressure, before gas migration?

a. 1.31 bbl.
b. 1.32 bbl.
c. 1.36 bbl.
d. 2.16 bbl.

[219]
5.2 A well is shut in after a kick has been taken.

SIDPP 600 psi

SICP 1000 psi

After 15 minutes the pressure has risen 100 psi on both gauges. The mud density
is 15 ppg and the influx gradient is 0.1 psi/ft.

Approximately how many feet per hour is the gas bubble migrating?

a. 129 ft./hr.
b. 1400 ft./hr.
c. 200 ft./hour
d. 513 ft./hour

[220]
5.3 A vertical well with a surface BOP stack has been shut in after a gas kick.

The surface pressures are as follows:

Shut in Drill Pipe Pressure (SIDPP) 530 psi
Shut in Casing Pressure (SICP) 680 psi
Mud density in the well 12.8 ppg

The well is left shut in for some time, during which the gas migrates 600 feet up the well.
What will be the expected pressures at surface?

a. Drill pipe pressure – 530 psi, casing pressure – 1080 psi

b. Drill pipe pressure – 530 psi, casing pressure – 680 psi
c. Drill pipe pressure – 930 psi, casing pressure – 1080 psi
d. Drill pipe pressure – 930 psi, casing pressure – 680 psi

[221]
[222]
6. Various
6.1 Whilst drilling a horizontal well a fault is crossed and a kick is taken.

The well is shut in.

Calculate the mud density required to kill the well using the data below:

Well Data:
Depth at start of horizontal section: MD 6500 ft. TVD 4050
Depth at time of kick: MD 10500 TVD 3970
Length of horizontal section: 4000 ft.
Mud density: 11.2 ppg

Kick Data:
Shut In Drill Pipe Pressure: 150 psi
Shut In Casing Pressure: 150 psi

……………………ppg

[223]
6.2 While drilling through a fault in the horizontal section of a well, a kick is taken
and the well shut in.

Calculate the new mud density required to kill the well using the data below.

Well Data:
Measured depth at start of horizontal section: 7690 ft.
Measured depth at time of kick: 13680 ft.
True vertical depth at start of horizontal: 5790 ft.
True vertical depth at time of kick: 5820 ft.
Length of horizontal section: 5990 ft.
Mud density: 12.8 ppg

Kick Data:
Shut In Drill Pipe Pressure 230 psi
Shut In Casing Pressure 240 psi

a. 13.1 ppg
b. 13.4 ppg
c. 13.6 ppg
d. 13.7 ppg

[224]
6.3 A well is shut in after a kick and will be killed using the Wait and Weight
Method.

Pre-recorded data:
True Vertical Depth (TVD) of well: 10000 ft.
Total string volume: 1400 strokes
Total annulus volume: 5700 strokes

Kill rate circulating data:

At 30 SPM and 12.0 ppg mud weight: 520 psi

Kick data:
Shut In Drill Pipe Pressure (SIDPP): 480 psi
Shut In Casing Pressure (SICP): 650 psi
Drilling fluid density in the well: 12.0 ppg

What is the required kill fluid density?

a. 12.8 ppg
b. 13.0 ppg
c. 13.2 ppg
d. 13.3 ppg

[225]
6.4 A vertical well with a surface BOP stack is shut in after a gas kick.

The bit is 500 feet off bottom and the influx is calculated to be on bottom.
Shut in Drill Pipe Pressure (SIDPP) is 250 psi.

What will the Shut In Casing Pressure (SICP) be?

a. Zero
b. 250 psi
c. 750 psi

6.5 A well is shut in after a kick and will be killed using the Wait and Weight Method.

Pre-recorded data:
True Vertical Depth (TVD) of well: 10000 ft.
Total string volume: 1400 strokes
Total annulus volume: 5700 strokes

Kill rate circulating data: At 30 SPM is 520 psi

Kick data:
Shut-In Drill Pipe Pressure (SIDPP): 480 psi
Shut In Casing Pressure (SICP): 650 psi
Drilling fluid density in the well: 12.0 ppg

What is the Final Circulating Pressure (FCP) at 30 SPM?

a. 564 psi
b. 607 psi
c. 720 psi
d. 752 psi
[226]
6.6 The well is shut in after a kick, and will be killed using the Wait and Weight Method.

Kill rate circulating date: At 30 SPM is 520 psi

Shut-in data:
Shut In Drill Pipe Pressure (SIDPP): 480 psi
Shut In Casing Pressure (SICP): 650 psi
Drilling fluid density in the well: 12.0 ppg

Calculate the Initial Circulating Pressure (ICP) at 30 SPM.

a. 1000 psi
b. 1070 psi
c. 1130 psi
d. 1170 psi

[227]
[228]
Model Answers

1.1 A
Formation Pressure Gradient = Pressure / Depth
= 601 / 1200
= 0.5 psi/ft. > 0.465 psi/ft.

1.2 C
Pressure at the top of the reservoir = Pressure at the gas/water contact – Gas hydrostatic
= (3950 x 0.464) – {(3950-3470) x 0.1}
= 1832.8 – (480 x 0.1)
= 1832.8 – 48
= 1784.8 psi

1.3 Reduction in Hydrostatic pressure = Level Drop x Mw x 0.052

= (10 bbl./hr. x 3 hours / 0.073) x 10.8 x 0.052
= 410.958 x 10.8 x 0.052
= 230.79 psi

1.4 Bottom Hole Pressure = Mw x Well TVD x 0.052

= 14.7 x 16281 x 0.052
= 12445 psi

1.5 C

1.6 Expected Reservoir Pressure = Hydrostatic Pressure – Swab Pressure

= (9500 x .052 x 10) - 250
= 4940 - 250
= 4690 psi

[229]
1.7 Final Bottom-hole pressure = (Mud density + cuttings density) x .052 x TVD
= (9.8 + 0.2) x .052 x 5000
= 10 x .052 x 5000
= 2600 psi

1.8 11.65 ppg

1.9 D

1.10 Increase in BHP = Increase in Trip Margin x .052 x TVD

= 0.5 x .052 x 8300
= 215- 216 psi

1.11 Bottom-hole pressure = New drilling fluid level x .052 x Mud density
= (9500 – 580) x .052 x 11.9
= 8920 x .052 x 11.9
= 5519.69 – 5520 psi

1.12 Decrease in hydrostatic pressure = (Mud density – Water density) x water height x 0.052
= (11.3 - 8.6) x 200 x 0.052
= 28 psi

1.13 Mud density = Mud gradient / .052

= .884 / .052
= 17 ppg

[230]
1.14 Reduction in BHP = Reduction in Hydrostatic pressure
= Reduction in drilling fluid level x .052 x Mud density
= 800 x .052 x 10.5
= 436.8 – 437 psi

1.15 BHP drop = Level drop x Mw x 0.052

= 100 x 15 x 0.052
= 78 psi

1.16 Hydrostatic Pressure = Well TVD x .052 x Mud density

= 16,281 x .052 x 14.7
= 12,445.19 psi

1.17 A
Level drop = Length of BHA × Metal Displacement ÷ Casing capacity (Eq. 21)
= 400 × 0.070 ÷ 0.146
= 191.78 ft.
BHP drop = Level drop x Mwt. x 0.052
= 191.78 x 10 x 0.052
= 99.72 ≈ 100 psi.

1.18 D

1.19 BHP while circulating = Hydrostatic Pressure + APL

= (6020 x 0.052 x 11.5) + 110
= 3709.96 - 3710 psi

1.20 Equations 9 and 10

New Pump pressure = Old pump pressure x (New Mw / Old Mw) x (New SPM / Old
Spm)2
= 1000 x (11.4 / 10) x (25 /40)2
= 445 psi
[231]
2.1 2817 psi – 2838 psi

2.2 2912 psi

2.3 471 psi – 474 psi

2.4 Formation Strength = MAASP + Hydrostatic Pressure above casing shoe

= 1300 + (6000 x .052 x 12)
= 1300 + 3744
= 5044 psi

2.5 Maximum Allowable Mud density = Equation Number 11

= (1500 / 8000 / .052) + 10.4
= 14 ppg

2.6 D
Maximum Mud density = Test Mud Weight + [LOT pressure / (Shoe TVD x 0.052)]
= 12 + {875 / (5000 x 0.052)}
= 12 + (875 / 260)
= 15.36 ppg

2.7 Maximum Allowable Mud density with APL = (Formation Strength – APL) / (TVD x .052)
= (1900 – 250) / (2000 x .052)
= 1650 / 104
= 15.8 – 15.86 ppg

[232]
2.8 Fracture Pressure including safety margin = Fracture pressure at test – APL
= 5730 – 350
= 5380 psi
Maximum fluid density for circulation = Fracture pressure with safety / (Shoe TVD x
0.052)
= 5380 / (8640 x 0.052)
= 11.9 - 11.97 ppg

2.9 B
MAASP change = Hydrostatic Pressure change above casing shoe
= Mud weight change above casing shoe x .052 x TVD
= +1.2 x .052 x 5125
= +319.8 psi
The hydrostatic increased, then the MAASP should decrease by 319.8 – 320 psi

2.10 D
Maximum Mud weight = Mud weight at test + [LOT pressure / (Shoe TVD x 0.052)]
= 12.8 + {380 / (5560 x 0.052)
= 14.11 ppg
MAASP with mud weight 13.5 ppg = (Maximum Mw – Current Mw) x Shoe TVD x 0.052
= (14.11 – 13.5) x 5560 x 0.052
= 177 psi
Safety Margin = MAASP – SICP
= 177 – 180
= -3 psi (No margin)

3.1 Pressure drop after pulling dry pipe = Equation Number 19 x Length of pipe
= (11 x .052 x .0076) / (.1522 - .0076)x 1000
= (.0043472 / .1446) x 1000
= 30 – 30.06 psi

[233]
3.2 Pressure drop after pulling dry pipe = Equation Number 19 x Length of pipe
= (10 x 0.052 x 0.0075) / (0.0758 – 0.0075) x (10 x 93)
= (0.0039 / 0.0683) x 930
= 53 - 53.1 psi

3.3 Formula #20:

Pressure Drop = (Mw x 0.052 x Closed End) / (Casing Capacity – Closed End)
Closed End = Metal displacement + Internal capacity
= 0.0075 + 0.0178
= 0.0253 bbl./ft.
Pressure Drop = (10 x 0.052 x 0.0253) / (0.0758 – 0.0253)
= 0.013156 / 0.0505
= 0.26 psi/ft.
Total pressure drop = 0.26 x 10 stands x 93 feet = 241.8 – 242 psi

3.4 45 Stands

3.5 Time to circulate from pumps to bit = Strokes pumped from pumps to bit / Pump Speed
*Strokes Pumped = Volume pumped / Pump Output
*Volume Pumped = Capacity of surface line + Capacity of drill string
= 12 + Drill Pipe capacity + BHA capacity
= 12 + ((Hole MD – Length pulled- BHA length) x .0778) + (.0077*774)
= 12 + ((8680 - 930 - 774) x .0778) + 5.9598
= 12 + (6976 x .0778) + 5.9598
= 12 + 542.7328 + 5.9598
= 560.6926 bbls
*Strokes Pumped = 560.6926 / .12

= 4672-4673 strokes
*Time = 4673 /
30
= 155.7 – 156 minutes

[234]
3.6 Time to circulate from pumps to bit = Strokes pumped from pumps to bit / Pump Speed
*Strokes Pumped = Volume pumped / Pump Output
*Volume Pumped = Capacity of surface line + Capacity of drill string
= 12 + Drill Pipe capacity + BHA capacity
= 12 + ((Hole MD – Length pulled- BHA length) x .0778) + (.0077*774)
= 12 + ((8680 - 930 - 774) x .0778) + 5.9598
= 12 + (6976 x .0778) + 5.9598
= 12 + 542.7328 + 5.9598
= 560.6926 bbls
*Time = 560.6926 / 3.6

= 155.7 – 156 minutes

3.7 Bit To shoe strokes = Open hole volume / pump output

= (BHA length x BHA/OH capacity + drill pipe length x OH/DP capacity) /
POP
= ( 744 x 0.102 + (9750 – 8076 – 930 – 744) x 0.132) / POP
= (75.888 + 0) / 0.12
= 632 strokes

[235]
3.8 C
Pump to bit strokes = Surface line strokes + drill pipe strokes + BHA strokes
Drill pipe strokes = (Drill pipe length x drill pipe capacity) / pump
output
= ((9750 – 744 – 930) x 0.0178) / 0.12
= (8076 x 0.0178) / 0.12
= 143.752 / 0.12
= 1197 strokes
BHA strokes = (BHA length x BHA capacity) / Pump Output
= (744 x 0.0078) / 0.12
= 48 strokes
Surface line strokes = Surface line volume / Pump Output
= 12 / 0.12
= 100 strokes
Pump to bit strokes = 1197 + 48
+ 100
= 1345 strokes

3.9 Volume of mud (dry) = Drill Collar Metal Displacement x Drill Collar Pulled Length
= 0.0370 x (3 x 90)
= 9.99 bbl.

3.10 Volume to fill the hole ‘wet’ = Stand length x Closed End displacement
= 93 x (0.0178 + 0.0082)
= 2.418 – 2.42 bbl.

[236]
 4.1 Level Drop due to slug = Pit Gain / Drill Pipe Capacity
*Pit Gain due to slug = Equation Number 27

= 20 x ((14.5/12.2) -1)
= 20 x (1.1885 -1)
= 3.77 bbl.
*Level Drop due to slug = 3.77 / .01776
= 212.3 ft.

4.2 A

5.1 Volume to bleed after gas migration = Equation Number 25

= (300 x 30) / (Formation Pressure – 300)
*Formation Pressure = Equation Number 4
= (10,000 x .052 x 11.7) + 800
= 6084 + 800
= 6884 psi
Volume to bleed = (300 x 30) / (6884 – 300)
= 9000 / 6584
= 1.36 - 1.366 – 1.367 bbl.

5.2 D
Formula #17
Gas Migration Rate = Rate of increase in pressure per hour / (Mw x 0.052)
= (100 x (60/15)) / (15 x 0.052)
= (100 x 4) / (15x 0.052)
= 512.82 ft./hr.

[237]
 5.3 Pressure Increase due to gas migration = Migration Distance x .052 x Mud density
= 600 x .052 x 12.8
= 399.36 – 400 psi
*SIDPP = 530 + 400
= 930 psi
*SICP = 680 + 400
= 1080 psi

6.1 Kill Mud Density = Equation Number 13

= (SIDPP / TVD at time of kick / .052) + Original Mud
density
= (150 / 3970 / .052) + 11.2
= 11.92 – 12 ppg

6.2 Kill Mud Density = Equation Number 13

= (SIDPP / TVD at time of kick / .052) + Original Mud
density
= (230 / 5820 / .052) + 12.8
= 13.55 – 13.6 ppg

6.3 B
Kill Mw = Current Mw + {SIDPP / (TVD x 0.052)}
= 12 + {480 / (10000 x 0.052)}
= 12.93 – 13 ppg

6.4 Off Bottom SIDPP = Off Bottom SICP

= 250 psi

[238]
6.5 A
Final Circulating Pressure = (Kill Mw / Current Mw) x RRCP
Kill Mud Density = Current Mw + {SIDPP / (TVD x 0.052)}
= 12 + {480 / (10000 x 0.052)}
= 12 + 0.92
= 12.92 - 13 ppg
FCP = (13 / 12) x 520
= 563.3 – 564 psi

6.6 A
Initial Circulating Pressure = SIDPP + RRCP
= 480 + 520 = 1000 psi
Part 4: Kill Sheets

1
2
Kill Sheet #1

Well Data
Hole Size 12 1/4 inch
Hole Depth 9800 feet TV D/MD
Drill pipe 5 inch Capacit y = 0.017766 bb/ft
Drill Collars 8 1/2 Inch, 68 0 feet long , capacity = 0.007 bbl/ft
Casing 13 3/8 casing set at 6500 feet TVD/MD
Mud density 10.8 ppg

Capacities
Drill collars in open hole 0.0756 bbls/ft
Drill pipe in open hole 0.1215 bbl/ft
Drill pipe in casing 0.1279 bbl/ft
Mud Pumps displacement 0.15 bbl/Stroke
Slow Circulating Rate 950 psi at 40 spm
A leak-off test was carried out at the 133/8 casing she and fracture Gradient at shoe is 0.806 psi/foot

The well was been shut in the following a kick

Kick Data
Shut-in Drill Pipe Pressure 800 psi
Shut-in Casing pressure 1000 psi
Pit Gain 30 bbl
Answer the following question from the data above
1. What is the kill mud density? = …... ppg
2. How many strokes are required to pump kill mud from surface to = …… stroke
bit?
3. How many strokes are required to pump from bit to casing shoe? = …stroke
4. How many strokes are required to pump from bit to surface? = …… stroke
5. What is the MAASP at the time the well was shut in? = …... Psi
6. What is the MAASP after circulation of the kill mud? = …… psi
7. How many strokes are required for one complete circulation? =…... Stroke
8. What is the Initial Circulating pressure? = …… psi
9. What is the Final circulating pressure? = …… psi
10. What is the drill pipe pressure reduction per 100 strokes as kill = …… psi/ 100stk
mud is being pumped to the bit?

3
Kill Sheet #2

Well Data
Hole Size 8 1/4 inch
Hole depth 11200 feet T VD, 12250 feet MD
Casing 9 5/8 casing set at 7500 TVD/MD
Drill pipe 5 inch, Capacity = 0.01776 bbl/ ft
Drill Collars 6 inch, 800 f eet long, Capacity = 0.005 bbl/ft.
Mud density 12.2 ppg

Capacities
Drill collars in open hole 0.031 bbl/ft
Drill pipe in open hole 0.0418 bbl/ft
Drill pipe in casing 0.0529 bbl/ft
Mud Pumps displacement 0.2 bbl/Stroke
Slow Circulating Rate 1100 psi at 35 spm
Fracture Mud density at the casing shoe 16 ppg

The well was been shut in the following a kick

Kick Data
Shut-in Drill Pipe Pressure 750 psi
Shut-in Casing pressure 1000 psi
Pit Gain 20 bbl
Answer the following question from the data above
1. What is the kill mud density? = …... ppg
2. What is the MAASP at the time the well was shut in? = …… psi
3. How many strokes are required to pump kill mud from surface to = …... stroke
bit?
4. How many strokes are required to kill mud from bit to surface? = …… stroke
5. How many strokes are required to pump from bit to casing shoe? = …… Strok e
6. What is the time for one complete circulation? = …... Minut e
7. How many strokes are required for one complete circulation? =…... Stroke
8. What is the initial circulating pressure? = …… psi
9. What is the final circulating pressure? = …… psi
10. What is the drill pipe pressure reduction per 100 strokes as kill = …… psi/10 0stk
mud is being pumped to the bit?

4
Kill Sheet #3

Well Data
Hole Size 12 1/4 inch
Hole depth 10200 feet TV D, 12220 feet MD
Casing 13 3/8 casing set at 6500 TVD, 8620 feet MD
Drill pipe 5 inch, capacit y = 0.01776 bbl/ft
Heavy wall drill pipe 5 inch, 630 fe et long, Capacity = 0.0088 bbl/ft.
Drill collars 8 inch, 542 fe et long, capacity = 0.0061 bbl/ft
Mud density 10.5 ppg
Capacities
Drill collars in open hole 0.086 bbl/ft
Drill pipe in open hole 0.1251 bbl/ft
Drill pipe in casing 0.1238 bbl/ft
Mud Pumps displacement 0.11 bbl/Stroke
Slow Circulating Rate 750 psi at 30 spm
A leak-off test was carried out at the 13 3/8 casing shoe using a mud density off 9.8 ppg and a surface pressure of 1600 psi was
recorded.
The well was been shut in the following a kick
Kick Data
Shut-in Drill Pipe Pressure 800 psi
Shut-in Casing pressure 1100 psi
Pit Gain 60 bbl
Answer the following question from the data above
1. How many strokes are required to pump kill mud from surface to = …... stroke
bit?
2. How many strokes are required to pump from bit to casing shoe? = …… stroke
3. How many strokes are required to pump from bit to surface? = …... stroke
4. What is the kill mud density? = …… ppg
5. What is the initial circulating pressure? = …… psi
6. What is the Final circulating pressure? = …… psi
7. What is the MAASP at the time the well was shut in? =…... Psi
8. What is the MAASP after circulation of the kill mud? = …… psi
9. What is the time for one complete circulation? = …… Minute

10. What is the drill pipe pressure reduction per 100 strokes as kill = …… psi/100s tk
mud is being pumped to the bit?

5
Kill Sheet #4

Well Data
Hole size 8 3/8 inch

Hole depth 11095 feet TVD/MD

Casing 9 5/8 casing set at 8856 feet TVD/MD

Drill pipe 5 inch, capacity = 0.0178 bbl/ft

Heavy wall drill pipe 5 inch, 630 feet long, capacity = 0.0088 bbl/ft

Drill collars 6 ½ inch, 450 feet long, capacity = 0.0077 bbl/ft

Mud density 12 ppg

Surface lines volume 7 bbls

Capacities

Drill collars in open hole 0.0271 bbl/ft

Heavy wall drill pipe in open hole 0.0439 bbl/ft

Drill pipe in open hole 0.0439 bbl/ft

Drill pipe in casing 0.0493 bbl/ft

Mud pumps displacement 0.109 bbl/stroke

Slow circulating rate 450 psi at 40 spm

A leak-off test was carried out at the 9 5/8 casing shoe using a mud density off 10.3 ppg and a surface pressure of 1700 psi was
recorded

The well has been shut in following a kick

Kick data

Shut-in drill pipe pressure 650 psi

Shut-in casing pressure 850 psi

Pit gain 15 bbls

Answer the following questions from the data above

1. What is the kill mud density? =…...ppg

2. What is the maximum allowable mud density? = …...ppg

3. How many strokes are required to pump kill mud from surface to bit? = …...strokes

4. How many strokes are required to pump from bit to casing shoe? = …...strokes

5. What is the total annular volume? = …...bbl

6. What is the initial circulating pressure? = …psi

7. What is the final circulating pressure? = …...psi

8. What is the MAASP at the time the well was shut in? = …...psi

9. What is the MAASP after circulation of the kill mud? = ……psi

10. What is the time for one complete circulation = ……minute

6
Kill Sheet #5

Well Data
Hole size 12 1/4 inch

Hole depth 12900 feet MD/ 11680 feet TVD

Casing 13 3/8 casing set at 4100 feet TVD/MD

Drill pipe 5 inch, capacity = 0.0177 bbl/ft

Drill collars 6 ½ inch, 590 feet long, capacity = 0.0077 bbl/ft

Mud density 12 ppg

Surface lines volume 5 bbls

Capacities

Drill collars in open hole 0.084 bbl/ft

Drill pipe in open hole 0.12 bbl/ft

Drill pipe in casing 0.13 bbl/ft

Mud pumps displacement 0.103 bbl/stroke

Slow circulating rate 670 psi at 30 spm

A leak-off test was carried out at the 13 3/8 casing shoe using a mud density off 10.6 ppg and a surface pressure of 1380 psi was
recorded

The well has been shut in following a kick

Kick data

Shut-in drill pipe pressure 580 psi

Shut-in casing pressure 740 psi

Pit gain 19 bbls

Answer the following questions from the data above

1. What is the kill mud density? =…...ppg

2. What is the maximum allowable mud density? = …...ppg

3. How many strokes are required to pump kill mud from surface to bit? = …...strokes

4. How many strokes are required to pump from bit to casing shoe? = …...strokes

5. What is the total annular volume? = …...bbl

6. What is the initial circulating pressure? = …psi

7. What is the final circulating pressure? = …...psi

8. What is the MAASP at the time the well was shut in? = …...psi

9. What is the MAASP after circulation of the kill mud? = ……psi

10. What is the time for one complete circulation = ……minute

7
Kill Sheet #6

Well Data
Hole size 8 1/2 inch

Hole depth 12336 feet MD/TVD

Casing 9 5/8 casing set at 9875 feet TVD/MD

Drill pipe 5 inch, capacity 0.0178 bbl/ft

Heavy Weight Pipe 5 inch, 489 feet long, capacity 0.0088 bbl/ft

Drill collars 6 ¼ inch, 902 feet long, capacity 0.006 bbl/ft

Mud density 14.1 ppg

Capacities

Drill collars in open hole 0.0322 bbl/ft

DrillPipe/HWDP in open hole 0.0473 bbl/ft

Drill pipe in casing 0.0493 bbl/ft

Pumps Displacement = 0.102 bbl/Stroke

Slow circulating rate 650 psi at 30 spm

Fracture mud density at the casing shoe 16.6 ppg

The well has been shut in after a kick

Kick data

Shut-in drill pipe pressure 530 psi

Shut-in casing pressure 720 psi

Pit gain 10 bbls

The well will be killed using the Driller’s Method at 30 SPM

Answer the following questions from the data above

1. What is the kill mud density? =…...ppg

2. How many strokes are required to pump kill mud from surface to bit? = …...strokes

3. How many strokes are required to pump from bit to casing shoe? = …...strokes

4. How many strokes are required to pump from bit to surface? = …...strokes

5. What is the initial circulating pressure? = …psi

6. What is the final circulating pressure? = …...psi

7. What is the MAASP at the time the well was shut in? = …...psi

8. What is the MAASP after circulation of the kill mud? = ……psi

9. What is the time for one complete circulation = ……minute

8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Kill Sheet #1
1. What is the kill mud density? = …12.36-12.4... ppg
2. How many strokes are required to pump kill mud from surface to bit? = …1111-1112… stroke
3. How many strokes are required to pump from bit to casing shoe? = …2464-2465... stroke
4. How many strokes are required to pump from bit to surface? = …8007-8008… stroke
5. What is the MAASP at the time the well was shut in? = …1588 – 1588.6... Psi
6. What is the MAASP after circulation of the kill mud? = …1047-1061.32… psi
7. How many strokes are required for one complete circulation? =…9118-9119... Stroke
8. What is the Initial Circulating pressure? = …1750… psi
9. What is the Final circulating pressure? = …1087.2-1091… psi
10. What is the drill pipe pressure reduction per 100 strokes as kill mud = …59-60… psi/100stk
is being pumped to the bit?

Kill Sheet #2
1. What is the kill mud density? = …13.48-13.5... ppg
2. What is the MAASP at the time the well was shut in? = …1482… psi
3. How many strokes are required to pump kill mud from surface to bit? = …1036-1037... stroke
4. How many strokes are required to kill mud from bit to surface? = …2933-2934… stroke
5. How many strokes are required to pump from bit to casing shoe? = …949-950… Stroke
6. What is the time for one complete circulation? = …112.4-114.4... Minu te
7. How many strokes are required for one complete circulation? =…3970-3971... Stroke
8. What is the initial circulating pressure? = …1850… psi
9. What is the final circulating pressure? = …1215.4-1218… psi
10. What is the drill pipe pressure reduction per 100 strokes as kill mud = …61-62… psi/100stk
is being pumped to the bit?

Kill Sheet #3
1. How many strokes are required to pump kill mud from surface to bit? = …1845-1883... stroke

2. How many strokes are required to pump from bit to casing shoe? = …3862-3941… stroke
3. How many strokes are required to pump from bit to surface? = …13466-13739... stroke
4. What is the kill mud density? = …12.00-12.1… ppg
5. What is the initial circulating pressure? = …1550… psi
6. What is the Final circulating pressure? = …857.14-865… psi
7. What is the MAASP at the time the well was shut in? =…1352-1362.14... Psi
8. What is the MAASP after circulation of the kill mud? = …811-855… psi
9. What is the time for one complete circulation? = …514.5-516.5… Minute
10. What is the drill pipe pressure reduction per 100 strokes as kill mud = …36-38… psi/100stk
is being pumped to the bit?

23
Kill Sheet #4
1. What is the kill mud density? =…13.12-13.2...ppg

2. What is the maximum allowable mud density? = …13.9 – 13.99...ppg

3. How many strokes are required to pump kill mud from surface to bit? = …1718........strokes

4. How many strokes are required to pump from bit to casing shoe? = …1013…....strokes

5. What is the total annular volume? = …527.3329...bbl

6. What is the initial circulating pressure? = …1100...psi

7. What is the final circulating pressure? = …491.9 - 495...psi

8. What is the MAASP at the time the well was shut in? = …874 – 916.41...psi

9. What is the MAASP after circulation of the kill mud? = …322 – 400.6…psi

10. What is the time for one complete circulation = …163.9-164…minute

Kill Sheet #5
1. What is the kill mud density? =…12.95-13.0...ppg

2. What is the maximum allowable mud density? = …17.0 – 17.07...ppg

3. How many strokes are required to pump kill mud from surface to bit? = …2159-2160...strokes

4. How many strokes are required to pump from bit to casing shoe? = …10046 - 10047...strokes

5. What is the total annular volume? = …1567.76...bbl

6. What is the initial circulating pressure? = …1250...psi

7. What is the final circulating pressure? = …723.04 - 726...psi

8. What is the MAASP at the time the well was shut in? = …1066 – 1080.92...psi

9. What is the MAASP after circulation of the kill mud? = …863 – 878.38…psi

10. What is the time for one complete circulation = …579.34-580…minute

Kill Sheet #6
1. What is the kill mud density? =…14.92 to 15...ppg

2. How many strokes are required to pump kill mud from surface to bit? = …1985 to 2025...strokes

3. How many strokes are required to pump from bit to casing shoe? = …665 to 1018...strokes

4. How many strokes are required to pump from bit to surface? = ….5723 to 5839..strokes

5. What is the initial circulating pressure? = …1180...psi

6. What is the final circulating pressure? = …677 - 707...psi

7. What is the MAASP at the time the well was shut in? = …1283 ...psi

8. What is the MAASP after circulation of the kill mud? = …771 to 871…psi

9. What is the time for one complete circulation = …257-263…minute

24
Part 5: Gauge Problems

25
26
 Driller’s Method - #01
International Well Control Forum DATE :

Surface BOP Kill Sheet - Deviated Well (API Field Units) NAME :

FORMATION STRENGTH DATA: CURRENT WELL DATA:

SURFACE LEAK -OFF PRESSURE FROM
1500 psi DRILLING MUD DATA:
FORMATION STRENGTH TEST (A)
WEIGHT 10.6 ppg
MUD WEIGHT AT TEST (B) 10 ppg GRADIENT 0.551 psi/ft

MAXIMUM ALLOWABLE MUD WEIGHT =

(A)
(B) + = (C) 15.4 ppg
DEVIATION DATA:
SHOE T.V. DEPTH x 0.052
KOP M.D. 3000 ft
INITIAL MAASP =
((C) - CURRENT MUD WEIGHT) x SHOE T.V. DEPTH x 0.052
KOP T.V.D. 3000 ft

= 1322 psi EOB M.D. 8500 ft

EOB T.V.D. 5750 ft

PUMP NO. 1 DISPL. PUMP NO. 2 DISPL. CASING SHOE DATA:

0.1 bbls / stroke bbls / stroke

SIZE 9-5/8 in
M. DEPTH 8600 ft
T.V. DEPTH 5300 ft

SLOW PUMP (PL) DYNAMIC PRESSURE LOSS HOLE DATA:

RATE DATA: PUMP NO. 1 PUMP NO. 2 SIZE 8-1/2 in

30 SPM 350 psi psi

M. DEPTH 12000 ft

SPM psi psi

T.V. DEPTH 6000 ft

PRE-RECORDED LENGTH CAPACITY VOLUME PUMP STROKES TIME

VOLUME DATA: ft bbls / ft bbls strokes minutes

DP - SURFACE TO KOP 3000 x 0.0176 = 52.80 (L) 528 stks

DP - KOP TO EOB 5500 x 0.0176 = 96.80 + (M) 968 stks
DP - EOB TO BHA 2200 x 0.0176 = 38.70 + (N1) 387 stks

HEVI WALL DRILL PIPE 800 x 0.0087= 6.9 + (N2) 70 stks

DRILL COLLAR 500 x 0.0076= 3.8 + (N3) 38 stks

DRILL STRING VOLUME (D) 199 bbls 1990 stks 66 min

DC x OPEN HOLE 500 x 0.021 = 10.50

DP / HWDP x OPEN HOLE 2900 x 0.045 = 130.50 +
OPEN HOLE VOLUME (F) 141 bbls 1410 stks 47 min

DP x CASING 8600 x 0.049 = (G) 421.40 + 4214 stks 140.5 min

TOTAL ANNULUS VOLUME (F+G) = (H) 562.40 bbls 5624 stks 187.5 min
TOTAL WELL SYSTEM VOLUME (D+H) = (I) 761.40 bbls 7614 stks 254 min
Dr No SD 04/01
ACTIVE SURFACE VOLUME (J) bbls (Field Units)
TOTAL ACTIVE FLUID SYSTEM (I+J) 27-01-2000
bbls

27
 International Well Control Forum DATE :

Surface BOP Kill Sheet - Deviated Well (API Field Units) NAME :

KICK DATA :

SIDPP 800 psi SICP 900 psi PIT GAIN 20 bbl

KILL MUD WEIGHT SIDPP

CURRENT MUD WEIGHT + TVD x 0.052
10.6 800
.1
...3
.....1
...6
................. + =
KMW ..... ppg
6000 X 0.052

INITIAL CIRC. PRESSURE DYNAMIC PRESSURE LOSS + SIDPP

ICP ....3
...5
...0
....... + ...8
...0
..0
......... = ..1
..1
...5
...0
..... psi

KILL MUD WEIGHT

FINAL CIRCULATING x DYNAMIC PRESSURE LOSS
CURRENT MUD WEIGHT
PRESSURE
FCP 13.16 x .....3
...5
...0
...... =
10.6 .....4
...3
...5
.... psi

DYNAMIC PRESSURE KOPMD 3000

PL + (FCP-PL) x = ..3
...5
...0
.. + (..4
...3
...5
...-...3
..5
...0
....) x =
LOSS AT KOP (O) TDMD 12000 .....3
..7
...1
..... psi

SIDPP - (KMW - CMW) x 0.052 x KOPTVD

REMAINING SIDPP
AT KOP (P) = ...8
...0
..0
...... - (..1
...3
.....1
...6
......-......1
..0
......6
......) x 0.052 x ....3
...0
...0
..0
..... =
......4
...0
..1
.... psi

CIRCULATING PRESS. (O) + (P) = ...3

...7 .... + ...4
...1 ...0
..1
..... = 772
AT KOP (KOP CP) ............... psi

DYNAMIC PRESSURE EOBMD

= ..3
...5
...0
.. + (.4
...3
...5
....-...3
...5
...0
...) x 8500 =
PL + (FCP-PL) x
LOSS AT EOB (R) TDMD 12000 .....4
...1
...0
.... psi

SIDPP - (KMW - CMW) x 0.052 x EOBTVD

REMAINING SIDPP
AT EOB (S) = ...8
...0 ..... - (...1
...0 ...3
.....1
...6
.....-.......1
...0
.....6
.....) x 0.052 x ...5
..7
...5
...0
...... =
....3
...5
........ psi

CIRCULATING PRESSURE (R) + (S) = ....4

...1
...0
... + ....3
...5
...... =
AT EOB (EOB CP) ....4
..4
...5
...... psi

(T) x 100 378 x 100 psi

(T) = ICP - KOP CP = ...1
..1
...5 .... - ....7
...0 ...7
...2
... = ...3
...7
...8
.. psi (L) = = ..7
...2
........ 100 strokes
528
(U) x100 327 X100 psi
(U) = KOP CP - EOB CP = .7
...7
...2
... - ..4
...4
...5
.. = ....3
...2
..7
.. psi = = ...3
...4
.......
(M) 100 strokes
968

..... = ....1
...0
(W) x 100 psi
(W) = EOB CP - FCP = ...4
..4
...5
.... - ....4
..3
...5 .... psi = 10 X 100
= ....2
.........
(N1+N2+N3) 100 strokes
495
28
 STATIC & DYNAMIC DRILL PIPE PRESSURE [psi]

STROKES PRESSURE
[psi]
0 1150
100 1078
200 1006
300 934
400 862
500 790
528 772
600 738
700 704
800 670
900 636
1000 602
1100 568
International Well Control Forum

1200 534
1300 500

29
1400 466
1496 445
1500 443
Surface BOP Kill Sheet - Deviated Well (API Field Units)

1600 441
1700 439
1800 437
1900 435
1990 435
DATE :

NAME :

STROKES

Dr No SD 04/03 (Field Units) 27-01-2000

30
 Driller’s Method - #01

Use the information from the completed Kill sheet on the previous pages to answer the
following ELEVEN questions. The well will be killed using the Driller's Method at 30
SPM. Ignore the surface line volume.

1. After 60 strokes have been circulated the following gauge readings are observed on
the remote choke panel:

Drill pipe pressure 900 psi

Casing pressure 750 psi
Pump speed 30 spm
Strokes pumped 60 strokes .
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Increase the pump rate.
d. Decrease the pump rate.
e. Continue - Everything is OK.

2. After 510 strokes have been circulated the following readings are observed on the
remote choke panel:

Drill pipe pressure 1160 psi

Casing pressure 1020 psi
Pump speed 30 spm
Strokes pumped 510 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Increase the pump rate.
d. Decrease the pump rate.
e. Continue - everything is OK.

31
3. After 600 strokes have been circulated the following readings are observed on the
remote choke panel:

Drill pipe pressure 1130 psi

Casing pressure 1030 psi
Pump speed 28 spm
Strokes pumped 600 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Increase the pump rate.
d. Decrease the pump rate.
e. Continue - everything is OK.

4. After 4000 strokes have been circulated, the following readings are observed on
the remote choke panel:

Drill pipe pressure 1160 psi

Casing pressure 1310 psi
Pump speed 30 sprn
Strokes pumped 4000 strokes

The casing pressure has now started to increase faster than before. What is the
most likely reason for this?

a. The circulating rate is below the required bottom hole pressure and more influx
is entering the well.

b. The influx is being circulated from highly deviated section into the build section
of the well.

c. The change is caused by the effect of gas free mud in the horizontal section of
the well.

d. The choke is partially plugged.

32
5. After 5000 strokes have been circulated, the following readings are observed on the
remote choke panel:

Drill pipe pressure 1170 psi

Casing pressure 1400 psi
Pump speed 30 spm
Strokes pumped 5000 strokes
What action should be taken?
a. Open the choke more - MAASP has been exceeded.
b. Close the choke little.
c. Slow the pumps down to reduce circulating friction in the annulus.
d. Continue - Everything is OK.

6. After 6500 strokes have been circulated, the pump is shuts down while holding
casing pressure constant.

Provided that no more influx was allowed to enter the well during the first
circulation of driller's method, what reading would you expect to see on the drill
pipe pressure gauge on the remote choke panel?
a. 435 psi.
b. 800 psi.
c. 900 psi.
d. 0 psi.

7. Provided that no more influx was allowed to enter the well during the first
circulation of driller's method, what reading would you expect to see on the casing
pressure gauge on the remote choke panel?
a. 345 psi.
b. 800 psi.
c. 900 psi.
d. 0 psi.

33
8. Kill mud is now being pumped into the well.
After 1000 strokes have been circulated, the following readings are observed on the
remote choke panel:

Drill pipe pressure 700 psi

Casing pressure 900 psi
Pump speed 30 spm
Strokes pumped 1000 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke little.
c. Increase the pump rate.
d. Decrease the pump rate.
e. Continue - Everything is OK.

9. After 2500 strokes have been circulated, the drill pipe pressure suddenly increases
while the casing pressure remains constant.

Drill pipe pressure 640 psi

Casing pressure 700 psi
Pump speed 30 spm
Strokes pumped 2500 strokes
What action should be taken?
a. Shut the well in and analyze the problem.
b. Open the choke more.
c. Close the choke little.
d. Increase the pump rate.
e. Decrease the pump rate.

34
10. How do you explain the previous problem?

a. A lost bit nozzle.

b. A washout in the drill pipe.
c. A plugged bit nozzle.
d. A pump problem.
e. A washout in the choke.
f. A plugged choke.

11. The choke is now fully open and the kill mud is returning to surface, but it is
difficult to determine whether there is any pressure on the casing.

The following readings are observed on the remote choke panel:

Drill pipe pressure 640 psi

Casing pressure 0 psi
Pump speed 30 spm
Strokes pumped 8000 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke little.
c. Stop the pump, shut in the well, observe pressures.
d. Reduce the pump rate.
e. Stop pumping and open the well.

35
36
 Driller’s Method - #02
International Well Control Forum DATE :

Surface BOP Kill Sheet - Deviated Well (API Field Units) NAME :

FORMATION STRENGTH DATA: CURRENT WELL DATA:

SURFACE LEAK -OFF PRESSURE FROM
DRILLING MUD DATA:
FORMATION STRENGTH TEST (A) 1125 psi
WEIGHT 10.9 ppg
MUD WEIGHT AT TEST (B) 10.4 ppg GRADIENT psi/ft

MAXIMUM ALLOWABLE MUD WEIGHT =

(A) (C) ppg
(B) + = 14.6 DEVIATION DATA:
SHOE T.V. DEPTH x 0.052
KOP M.D. ft
INITIAL MAASP =
KOP T.V.D. ft
((C) - CURRENT MUD WEIGHT) x SHOE T.V. DEPTH x 0.052

= 981 psi EOB M.D. ft

EOB T.V.D. ft

PUMP NO. 1 DISPL. PUMP NO. 2 DISPL. CASING SHOE DATA:

SIZE 9-5/8 in
0.12 bbls / stroke bbls / stroke
M. DEPTH 6200 ft
T.V. DEPTH 5100 ft

SLOW PUMP (PL) DYNAMIC PRESSURE LOSS HOLE DATA:

RATE DATA: PUMP NO. 1 PUMP NO. 2 SIZE 8-1/2 in
M. DEPTH 11950 ft
30 SPM 625 psi psi
T.V. DEPTH 6100 ft
SPM psi psi

PRE-RECORDED LENGTH CAPACITY VOLUME PUMP STROKES TIME

VOLUME DATA: ft bbls / ft bbls strokes minutes

DP - SURFACE TO KOP 3000 x 0.01750 = 52.50 (L) 438 stks

DP - KOP TO EOB 2900 x0.01750 = 50.75 + (M) 423 stks
DP - EOB TO BHA 5720 x 0.01750 = 100.10 + (N1) 834 stks

HEVI WALL DRILL PIPE 180 x 0.0087= 1.57 + (N2) 13 stks

DRILL COLLAR 150 x 0.0061= 0.92 + (N3) 8 stks

DRILL STRING VOLUME (D) 205.84 bbls 1716 stks min

DC x OPEN HOLE 150 x 0.0323 = 4.85

DP / HWDP x OPEN HOLE 5600 x 0.0459 = 257.04 +
OPEN HOLE VOLUME (F) 261.90 bbls 2183 stks min

DP x CASING 6200 x 0.0515 = (G) 319.30 + stks min

TOTAL ANNULUS VOLUME (F+G) = (H) 581.20 bbls 4843 stks min
TOTAL WELL SYSTEM VOLUME (D+H) = (I) 787.00 bbls 6559 stks min

Dr No SD 04/01
ACTIVE SURFACE VOLUME (J) bbls (Field Units)
TOTAL ACTIVE FLUID SYSTEM (I+J) 27-01-2000
bbls

37
 International Well Control Forum DATE :

Surface BOP Kill Sheet - Deviated Well (API Field Units) NAME :

KICK DATA :

SIDPP 875 psi SICP 905 psi PIT GAIN 15 bbl

KILL MUD WEIGHT SIDPP

CURRENT MUD WEIGHT + TVD x 0.052
10.9 875
.1
...3
.....7
................. + =
KMW ........ ppg
6100 X 0.052

INITIAL CIRC. PRESSURE DYNAMIC PRESSURE LOSS + SIDPP

ICP ....6
...2
...5
....... + ...8
...7
..5
......... = ..1
..5
...0
...0
..... psi

KILL MUD WEIGHT

FINAL CIRCULATING x DYNAMIC PRESSURE LOSS
CURRENT MUD WEIGHT
PRESSURE
FCP 13.7 x .....6
...2
...5
...... =
10.9 .....7
...8
...5
.... psi

DYNAMIC PRESSURE KOPMD 3000

PL + (FCP-PL) x = ..6
...2
...5
.. + (..7
...8
...5
...-...6
..2
...5
....) x =
LOSS AT KOP (O) TDMD 11950 .....6
..6
...5
..... psi

SIDPP - (KMW - CMW) x 0.052 x KOPTVD

REMAINING SIDPP
AT KOP (P) = .............. - (..................-...................) x 0.052 x ................. =
............... psi

CIRCULATING PRESS. (O) + (P) = ...3

...7 .... + ...4
...1 ...0
..1
..... =
AT KOP (KOP CP) ............... psi

DYNAMIC PRESSURE EOBMD

PL + (FCP-PL) x = .......... + (...........-............) x =
LOSS AT EOB (R) TDMD ............... psi

SIDPP - (KMW - CMW) x 0.052 x EOBTVD

REMAINING SIDPP
AT EOB (S) = .............. - (..................-...................) x 0.052 x ................. =
............... psi

CIRCULATING PRESSURE
(R) + (S) = ............. + ............. =
AT EOB (EOB CP) ............... psi

(T) x 100 x 100 psi

(T) = ICP - KOP CP = ............... - ............. = ........... psi = = .............
(L) 100 strokes

(U) x 100 X 100 psi

(U) = KOP CP - EOB CP = .......... - .......... = ........... psi = = .............
(M) 100 strokes

(W) x 100 X 100 psi

(W) = EOB CP - FCP = ............ - .............. = ........... psi = = .............
(N1+N2+N3) 100 strokes
Dr No SD 04/02 (Field Units) 27-01-2000
38
 STATIC & DYNAMIC DRILL PIPE PRESSURE [psi]

STROKES PRESSURE
[psi]
0 1500
100 1410
200 1320
300 1230
400 1140
438 1106
500 1068
600 1007

700 946
800 885
861 848

900 845

1000 838
International Well Control Forum

1100 831
1200 824

39
1300 817
1400 810
1500 803
Surface BOP Kill Sheet - Deviated Well (API Field Units)

1600 796
1700 789

1716 785
DATE :

NAME :

STROKES

Dr No SD 04/03 (Field Units) 27-01-2000

40
 Driller’s Method - #02

Use the information from the completed Kill sheet on the previous pages to answer the
following ELEVEN questions. The well will be killed using the Driller's Method at 30
SPM. Ignore the surface line volume.

1. After 4 minutes of circulation the following gauge readings are observed on the
remote choke panel:

Drill pipe pressure 1500 psi

Casing pressure 905 psi
Pump speed 30 spm
Strokes pumped 100 strokes .
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Increase the pump rate.
d. Decrease the pump rate.
e. Continue - Everything is OK.

2. After 8 minutes of circulation the following readings are observed on the remote
choke panel:

Drill pipe pressure 1500 psi

Casing pressure 905 psi
Pump speed 30 spm
Strokes pumped 220 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Increase the pump rate.
d. Decrease the pump rate.
e. Continue - everything is OK.

41
3. After 1800 strokes have been circulated the following readings are observed on the
remote choke panel:

Drill pipe pressure 1620 psi

Casing pressure 1090 psi
Pump speed 30 spm
Strokes pumped 1800 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Increase the pump rate.
d. Decrease the pump rate.
e. Continue - everything is OK.

4. After 5000 strokes have been circulated, the well is shut in and the gauge
readings are observed on the choke panel:

Drill pipe pressure 875 psi

Casing pressure 875 psi
Pump speed 0 sprn
Strokes pumped 5000 strokes

What action should be taken?

a. Reset the stroke counters and start up holding casing pressure constant while
bringing the pump to kill speed, and then hold the drillpipe pressure constant by
following the diagram of the kill sheet till the heavy fluid is at the bit.

b. Start up holding drill pipe pressure constant.

c. Everything is OK. Continue kill procedure at 30 SPM and same final circulating
pressure.

42
5. The second circulation has commenced and kill fluid is being circulated.
After 1800 strokes have been circulated, the following readings are observed on
the remote choke panel:

Drill pipe pressure 785 psi

Casing pressure 875 psi
Pump speed 30 spm
Strokes pumped 1800 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke little.
c. Increase the pump rate.
d. Reduce the pump rate.
d. Continue - Everything is OK.

6. After 1900 strokes have been circulated, the following readings are observed?
Drill pipe pressure 885 psi
Casing pressure 960 psi
Pump speed 30 SPM
Strokes circulated 1900 strokes
What action should be taken?
a. Open the choke more
b. Close the choke more
c. Reduce the pump rate
d. Shut down and observe pressures

43
7. After 2500 strokes have been circulated the following gauge readings are observed.
Drill pipe pressure 653 psi
Casing pressure 682 psi
Pump Speed 30 SPM
Strokes circulated 2500 strokes

What action should be taken?

a. Open the choke more
b. Close the choke more
c. Increase the pump rate
d. Shut down and observe pressures.

8. After 2800 strokes have been circulated the casing pressure and then the drill pipe
pressure start to fluctuate and increase:

Drill pipe pressure 1075 psi

Casing pressure 1090 psi
Pump speed 30 spm
Strokes pumped 2800 strokes

What is the problem?

a. A pump suction problem.
b. A plugged bit nozzle
c. A wash out in the drill string
d. A plugging choke
e. The pulsation dampener of the mud pump is malfunctioning.

44
9. After 3000 strokes have been circulated, the drill pipe pressure suddenly decreases.
The casing pressure is not affected.
Drill pipe pressure 508 psi
Casing pressure 785 psi
Pump speed 30 spm
Strokes pumped 3000 strokes
What is the problem?
a. A pump problem.
b. A lost bit nozzle.
c. A wash out in the drill string.
d. A wash out in the choke manifold.
e. The U-tubing effect of the heavy kill fluid.

10. The previous problem has been solved.

After 4800 strokes have been circulated, it requires continuous small opening
correction of the choke to maintain drill pipe pressure at 508 psi.
Drill pipe pressure 508 psi
Casing pressure 580 psi
Pump Speed 30 SPM
Strokes circulated 4800 strokes
What is the problem?
a. A bit nozzle washing out.
b. The choke washing out.
c. A wash out developing inside the fluid pump.
d. There is no problem. It is caused by the kill fluid rising up the annulus.

45
11. The choke is now fully open and the kill mud is returning to surface, but it is
difficult to determine whether there is any pressure on the casing.

The following readings are observed on the remote choke panel:

Drill pipe pressure 508 psi

Casing pressure 0 psi
Pump speed 30 spm
Strokes pumped 7000 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke little.
c. Stop the pump, shut in the well, observe pressures.
d. Reduce the pump rate.
e. Stop pumping and open the well.

46
 Wait & Weight Method - #01
International Well Control Forum DATE :

Surface BOP Vertical Well Kill Sheet (API Field Units) NAME :

FORMATION STRENGTH DATA: CURRENT WELL DATA::

SURFACE LEAK -OFF PRESSURE FROM
FORMATION STRENGTH TEST (A) psi

MUD WEIGHT AT TEST (B) ppg

CURRENT DRILLING MUD:
MAXIMUM ALLOWABLE MUD WEIGHT = WEIGHT ppg
(A) 11
(B) + = (C) ppg
SHOE T.V. DEPTH x 0.052

INITIAL MAASP =
((C) - CURRENT MUD WEIGHT) x SHOE T.V. DEPTH x 0.052
CASING SHOE DATA:
= 1100 psi
SIZE 13 5/8 inch

M. DEPTH 6000 feet

PUMP NO. 1 DISPL. PUMP NO. 2 DISPL. T.V. DEPTH feet
5820
bbls / stroke bbls / stroke
HOLE DATA:
(PL) DYNAMIC PRESSURE LOSS [psi]
SIZE 12 1/4 inch
SLOW PUMP
PUMP NO. 1 PUMP NO. 2
RATE DATA: M. DEPTH 7550 feet
500 T.V. DEPTH 6000 feet
30 SPM 500
SPM

PRE-RECORDED LENGTH CAPACITY VOLUME PUMP STROKES TIME

VOLUME DATA: feet bbls / foot barrels strokes minutes

DRILL PIPE x = VOLUME PUMP STROKES

HEAVY WALL DRILL PIPE x = +
PUMP DISPLACEMENT SLOW PUMP RATE
DRILL COLLARS x = +

DRILL STRING VOLUME (D) bbls (E) 1085 strokes 36 Min

DC x OPEN HOLE x =

DP / HWDP x OPEN HOLE x = +

OPEN HOLE VOLUME (F) bbls 1420 strokes 47 Min

DP x CASING x = (G) + strokes Min

TOTAL ANNULUS VOLUME (F+G) = (H) bbls 6519 strokes 217 Min

TOTAL WELL SYSTEM VOLUME (D+H) = (I) bbls 9024 strokes 301 Min

ACTIVE SURFACE VOLUME (J) bbls strokes

TOTAL ACTIVE FLUID SYSTEM (I +J) bbls strokes Dr No SV 04/01

(Field Units)
27-01-2000

47
 International Well Control Forum DATE :

Surface BOP Kill Sheet - Vertical Well (API Field Units) NAME :

KICK DATA :
SIDP 550 psi SICP 650 psi PIT GAIN 25 barrels
P

KILL MUD WEIGHT SIDPP

CURRENT MUD WEIGHT +
TVD x 0.052
................. + =
KMW X 0.052 12.5 ppg

INITIAL CIRCULATING DYNAMIC PRESSURE LOSS + SIDPP

PRESSURE
................. + ................. =
ICP 1050 psi

KILL MUD WEIGHT

FINAL CIRCULATING x DYNAMIC PRESSURE LOSS
CURRENT MUD WEIGHT
PRESSURE
FCP x ................. =
570 psi

(K) x 100 X 100 psi

(K) = ICP - FCP = ................... - ................... = ......4
...8
...0.. psi = = 44.2
(E)

STROKES PRESSURE
[psi]
0 1050
100 1006
200 962
300 917
STATIC & DYNAMIC DRILL PIPE PRESSURE [psi]

400 873
500 820
600 785
700 741
800 695
900 652
1000 608
1085 570

STROKES

Dr No SV 04/02 (Field Units) 27-01-2000

48
 Wait & Weight Method - #01

Use the information from the completed Kill sheet on the previous pages to answer the
following ELEVEN questions.
The well will be killed using the Wait and Weight Method at 30 SPM. Ignore the surface
line volume.

1. After 139 strokes have been circulated the following gauge readings are observed
on the remote choke panel:

Drill pipe pressure 940 psi

Casing pressure 670 psi
Pump speed 25 spm
Strokes pumped 139 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Increase the pump rate.
d. Reduce the pump rate.
e. Continue - Everything is OK,

2. After 270 strokes have been circulated the following readings are observed on the
remote choke panel:
Drill pipe pressure 935 psi
Casing pressure 680 psi
Pump speed 30 spm
Strokes pumped 270 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Adjust pump rate.
d. Stop pumping and close the choke.
e. Continue - Everything is OK.

49
3. After 450 strokes have been circulated, the following readings are observed on the
remote choke panel:

Drill pipe pressure 855 psi

Casing pressure 690 psi
Pump speed 30 spm
Strokes pumped 450 strokes

What action should be taken?

a. Open the choke more.

b. Close the choke more.
c. Increase the pump rate.
d. Reduce the pump rate.
e. Continue - Everything is OK.

4. After 870 strokes have been circulated, the following readings are observed on
the remote choke panel:

Drill pipe pressure 760 psi

Casing pressure 750 psi
Pump speed 30 spm
Strokes pumped 870 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke more.
c. Increase the pump rate.
d. Reduce the pump rate.
e. Continue - Everything is OK.

50
5. After 1150 strokes have been circulated, the well is shut in to make a check.

The following readings are observed on the remote choke panel:

Drill pipe pressure 0 psi

Casing pressure 850 psi
Pump speed 0 spm
Strokes pumped 1150 strokes

After the check the kill procedure is continued. What should be done?

a. The casing pressure is less than shut in pressure because the kill mud density is
too high. Continue the kill procedure using a kill mud density corrected for the
pressure difference.

b. Start up holding drill pipe pressure constant.

c. Start up holding casing pressure constant while bringing the pump to kill speed,
then hold the observed drill pipe pressure constant.

d. Restart circulation at 30 spm maintaining the same final circulating pressure.

6. After 5500 strokes have been circulated, the following readings are observed on
the remote choke panel:

Drill pipe pressure 575 psi

Casing pressure 1430 psi
Pump speed 30 spm
Strokes pumped 5500 strokes
What action should be taken?
a. Open the choke more.
b. Close the choke little.
c. Increase the pump rate.
d. Reduce the pump rate.
e. Continue - Everything is OK.

51
7. After 5900 strokes have been circulated, the drill pipe pressure suddenly decreased
while the casing pressure remains steady.

Drill pipe pressure 440 psi

Casing pressure 1460 psi
Pump speed 30 spm
Strokes pumped 5900 strokes
What is the problem?
a. A lost bit nozzle.
b. A washout in the drill pipe.
c. A plugged bit nozzle.
d. A pump problem.
e. A washout in the choke.
f. A plugged choke.

8. What action should be taken?

a. Stop the pump and shut the well in.
b. Open the choke more.
c. Close the choke little.
d. Increase the pump rate.
e. Decrease the pump rate.

9. The problem has been identified, and the following gauge readings are now
observed on the remote choke panel:

Drill pipe pressure 440 psi

Casing pressure 1440 psi
Pump speed 33 spm
Strokes pumped 5920 strokes
What action should be taken?
a. Continue - Everything is OK.
b. Reduce the pump rate.
c. Increase the pump rate.
d. Close the choke more.
e. Open the choke little.

52
10. After 6100 strokes have been circulated, the following readings are observed on
the remote choke panel:

Drill pipe pressure 440 psi

Casing pressure 1370 psi
Pump speed 30 spm
Strokes pumped 6100 strokes
What action should be taken?
a. Continue - Everything is OK.
b. Reduce the pump rate.
c. Increase the pump rate.
d. Close the choke more.
e. Open the choke little.

11. After 9350 strokes have been circulated, the following readings are observed on
the remote choke panel:

Drill pipe pressure 440 psi

Casing pressure 0 psi
Pump speed 30 spm
Strokes pumped 9350 strokes
The choke now fully open and there is no back pressure on the casing.
What action should be taken?
a. Close the choke more.
b. Stop the pump, shut the well in, observe pressures.
c. Open the BOP and then start drilling operations.
d. Reduce the pump rate.

53
54
 Wait & Weight Method - #02

12

1170 13-5/8
7200
6980
0.119

12-1/4
9580
30 450 9186

1380 46

2220 74

10050 335

11430 381

55
 525 650 21

13.1

975

490

485 35.15

0 975
100 940
200 905
300 870
400 835
500 800
600 765
700 730
800 695
900 660
1000 625
1100 590
1200 555
1300 520
1380 490

56
 Wait & Weight Method - #02

The well will be killed using the Wait and Weight Method at 30 SPM. Ignore the surface
line volume.

1. After 105 strokes are circulated, the remote choke panel shown the following
readings:

Drill pipe pressure 769 psi

Casing pressure 638 psi
Pump speed 24 SPM
Strokes pumped 105 strokes
What action should be taken?
a. Close the choke more.
b. Continue – everything is okay.
c. Increase the pump rate.
d. Open the choke more.
e. Reduce the pump rate

2. After 240 strokes are circulated, the remote choke panel shows the following
readings:

Drill pipe pressure 895 psi

Casing pressure 660 psi
Pump speed 30 SPM
Strokes pumped 240 strokes
What action should be taken?
a. Close the choke more.
b. Continue – everything is okay.
c. Increase the pump rate
d. Open the choke more
e. Reduce the pump rate

57
3. After 420 strokes are circulated, the remote choke panel shows the following
readings:

Drill pipe pressure 830 psi

Casing pressure 680 psi
Pump speed 30 SPM
Strokes pumped 420 strokes

What action should be taken?

a. Close the choke more.

b. Continue – everything is okay.
c. Increase the pump rate
d. Open the choke more
e. Reduce the pump rate

4. After 900 strokes are circulated, the remote choke panel shows the following
readings:

Drill pipe pressure 750 psi

Casing pressure 800 psi
Pump speed 30 SPM
Strokes pumped 900 strokes
What action should be taken?
a. Close the choke more
b. Continue – everything is okay.
c. Increase the pump rate
d. Open the choke more
e. Reduce the pump rate

58
5. After reaching Final Circulating Pressure (FCP) after 1500 strokes circulated,
the well is shut in to complete a pressure check. The remote choke panel then shows
the following readings:

Drill pipe pressure 0 psi

Casing pressure 730 psi
Pump speed 0 spm
Strokes pumped 1500 strokes

After confirming the pressure check is acceptable, the kill procedure is continued.

What action should be taken?

a. Calculate the new kill fluid density and pump rate

b. Everything is okay, continue the kill procedure with 40 spm but keep the same
FCP.
c. Start-up the kill procedure by holding casing pressure constant, while bringing
the pump up to kill speed, then hold the observed drill pipe pressure constant.
d. Start-up the kill procedure by holding the drill pipe pressure constant, while
bringing the pump up to kill speed, then hold the observed casing pressure
constant.

6. After 3050 strokes are, the remote choke panel shows that both the drill pipe
and casing pressure are decreasing:

Drill pipe pressure 420 psi

Casing pressure 690 psi
Pump speed 30 spm
Strokes pumped 3050 strokes
What is the reason for this decrease in pressure?
a. A lost bit nozzle
b. A plugged bit nozzle
c. A plugged choke
d. A pump problem
e. A washout in the choke
f. A washout in the drill pipe

59
7. After identifying the problem (from the previous question), what is the first action
to take?
a. Change over to the back-up choke
b. Close the choke
c. Increase the pump rate
d. Stop the pump, and close one valve upstream of the choke

8. Once the problem (from the previous question) is resolved, the remote choke panel
shows the following readings:

Drill pipe pressure 490 psi

Casing pressure 720 psi

Pump rate 33 spm

Strokes circulated 3070 strokes

What action should be taken?

a. Close the choke more
b. Continue – everything is okay
c. Increase the pump rate
d. Open the choke more
e. Reduce the pump rate

9. After 8000 strokes are circulated, the remote choke panel shows the following
readings:

Drill pipe pressure 490 psi

Casing pressure 800 psi
Pump speed 30 spm
Strokes pumped 8000 strokes
What action should be taken?
a. Close the choke more
b. Continue – everything is okay
c. Increase the pump rate
d. Open the choke more
e. Reduce the pump rate

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10. After 9000 strokes are circulated, the remote choke panel shows the following
readings:

Drill pipe pressure 410 psi

Casing pressure 840 psi
Pump speed 30 spm
Strokes pumped 9000 strokes
What action should be taken?
a. Close the choke more
b. Continue – everything is okay
c. Increase the pump rate
d. Open the choke more
e. Reduce the pump rate

11. After 12200 strokes are circulated, the remote choke panel shows the following
readings:

Drill pipe pressure 490 psi

Casing pressure 0 psi
Pump speed 30 spm
Strokes pumped 12200 strokes
The choke now fully open and the casing pressure gauge reads 0 psi.
What action should be taken?
a. Close the choke more.
b. Reduce the pump rate
c. Stop pumping and continue drilling
d. Stop pumping, shut the well in and monitor pressures

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Driller’s method #01 Wait & Weight #01
1. B 1. C
2. E 2. E
3. C 3. E
4. B 4. A
5. D 5. C
6. B 6. E
7. B 7. A
8. A 8. A
9. A 9. B
10. C 10. A
11. C 11. B

Driller’s Method #02 Wait & Weight #02

1. E 1. C
2. E 2. B
3. A 3. B
4. A 4. D
5. D 5. C
6. A 6. E
7. B 7. D
8. D 8. E
9. B 9. B
10. D 10. A
11. C 11. D

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