DRILLING P&P SURFACE LEVEL 4 R4 EXAM

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1 / 64

A kick is circulated out at 40 spm on surface BOP stack. Drillpipe pressure is 650 psi and the casing pressure is 1050 psi. The pumps are slowed to 30 spm while maintaining 1050 psi on the casing gauge.

How will this affect bottomhole pressure (BHP)? Exclude any equivalent circulating density (ECO) effects.

BHP will increase.

BHP will stay the same.

BHP will decrease.

2 / 64

A driller prepares to pull out of the hole and lines 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 (RKB):	9200 ft
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 dro p when the well has equalised?

213 ft.

1143 ft.

183 ft.

263 ft.

3 / 64

Using the trip sheet below, what action should the supervisor take?

Note: The pipe will be pulled dry.

Drillpipe capacity: 0.0177 bbl/ft Drillpipe displacement: 0.0069 bbl/ft
Stands pulled	Length pulled (ft)	Total length (ft)	Calculated displacement (bbl)	Trip tank volume (bbl)
-	-	-	-	15
1-5	462	462	3.2	11.8
6-10	464	926	3.2	8.6
11-20	930	1856	6.4	2
15 bbl added to the trip tank				18
21-30	928	2784	6.4	11.6
31-40	927	3711	6.4	5.2

Stop tripping, flow check the well. If flow is confirmed, run back to bottom.

Stop tripping, flow check well. If there is no flow, continue to pull out of hole.

Stop tripping, flow check the well. If there is no flow, circulate the well.

Stop tripping, flow check the well. If there is no flow, run back to bottom.

4 / 64

While displacing the well with kill fluid during the second circulation of the driller's method, when will the final circulating pressure (FCP) be reached?

As kill fluid is being pumped down the drillstring.

When kill fluid reaches the casing shoe.

Once the influx is circulated out of the hole.

When kill fluid reaches the bit.

5 / 64

How is lost circulation detected during a well control operation? Choose three answers.

An unexpected requirement to close the choke to maintain the drillpipe pressure.

By monitoring the drilling fluid density.

By monitoring the drilling fluid volume in the mud tanks against predicted values.

By monitoring the trip tank levels.

By monitoring the U-tube pressure gauge.

By monitoring the flowline flow rate indicator against the predicted values.

By monitoring annulus and drillpipe pressures against predicted values.

6 / 64

Shortly after starting the first circulation of the driller's method, the drillpipe becomes plugged and you cannot circulate or read the drillpipe pressure. You have indications that the gas kick is migrating.

Which well control procedure should you apply?

The driller's method.

Reverse circulation.

The wait and weight method.

The volumetric method.

7 / 64

A vertical well is shut in on a surface BOP installation. During the second circulation of the driller's method, when should the surface casing pressure first decrease?

As the kill fluid enters the annulus.

When the kill fluid is halfway down the drillstring.

Immediately before the kill fluid reaches the bit.

As the kill fluid reaches the casing shoe.

8 / 64

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.

9 / 64

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 effect bottomhole pressure (BHP)?

BHP would increase.

BHP would remain constant.

BHP would decrease.

10 / 64

A cement bond log has identified a poor cement job between the production casing string and the intermediate casing string. Pressure has built up in the annulus, between these casing strings. What is the long-term risk to well control?

There could be differential sticking.

The intermediate casing could burst.

The equivalent circulating density (ECO) will increase.

The production casing could burst.

11 / 64

What is one essential requirement of a management of change (MOC) procedure?

Changes to drilling procedures only require authorisation and documentation by the assistant driller.

A change to procedure can be authorised using a previous risk assessment.

Only the accountable manager can do a MOC risk assessment.

All changes to a procedure require authorisation and documentation by the accountable manager.

12 / 64

The drilling programme requires that the casing shoe is drilled out and a leak-off test (LOT) is performed 12 ft below the shoe depth. However, premixed mud is added to the active system and the fluid density in the suction tank is varying by 0.5 ppg.

In this situation, which action is required to give an accurate LOT result?

Condition the fluid until you are certain of constant fluid density in the well, before doing the LOT.

Stop the pump after every 10 gallons and use the stabilised drillpipe pressure for the LOT.

Select the lowest fluid density and use it to perform the LOT.

Using the cement unit, slowly pump down the drillpipe using pump pressure for the LOT.

13 / 64

Which parameter would affect the leak-off test (LOT) pressure?

The pressure limit for the fluid pump.

The volume of fluid in the annulus from casing shoe to surface.

The hydrostatic pressure at the casing shoe.

The fluid pump circulating rate for the next drilling operation.

14 / 64

What would the shut-in drillpipe pressure (SIDPP) read if 10 bbl of gas 0.1 psi/ft is swabbed into
the horizontal section of an 8-1/2 in well?

Well data:
Current fluid density:	112.2 ppg
True vertical depth (TVD):	12895 ft
Hole capacity:	0.0820 bbl/ft

80 psi.

0 psi.

8180 psi.

65 psi.

15 / 64

What is one advantage of the wait and weight method compared to the driller's method in vertical wells?

The wait and weight method always produces a lower pressure against the open hole compared to the driller's method.

There is no advantage of using the wait and weight method compared to the driller's method.

The wait and weight method produces a lower choke pressure at the start of a kill operation.

The wait and weight method produces lower risk of formation breakdown if the volume of the openhole is greater than the volume of the drillstring.

16 / 64

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 bottomhole 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 metal displacement	0.00751 bbl/ft

17 / 64

Calculate the rate of gas migration, in feet per hour, from the data below.

Shut-in drillpipe pressure increased by 50 psi in 15 minutes.
Fluid density is 10.5 ppg.

18 / 64

What should you do if an annular BOP fails its pressure test?

You do not need to retest it until the next planned test date.

No action is required if the rams are successfully tested.

You should repair it immediately and then re-test it.

You should remove the annular from service.

19 / 64

Well data:
13-3/8 in casing set at:	;49:l1 tt true vertical depth l 'VU)
Formation strength at the shoe:	3626 psi (determined by a leak-off test)
Current fluid density:	10 ppg

What is the maximum allowable annulus surface pressure (MAASP)?

3045 psi.

1067 psi.

1807 psi.

425 ps.

20 / 64

In addition to the handling capacity of the mud gas separator (MGS) and the volume capacity of the choke, what other factor do you need to consider when selecting the pump rate for killing the
well?

The volume capacity of the vacuum degasser.

The burst pressure of the casing.

The size of the bit nozzles.

Annular friction losses during the kill operation.

21 / 64

The pit level increases when the pumps are off, but the pit level stays constant when the pumps are running. What could be the problem?

Annular pressure losses are oreating an overbalance that prevents the well from flowing.

The pump pressure is greater than the hydrostatic pressure.

The hydrostatic pressure is greater than the formation pressure.

The pumps have failed.

22 / 64

What is the reduction in bottomhole pressure (BHP) if the drilling fluid level dropped by 800 ft with a density of 10.5 ppg?

23 / 64

During a well control operation, you see casing pressure rapidly increasing.

You tell the driller to shut down the pump to prevent over-pressuring the openhole.

What could have caused the rapid increase in casing pressure?

A plugged bit nozzle.

A plugged choke.

A lost bit nozzle.

A washout in the drillpipe.

24 / 64

On a trip out of hole, the hole was filled correctly while pulling drillpipe. The hole fill pump was stopped and the complete BHA was pulled dry.

Hole size	12-1/4 in
Casing shoe depth	1500 ft
Length of BHA	400 ft
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
Drilling fluid density

What is the expected decrease in bottomhole pressure (BHP)?

188 psi.

210 psi.

205 psi.

100 psi.

25 / 64

At what stage of a kill operation can choke pressure readings exceed MAASP without breaking down the formation at the shoe?

When the influx is above the casing shoe.

When the influx is in the open hole section.

When the influx is on bottom.

As kill fluid is circulated to the bit.

26 / 64

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

Current drilling fluid density	111.9 ppg
True vertical depth (TVD)	9500 ft

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

27 / 64

The measured gas percentage in the drilling fluid increases from 8% to 15% over one day. What should you instruct the driller to do?

Immediately stop drilling, shut the BOP and monitor for pressures.

Call the mud loggers to confirm that their instruments have been calibrated within the last week.

Increase the weight on bit (WOB) to compensate for the increase in gas, and stop flow checking on connections.

Carefully monitor for additional warning signs as the formation pressure may be increasing.

28 / 64

In which situation can hydrates form?

When there is a water influx while using water-based fluid.

When there is an oil influx while using water-based fluid.

When there is a natural gas influx while using water-based fluid.

When there is a natural gas influx while using oil-based fluid.

29 / 64

During a well kill operation, using the driller's method, the casing pressure gauge reading suddenly increases by 150 psi.

After a short time, the operator sees a 150 psi pressure increase on the drillpipe pressure gauge.

What is the correct action to take?

Shut in the well and change to the spare standpipe.

Reduce the pump rate to decrease both pressures by 150 psi.

This is normal, continue with the operation.

Shut in the well and change to another choke.

30 / 64

While drilling, the derrickman asks the driller to reduce the pump rate so that the shakers can handle an increase in cuttings in the mud returns.

What should the driller do?

Stop drilling and flow check. If there is no flow, circulate bottoms up at a reduced rate so that the shakers can handle the cuttings volume.

Stop drilling and flow check. If there is no flow, continue at the same rate allowing the excess to bypass the shakers and get caught in the sand traps.

Stop drilling and flow check. If there is no flow, continue using the original drilling parameters.

Continue drilling and reduce the pump rate until the shakers can handle the capacity of cuttings in the mud returns.

31 / 64

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 is equivalent to a volume of 1000 ft 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 pressures, reset stroke counter and restart circulation.

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

32 / 64

Calculate the maximum allowable mud weight using the information below:

Well data:
Casing shoe depth:	6350 ft TVD
Leak-off test pressure at pump:	1420 psi
Density of drilling fluid at test:	9.8 ppg.

33 / 64

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.

34 / 64

Leak-off test data
Casing shoe MD
Casing shoe TVD
Surface leak-off pressure at 6090 ft
Maximum allowable fluid density

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

Kick data
Hole depth MD
Hole depth TVD
SIDPP	140 psi
SICP	180 psi
Pit gain	8 bbl
Drilling fluid density	13.5 ppg

87 psi.

47 psi.

18 psi.

No margin.

35 / 64

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 4920 ft TVD if 580 psi pressure is applied from surface with the BOP closed?

3778 psi.

2618 psi.

3198 psi.

4750 psi.

36 / 64

You are working on a rig that has a large surface line volume (from the mud pumps to the drill floor).

The wait and weight method will be used. The pump stroke counter was not reset to zero when the kill fluid reached the drill floor.

How will this affect the bottomhole pressure when pumping kill fluid to the bit, in line with the step down chart schedule?

The BHP will be higher than required.

The BHP will not be affected.

The BHP will be lower than required.

37 / 64

After pulling ten stands out of the hole, the fluid it takes to fill the hole from the tank is less than calculated on the trip sheet.

What action is required?

Flow check. If there is no flow, continue to pull out of the hole to surface.

Pump the remaining stands out of the hole.

Flow check. If there is no flow, run back to bottom while monitoring returns.

Flow check. If there is no flow, displace a heavy slug into annulus and continue to pull out of hole.

38 / 64

When drilling a horizontal section of a well, there is a gas kick and the well shut in.

If the influx is in the horizontal section, what shut-in drillpipe pressure (SIDPP) and shut-in casing pressure (SICP) values would you expect to see on the pressure gauges?

SIDPP would be the same as SICP.

SICP would be higher than SIDPP.

SIDPP would be higher than SICP.

39 / 64

An influx is shut in on a surface BOP installation, and the initial stabilised shut-in pressures are:

Shut-in drillpipe pressure (SIDPP):	500 psi
Shut-in casing pressure (SICP):	900 psi

After the first circulation of the driller's method is complete, the well is shut in and the pressures stabilise. They then read:

SIDPP:	500 psi;text-align:left;
SICP:	600 psi

What could be the next action?

Bullhead the annulus until SICP is reduced to 500 psi.

Continue with second circulation of driller's method, holding drillpipe pressure constant until kill fluid reaches the bit.

Reverse circulate until SICP is reduced to 500 psi.

Circulate the kill mud using the step-down chart or graph.

40 / 64

Which critical pressure is calculated using the results of the leak-off test (LOT)?

Maximum allowable annular surface pressure (MAASP).

Final circulating pressure (FCP).

Initial circulating pressure (ICP).

Dynamic casing pressure.

41 / 64

During well kill operations, what will happen when bringing the pumps up to kill speed if the casing pressure is allowed to increase above shut-in casing pressure (SICP)?

Down hole pressure would decrease and may cause more of the influx to enter the well bore.

The drillpipe pressure will decrease and may allow more of the influx to enter the wellbore.

Downhole pressure would increase and may exceed the formation fracture gradient.

The increased SICP will have no effect on bottomhole pressure (BHP).

42 / 64

The driller shuts in the well on a kick. The drillpipe pressure is zero because there is a float (non-return) valve in the drillstring.

What action should be taken to establish the shut-in drillpipe pressure (SIDPP)?

Shear the pipe and read the SIDPP directly off the casing gauge.

Pump very slowly into the drillstring with the well shut in. When casing pressure starts to rise, stop the pump and read the drillpipe pressure. This is the SIDPP.

Bring the pump up to kill rate holding the casing pressure constant by opening the choke. The pressure shown when the pump is at kill rate is the SIDPP.

Pump at kill rate into the drillpipe and annulus with the well shut in. When the pressure equalises the float will open. This pumping pressure is the SIDPP.

43 / 64

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:	520 psi
KICK data:
Shut-in drillpipe pressure (SIDPP):	480 psi
Shut-in casing pressure (SICP):	1650 psi
Drilling fluid density in the well:	12.0 pg

What is the final circulating pressure (FCP) at 30 SPM?

752 psi.

607 psi.

564 psi.

720 psi.

44 / 64

Calculate the volume of drilling fluid required to fill the hole per stand when pulled 'wet', drilling fluid 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.

45 / 64

Please use the blank Surface kill sheets and well data to answer the following 9 questions

Level 3 & 4 Surface Kill Sheet Section - Group 1

Well Data
Hole Size	8-1/2 inch
Hole Depth	12336 feet. TVD/MD
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	6-1/4 inch, 902 feet long, capacity 0.006 bbl/ft
Mud density	14.1 ppg

Capacities
Drill collars in open hole	0.0322 bbl/ft
Drill pipe/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 bbl

The well will be killed using the Driller's Method at 30 spm

Q45: How many strokes are required to pump kill mud from surface to bit?

46 / 64

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

47 / 64

How many strokes are required to pump from the bit to surface?

48 / 64

What is the kill mud density?

49 / 64

What is the initial circulating pressure?

50 / 64

What is the final circulating pressure?

51 / 64

What is the MAASP at the time the well was shut in?

52 / 64

What is MAASP after circulation of the kill mud?

53 / 64

What is the time for one complete circulation?

54 / 64

Q54: The well will be killed using the wait and weight method at 30 SPM. Ignore the surface line volume.

After 50 strokes are circulated, the remote choke panel shows the following readings

Drillpipe pressure:	769 psi
Casing pressure:	638 psi
Pump speed:	24 SPM
Strokes circulated:	50 strokes

What action should be taken?

Close the choke more.

Reduce the pump rate.

Open the choke more.

Increase the pump rate.

Continue - everything is okay.

55 / 64

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

Drillpipe pressure:	896 psi
Casing pressure:	660 psi
Pump speed:	30 SPM
Strokes circulated:	240 strokes

What action should be taken?

Continue - everything is okay.

Open the choke more.

Close the choke more.

Reduce the pump rate.

Increase the pump rate.

56 / 64

After 420 strokes are circulated, the remote choke panel shows the following readings

Drillpipe pressure:	830 psi
Casing pressure:	680 psi
Pump speed:	30 SPM
Strokes circulated:	420 strokes

What action should be taken?

Increase the pump rate.

Continue - everything is okay.

Close the choke more.

Open the choke more.

Reduce the pump rate.

57 / 64

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

Drillpipe pressure:	750 psi
Casing pressure:	800 psi
Pump speed:	30 SPM
Strokes circulated:	600 strokes

What action should be taken?

Increase the pump rate.

Reduce the pump rate.

Open the choke more.

Close the choke more.

Continue - everything is okay.

58 / 64

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:

Drillpipe pressure:	0 psi
Casing pressure:	730 psi
Pump speed:	0 spm
Strokes circulated:	1500 strokes

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

What action should be taken?

Calculate the new kill fluid density and pump rate.

Everything is okay, continue the kill procedure with 40 spm but keep the same FCP.

Start-up the kill procedure by holding casing pressure constant, while bringing the pump up to kill speed, then hold the observed drillpipe pressure constant.

Start-up the kill procedure by holding the drillpipe pressure constant, while bringing the pump up to kill speed, then hold the observed casing pressure constant.

59 / 64

After 3050 strokes are circulated, the remote choke panel shows that the casing pressures is decreasing. A short time later, the drillpipe pressure also decreases.

Drillpipe pressure	420 psi
Casing pressure	690 psi
Pump rate	30 spm
Strokes circulated	3050 strokes

What action should be taken?

A lost bit nozzle.

A pump problem.

A plugged choke.

A plugged bit nozzle.

A washout in the choke.

A washout in the drillpipe.

60 / 64

After identifying the problem (from the previous question), what is the first action to take?

Open the back-up choke to increase casing pressure.

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

Close the choke to increase the casing pressure.

Increase the pump rate to increase equivalent circulating density (ECO).

61 / 64

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

Drillpipe pressure:	490 psi
Casing pressure:	720 psi
Pump rate:	33 spm
Strokes circulated:	3070 strokes

What action should be taken?

Close the choke more.

Open the choke more.

Reduce the pump rate.

Continue - everything is okay.

Increase the pump rate.

62 / 64

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

Drillpipe pressure:	490 psi
Casing pressure:	800 psi
Pump rate:	30 spm
Strokes circulated:	8000 strokes

What action should be taken?

Reduce the pump rate.

Open the choke more.

Continue - everything is okay.

Close the choke more.

Increase the pump rate.

63 / 64

After 9000 strokes are circulated, the remote choke panel shows the following pressures:

Drillpipe pressure:	410 psi
Casing pressure:	840 psi
Pump speed:	30 spm
Strokes circulated:	9000 strokes

What action should be taken?

Increase the pump rate.

Continue - everything is okay.

Close the choke more.

Reduce the pump rate.

Open the pump more.

64 / 64

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

Drillpipe pressure	490 psi
Casing pressure	0 psi
Pump rate	30 spm
Strokes circulated	12200 strokes

The choke is now fully open, and the casing pressure gauge reads 0 psi.

What action should be taken?

Stop pumping and continue drilling.

Stop pumping, shut the well in and monitor the pressures.

Close the choke.

Reduce the pump rate.

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