DRILLING P&P COMBINED SURFACE/SUBSEA LEVEL 4 R5 EXAM

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1 / 68

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 capacity	93 ft

What is the drop in hydrostatic pressure if 10 stands of pipe are pulled ‘wet’ without filing the well? (There are no returns to the well)

2 / 68

You are circulating an influx to surface using the first circulation of the driller’s method. The pump speed remains constant but the circulating pressure increases rapidly from 1100 psi to 1500 psi. Which action should you take?

Adjust the circulating pressure to 1100pso, by adjusting the choke and maintaining pump speed constant.

Adjust the circulating pressure to 1100psi by adjusting the pump speed.

Stop the pump, shut the well in, monitor the stabilized pressures, and investigate the problem.

Adjust the kill fluid density to compensate for the increase in well pressure.

3 / 68

While drilling ahead, a well kicks and is shut in. The shut-in drillpipe pressure (SIDPP) and shut-in casing pressure (SICP) begin to increase and then suddenly the SICP drops, followed by a sudden drop in SIDPP. What may have happened?

The bottomhole assembly has packed off

A weak formation has broken down

The drillstring has washed out

Gas has started to migrate up the well bore.

4 / 68

There is a total loss. Losses are measured at 10bbl/hour

Capacity of annulus and pipe contents	0.073 bbl/ft
Drilling fluid density	10.8 ppg

What will be the reduction in bottomhole pressure (BHP) after 3 hours if the hole cannot be filled?

231 psi

77 psi

300 psi

420 psi

5 / 68

In which situation would you use the lubricate and bleed method of well control?

When the gas is inside the drillstring

When gas has been allowed to migrate to surface when unable to circulate

When the float has failed in the drillstring

When surfaces pressures exceed the MAASP.

6 / 68

While displacing the well with kill fluid using the wait and weight method, when will the final circulating pressure (FCP) be reached?

When kill fluid reaches the bit

When the influx is circulated out of the well

When kill fluid reaches the casing shoe

When kill fluid is pumped down the drillstring

7 / 68

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 ft per hour is the gas bubble migrating?

129 ft/hour

513 ft/hour

1400 ft/hour

200 ft/hour

8 / 68

While drilling, the driller reports to the supervisor that the cuttings returning to the shakers have become splintered. What should the supervisor do?

This may be a kick warning sign, so communicate with the mud loggers to assess if there are other warning signs

This is a positive kick indicator, so instruct the driller to shut in the well.

This is normal, request for the return flow to by-pass the shale shakers.

This is normal, request a change of the shaker screens.

9 / 68

You have been monitoring returns on connections (fingerprinting) while drilling the current well section.
While circulating the estimated annular pressure loss (APL) is 350 psi.
On the last connection, the flowback is greater than had been previously. The well is shut in giving a stabilised shut-in casing pressure (SICP) of 225 psi. There is a non-ported float in the drillstring so you do not have a shut-in drillpipe pressure (SIDPP) reading.

What actions should you take to confirm the potential kick indicator?

As SICP is less than APL, open the BOP and continue with the connection.

Pump the float open to get the SIDPP, confirm there is pressure on the drillpipe and then circulate the well through the choke.

Pump the float to get SIDPP. If the SICP is greater than the SIDPP, this is normal and you can continue to make the connection

As the SICP is less than APL, bleed off the SICP by 350 psi and monitor the well.

10 / 68

You are diverting a shallow gas kick. What problems could this cause?

The well could bridge-over due to pumping kill fluid at a high pump rate

It will be difficult to track the pressure drop if kill fluid is pumped to the bit.

While diverting the shallow gas kick, the diverter system could quickly erode

The remote choke will become either plugged or washed out

11 / 68

When performing a leak-off test (LOT), which parameters must be accurately measured and recorded?

Fluid volume in open hole, density of the fluid used, and the true vertical depth (TVD)

Fluid volume pumped, density of the fluid used, and true vertical depth (TVD)

Pumping time until the leak-off, and the measured depth (MD)

Fluid volume in the casing, and measured depth (MD)

12 / 68

During a routine test, you see that the weep hole (drain hole/vent hole) on one of the ram type BOP bonnets is leaking drilling fluid. What action is required?

The weep hole only checks the closing chamber seals, leave it until the next maintenance schedule.

The ram packing elements on the ram body are worn out, replace them immediately.

Energise the secondary (emergency) seal. If the leak stops, leave it until the next maintenance schedule.

The primary ram shaft seal is leaking, secure the well and replace it immediately.

13 / 68

Which conditions are required to complete an accurate leak-off test (LOT)?

The exact fluid density, an appropriate pressure gauge, accurate measurement of pump volume, and the exact vertical depth of the casing shoe.

An accurate hole capacity, an accurate stroke counter, and the exact vertical depth of the casing shoe.

The exact fluid density, an accurate stroke counter, and the exact vertical depth of the casing shoe.

A fluid density sample, a fully rated pressure gauge, the calculated pumped volume, and the exact vertical depth of the casing shoe.

14 / 68

The driller fails to fill the hole when pulling out of the well. The drilling fluid level drops 580ft causing the well to flow.

Current drilling fluid density	11.9 ppg
True vertical depth (TVD)	9500 ft

What is the bottomhole pressure (BHP) when the well starts to flow?

15 / 68

There was a delay in shutting in the well and a large influx was taken. How would this affect surface shut-in pressures?

It will result in higher SICP but SIDPP will not be affected

It will result in higher SIDPP and SICP

It will result in a higher SICP and a lower SIDPP

It will result in a higher SIDPP, requiring a heavier kill fluid density

16 / 68

After a round trip at 9854 ft with 10.3 ppg drilling fluid, circulation is started at a constant pump rate and there is an increase in returns. The well is shut in with zero pressure on the drillpipe gauge and 200 psi on the casing gauge.
There is no float in the drillstring. What kill mud density will be required?

11.3 ppg

10.7 ppg

10.3 ppg

There is no way of working

17 / 68

During a well kill operation using the driller’s method, the choke pressure suddenly increases by 150 psi. after a short time, the operator sees the same pressure increase on the drillpipe pressure gauge. What is the most likely cause of this pressure increase?

A plugged nozzle in the bit

A second influx has entered the well

A wash out in the drillstring

The choke is partly plugged

18 / 68

A well is shut in after a kick on a surface BOP and will be killed using the wait and weight method.

Pre-recorded data
Vertical depth of well	10000 ft
Total string volume	1400 strokes
Total annulus volume	5700 strokes
Circulating pressure at kill rate (SCR)
At 30 SPM and 12.0 ppg fluid density	520 psi
Kick data
Shut-in drillpipe 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?

12.8 ppg

13.0 ppg

13.3 ppg

13.2 ppg

19 / 68

The production casing string of a well is displaced from drilling fluid to clean water. A cement bond log then identifies a poor cement job between the production and the intermediate casing string. If pressure builds up in the annulus between these casing strings, what is the immediate risk well integrity?

There could be differential sticking

The formation below the intermediate casing shoe could fracture

The production casing could burst

The equivalent circulating density (ECD) will increase.

20 / 68

A driller prepares to pull out of the hole and lines up to the slug pit. The driller then pumps a 20bbl heavy slug, followed by 10bbl of drilling fluid from the active pit.

Well data
Depth of hole (RKB)	9200 feet
Drilling fluid density	12.2 ppg
Heavy slug density	14.5 ppg
Drillpipe capacity	0.01776 bbl/ft
Surface line volume	6 bbl

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

213 ft

2243 ft

183 ft

263 ft

21 / 68

While killing a well, the drillstring is displaced to kill mud at a constant pump rate. There is a sudden loss in standpipe pressure, but no change in the casing pressure.

If the choke was closed to compensate for the reduction in pressure, how would this affect bottomhole pressure (BHP)?

BHP would increase

BHP would remain constant

BHP would decrease

22 / 68

While killing a well with a surface BOP, the pump speed is increased. What will happen to the casing pressure if the bottomhole pressure (BHP) is kept constant?

Casing pressure will increase

Casing pressure will decrease

Casing pressure will remain the same

23 / 68

When drilling at 10750 ft measured depth (MD), 9200 ft true vertical depth (TVD), the formation pressure is balanced by 10.6 ppg drilling fluid. A 250 psi trip margin must be included in the drilling fluid density.
What drilling fluid density is required?

24 / 68

In a vertical well with a long open hole section, which kill method will minimize the risk of losses at the casing shoe?

The bullheading method

The driller’s method

The wait and weight method

The volumetric method.

25 / 68

A well is drilled to a depth of 8200 ft TVD and the current density of the drilling fluid is 12.5 ppg. what will the pressure be at 4950 ft TVD if 580 psi pressure is applied from surface with the BOP closed?

3778 psi

2618 psi

3198 psi

4750 psi

26 / 68

In which situation would you expect formation fracture pressure to change?

When drilling into a new openhole formation.

When the BHA or bit is changed out.

Every time the drilling fluid density is changed.

When the shut-in drillpipe pressure (SIDPP) is higher than MAASP.

27 / 68

A water kick (with no associated gas) is circulated out of a vertical well with a surface BOP stack using water-based drilling fluid. When will the casing pressure reach its maximum?

Only when the kick reaches the casing shoe

Just after the kill fluid reaches the bit

When the kick is circulated out to surface

Immediately after the well is shut in and pressures stabilise

28 / 68

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

Well data
Drillpipe capacity	0.0178 bbl/ft
Drillpipe metal displacement	0.0082 bbl/ft
Average stand length	93 ft

9.28 bbl

1.65 bbl

2.42 bbl

0.76 bbl

29 / 68

During a kill operation with a surface Bop, which action is required to maintain constant bottomhole pressure when starting circulation? Ignore annular pressure loss (APL)

The pumps must be brought up to kill rate while reducing the casing pressure by a safety margin.

The pumps must be brought up to kill rate while holding the casing pressure constant

The drillpipe pressure should be kept constant while bringing the pumps up to kill rate

The pumps must be brought up to kill rate while increasing the drillpipe pressure by a safety margin above the original shut-in drill pipe pressure (SIDPP).

30 / 68

A vertical well is drilled to a depth of 8000ft

Overbalance	160 psi
Mud gradient	0.73 psi
Casing gradient	0.157 bbl/ft
Drillpipe 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)

46 stands

45 stands

47 stands

48 stands

31 / 68

What is one way to remove hydrates once they have formed?

Inject distilled water into the flow stream

Inject methanol into the affected equipment

Pressure test the well to maximum anticipated surface pressure

Bleed gas very quickly from surface equipment

32 / 68

You are about to run casing on a surface stack rig, with returns going to the trip tank. You will use a conventional double float system until the shoe reaches its final depth (20 ft from bottom). Use the data below to calculate the total volume of drilling fluid you need to keep the casing full

Well MD	11575 ft
Well TVD	10383 ft
Casing OD	9.625 in
Casing capacity	0.0787 bbl/ft
Casing metal displacement	0.1129 bbl/ft

815.6 bbl

911.0 bbl

909.4 bbl

817.1 bbl

33 / 68

Calculate the maximum allowable fluid density using the information below:

Well data
Casing shoe depth	8000 ft true vertical depth (TVD)
Leak-off test (LOT) pressure at pump	1500psi
Fluid density at the time of the LOT	10.4ppg

34 / 68

What is one positive indicator that the well is kicking?

An increase in cutting size

An increase in gas-cut drilling fluid

An increase in flow returns

An increase in torque

35 / 68

A vertical well on a surface BOP installation is killed using the wait and weight method. Initially, a quantity of original drilling fluid is pumped down the well instead of kill fluid. The quantity pumped equivalent to a volume of 1000ft of drillpipe. What action is required?

Increase the back pressure by the equivalent difference in drilling fluid hydrostatic

Ignore it, this mistake will only have a small effect on bottomhole pressure

Stop the pump and shut the well in. evaluate pressure, reset stroke counter and restart circulation

Bleed off the pressure from the drillpipe until the pumped volume is returned

36 / 68

During the second circulation of the driller’s method, which pressure must be kept constant when kill fluid is pumped to the bit to keep the bottomhole pressure (BHP) constant?

The accumulator pressure

The casing pressure

The drillpipe pressure

The well head pressure

37 / 68

In addition to the volume handling capacity of the choke and the annular friction losses during the kill operation, what other factor do you need to consider when selecting the circulating pressure kill rate (SCR)?

The size of the bit nozzles

The burst pressure of the casing

The volume capacity of the vacuum degasser

The mud gas separator (MGS) handling capacity

38 / 68

The drillers method is used to kill a well. Initial circulating pressure (ICP) is kept constant while pumping kill mud to the bit. What would happen to the bottomhole pressure (BHP)?

The BHP will decrease

The BHP will not change

The BHP will increase

39 / 68

While starting a well kill, the remote choke becomes stuck in the open position. Which action is required?

Decrease the pump rate to allow time to open the manual choke

Without stopping the pump, change over to the manual choke

Increase the pump rate to increase the annular friction losses

Stop the pump and close a valve upstream of the choke.

40 / 68

You are killing the well with a final circulating pressure (FCP) of 850 psi at 30spm. What will happen to the bottomhole pressure (BHP) if you increase the pump speed to 35spm while holding drillpipe pressure at 850psi?

BHP will increase

BHP will decrease

BHP will stay the same

41 / 68

Which statement is correct when comparing the driller’s method with the wait and weight method?

The wait and weight method requires more circulation time to kill the well than the driller's method

The wait and weight method allows you to start circulating out the influx sooner than the driller ’s method

The driller’s method allows you to start circulating out the influx sooner than the wait and weight method

The driller’s method gives a lower choke pressure than the wait and weight method

42 / 68

After killing a well through a subsea BOP stack, it is estimated that 2bbl of gas remains in the stack between the rams and the choke outlet

Pressure of the gas in the BOP	1385 psi
Atmospheric pressure	14.6 psi
Gas gradient	0.1 psi/ft

If the Bop was opened and the gas allowed to migrate to surface uncontrolled, what calculated volume
would be released at surface?

1900 bbl

200 bbl

170 bbl

290 bbl

43 / 68

After killing the well and displacing the riser to kill fluid, trapped gas remains in the subsea BOP. What fluid density must be displaced into the choke line to allow safe remove of the gas?

The choke line fluid density should be the same as fluid density in the riser annulus

The choke line fluid should be heavier than the fluid density in the riser annulus

The choke line fluid density should be lighter than that fluid density in the riser annulus

44 / 68

A gas kick is circulated out of a well, and the well is now dead

Well data
Shut-in casing pressure (SICP)	0 psi
Shut-in drillpipe pressure (SIDPP)	0 psi
Water depth	1000 ft
Riser length	1100 ft
Capacity of kill mud in the well and choke line	16.2 ppg
Original mud density in the well	12.2 ppg
Capacity of sea water	8.6 ppg

Calculate the estimated pressure of the gas trapped in the BOP beneath the closed pipe rams.

840 psi

230 psi

930 psi

700 psi

45 / 68

You may need to remove trapped gas from the upper rams on a subsea BOP stack after kill fluid returns to surface. What is the correct order of actions to take?

Isolate the wellbore by closing the lower pipe rams.
Circulate a lower density fluid into the choke line, open the choke to depressurize the gas.
Ensure the trip tank is circulating mud across the top of the riser
Open the upper pipe rams and allow the drilling fluid in the riser to U-tube into the choke line.

Open the upper pipe rams and allow drilling fluid to U-tube from the riser into the choke line.
Circulate kill fluid into the choke line and kill line.
Open the choke to depressurize the gas
Line up the trip tank to circulate across the riser

Open the choke to depressurize the gas, isolate the wellbore by closing the lower pipe rams.
Ensure the trip tank is circulating drilling fluid into the riser
Open the upper pipe rams and allow the drilling fluid to U-tube into the choke line.
Pump a lower density fluid into the choke line.

Ensure the trip tank is circulating drilling fluid into the riser
Open the choke to depressurize the gas and circulate a lower density fluid into the choke line.
Open the upper pipe rams and allow the drilling fluid to U-tube into the choke line.
Isolate the well bore by closing the lower pipe rams.

46 / 68

From a floating rig, the top-hole section is being drilled with a marine riser.

Well data
Drlling fluid density	9.6 ppg
Sea water density	8.6 ppg
Well depth	1700 ft TVD
Water depth	1000 ft
Riser length	1100 ft

While drilling at this depth, the drilling fluid gives an overbalance of 50 psi on the formation pressure. What drilling fluid density is required to allow the riser to be disconnected and maintain the same overbalance?

10.8 ppg

9.6 ppg

12.9 ppg

11.3 ppg

47 / 68

A well is shut in on a floating rig, and the following data is recorded:

Shut-in drillpipe pressure (SIDPP)	400 psi
Shut-in casing pressure (SICP)	600 psi
Kill line pressure	700 psi

What may have caused the different readings on the kill line and choke line gauges?

The fluid in the kill line has a higher density than the fluid in the choke line

The fluid in the kill line has a lower density than the fluid in the choke line

The BOP side outlet hydraulic valve on the kill line is partly closed

There is a partial blockage in the choke line.

48 / 68

Well data
Total vertical depth	1090 ft
Vertical depth of casing shoe	6500 ft
Slow pump rate pressure at 30spm through riser	580 psi
Slow pump rate pressure at 30spm through choke line	870 psi
Original drilling fluid density	9.6 ppg
Kill fluid density/td>	10.7 ppg

Using the wait and weight method, kill fluid is now back at surface, and the well is now circulated through a fully open choke. What is the bottomhole pressure (BHP) at this point in the operation? Ignore the dynamic pressure loss in the annulus.

The BHP will be less than the formation pressure as gas is trapped between the chole line and the closed annular preventer

BHP will be equal to the formation pressure, plus a riser margin

BHP will be equal to the formation pressure, plus choke line friction

BHP will be equal to the formation pressure.

49 / 68

What is one method that you can use to measure choke line friction (CLF) on a floating rig?

Circulate at the kill rate down the choke line and up the riser. The pump pressure is the CLF

Shut in the well and then record the CLF

Circulate at the kill rate down the choke line and up the kill line. The pump pressure is half the CLF

Circulate at the rate down the kill line and up the choke line with a half-open choke. The pump pressure is four times the value of the CLF.

50 / 68

Please use the blank Surface kill sheets and well data to answer the following 11 questions

Level 3 & 4 Surface Kill Sheet Section - Group 1

Well Data
Hole size	8-1/2 inch
Hole depth	11850 feet (TVD/MD)
Casing shoe, 9-5/8 inch	8880 feet (TVD/MD)
International Capabilities
Drillpipe, 5 inch	0.0172 bbl/ft.
Heavy weight drill pipe, 5 inch	length 837 feet, capacity; 0.0088 bbl/ft
Drill collars, 6-1/2 inch ID	length 1116 ft, capacity; 0.0077 bbl/ft
Choke line, 2-1/2 inch ID	length 553 feet, capacity; 0.0061 bbl/ft
Marine riser	length 540 feet, capacity; 0.3892 bbl/ft
Annulus capacities between
Drill collars in open hole	0.0292 bbl/ft
Drill pipe/HWDP in open hole	0.0447 bbl/ft
Drillpipe/HWDP in casing	0.0478 bbl/ft
Drill pipe in riser	0.3638 bbl/ft
Mud pump data
Displacement at 98% volumetric efficiency	0.12 bbl/stroke
Slow pump rate data
@ 45spm through the riser	880 psi
@ 45spm through the choke line	1000 psi
Other relevant information
Active surface fluid volume	460 bbl
Drill pipe closed end displacement	0.0254 bbl/ft
Formation strength test data
Surface leak-off pressure with 10ppg mud	2100 psi
Kick Data
The well kicked at 11850 ft vertical depth
Shut in drill pipe pressure	580 psi
Shut in casing pressure	870 psi
Pit gain	15 bbl
Mud density	10 ppg
Diagrams

The well will be killed using the Wait and Weight method

Q50:When the pressures had stabilized after 12 minutes, the instrumentation on the remote choke panel showed the following

Calculate the amount of extra pressure that can be applied, in this static condition, before the casing shoe breaks down

51 / 68

How many strokes are required to pump kill mud from surface to bit?

52 / 68

How many strokes are required to pump from the bit to casing shoe?

53 / 68

How much time is required to calculate the total well system?

54 / 68

How many strokes are required to displace the marine riser to kill fluid before opening the BOP?

55 / 68

What is the kill mud density?

56 / 68

What is the initial circulating pressure (ICP)?

57 / 68

What is the final circulating pressure (FCP)

58 / 68

What is the initial dynamic casing pressure at kill pump rate?

59 / 68

What is MAASP after circulation of the kill mud?

60 / 68

Calculate the pressure drop per 100 strokes of kill fluid pumped inside the drillstring.

61 / 68

Please use the information from the pre-filled kill sheets to answer the following 8 questions

Q61: The well will be killed using the driller’s method at 45spm. Ignore the surface line volume. The first circulation is started.
Immediately after the last choke adjustment, the remote choke panel gauges show the following readings

What action should be taken?

Continue – everything is okay

Open the choke more

Reduce the pump rate

Increase the pump rate

Close the choke more

62 / 68

After 4000 strokes are circulated, the remote choke panel shows the following readings:

What is the first action to take?

Close the choke more

Open the choke more

Increase the pumps rate

Continue – everything is okay

Reduce the pump rate

63 / 68

After taking the action (from the previous question), what is the next immediate action to take?

Close the choke more

Reduce the pump rate

Continue – everything is okay

Open the choke more

Increase the pump rate

64 / 68

After 6900 strokes are circulated, the remote choke panel shows the following readings:

What action should be taken?

Reduce the pump rate

Close the choke more

Continue – everything is okay

Open the choke more

Increase the pump rate

65 / 68

After 8800 strokes are circulated, the remote choke panel shows the following readings.

What action should be taken?

Increase the pump rate

Open the choke more

Reduce the pump rate

Continue – everything is okay

Close the choke more

66 / 68

After 10500 strokes are pumped, the influx is circulated out through the remote choke. What is the stabilized shut-in drillpipe pressure (SIDPP) if the pump is stopped and the well shut in correctly?

1450 psi

870 psi

580 psi

0 psi

67 / 68

What is the stabilized shut-in casing pressure (SICP) if the pump is stopped and the well is shut in correctly?

580 psi

0 psi

1450 psi

870 psi

68 / 68

The pump stroke counter is reset to zero. While pumping the kill fluid, the remote choke panel shows the following readings:

What action should be taken?

Increase the pump rate

Reduce the pump rate

Continue – everything is okay

Open the choke more

Close the choke more

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