P&P COMBINED SURFACE/SUBSEA LEVEL 2 EXAM

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1 / 31

When circulating the drilling fluid at 60 spm, the pressure on the stand pipe gauge reads 3500 psi.

What would the approximate standpipe pressure be if the pump speed was reduced to 30 spm?

1750 psi.

875 psi.

583 psi.

1166 psi.

2 / 31

After two hours of constant flow rate returns to the shaker house, the drilling fluid returns rate increases significantly.

Why should the shaker hand immediately inform the driller?

There are mud losses in the well bore, and the bottomhole pressure (BHP) may decrease.

The derrickman is transferring drilling fluid from an auxiliary pit to the active pit, and the driller should adjust the pit volume totaliser (PVT).

Formation fluids may have entered the well bore, and the driller may need to shut in the well

The mud engineer is mixing new drilling fluid volumes, which will affect the driller's fluid levels

3 / 31

The derrickman notices that the size of the cuttings returning to the shaker has increased.

What could this indicate?

There is a decrease in formation pressure.

Increasing formation pressure.

There is no change to formation pressure.

4 / 31

The driller shuts the pump down to start wet tripping out of the hole. The normal drain/flow volume into the active pit is exceeded.

What could this indicate?

The mud gas separator (MGS) is draining.

The trip tank is being filled.

There are losses.

There is a kick

5 / 31

A gas influx is shut in and migrates up the hole. What will happen to the volume of gas?

The gas influx volume increases.

The gas influx volume stays the same.

The gas influx volume decreases.

6 / 31

What is the main role of the driller in preventing well control incidents?

Taking actions to prevent abnormal pressures.

Taking actions to always keep the hole full.

Taking actions to prevent gas cut mud.

Taking actions to prevent lost circulation.

7 / 31

Which is a positive indication that a well is flowing?

Gas cut mud.

Increase in flow returns.

Increase in torque.

Decrease in pump pressure.

8 / 31

What is an important use of the stand-pipe manifold in the drilling circulating system? .

It is used to direct flow from the diverter to the mud gas separator (MGS).

It is used to control back flow from the drillstring.

It is used as primary barrier element when regularly pressure tested as part of the BOP test routine.

It is used to mount sensors and gauges measuring drillstring pressures.

9 / 31

While drilling, the driller increases the pump speed. How will this affect the pump pressure?

It will decrease.

It will stay the same.

It will increase

10 / 31

After pulling 20 stands of pipe out of the hole on a trip, the volume of drilling fluid required to fill the hole is less than the calculated value on the trip sheet. What action is required?

Immediately stop and flow check the well.

Pull another 5 stands, and check the resulting displacement figures.

Continue to pull out of hole. If a trip sheet is complete, everything should go as planned.

Query the figures on the trip sheet with the drilling supervisor and the tool pusher.

11 / 31

What is the hydrostatic pressure in a 12000 ft vertical well if the drilling fluid density is 15 ppg?

12 / 31

Why is it important to teach well control skills?

So that all personnel can fix simple problems with the BOPs.

So that everyone on the rig is aware of shallow gas.

So that everyone on the rig knows how to close the BOPs.

As we are responsible for keeping ourselves and our colleagues safe.

13 / 31

While drilling ahead, the derrickman transfers mud from the active pit into an auxiliary mud pit and forgets to inform the driller about the transfer.

How might the driller interpret the change in active pit level?

That there is a drilling break.

That there are losses.

That there is a change in the formation.

That there is a kick.

14 / 31

Which check is completed initially after a well is shut in, to ensure that the operation has been done correctly?

Check the trip tank level for flow.

Check the lines to cement unit.

Check that the diverter has closed successfully.

Check the kill mud levels in pits.

15 / 31

While drilling, the fluid density recorded in the shaker house is increasing.

What effect will this increase have on the bottomhole pressure (BHP)?

BHP will decrease.

There will be no change to BHP.

BHP will increase.

16 / 31

Which values are required to accurately calculate hydrostatic pressure? Choose two answers.

Casing shoe measured depth (MD).

Mud viscosity.

Fluid density.

Measured depth (MD).

True vertical depth (TVD).

17 / 31

What is the primary method of preventing kicks?

Using a suitable slow circulating rate pressure when killing the well.

Using pit capacity and flow rate measuring devices to recognise a kick.

Using BOPs to shut in a flowing well.

Using the fluid hydrostatic pressure to balance formation pressure.

18 / 31

During which operation, should trip tank levels be recorded?

When nippling down the BOP.

When nippling up the BOP.

When drilling.

When wireline logging.

19 / 31

How is bottom hole pressure (BHP) affected if there is a decrease in fluid density being circulated around the well?

BHP decreases.

BHP increases.

BHP stays the same.

20 / 31

What prevents formation fluid from entering the well bore during drilling?

A closed BOP stack.

A closed annular BOP.

An overbalanced hydrostatic pressure.

Static annular pressure losses.

21 / 31

Where is it required to record the 'kill rate circulating pressure'?

The remote choke panel pressure gauge.

The driller's pressure gauge.

The rig pump pressure gauge.

The mud logger's pressure sensor.

22 / 31

The friction losses for the well are:

Surface pressure losses:	100 psi
Bit nozzle pressure losses:	11300 psi
Drillstring pressure losses:	1900 psi
Annular pressure losses:	1300 psi

What will be the reading on the pump pressure gauge?

23 / 31

What well control principle does the driller's method and the wait and weight method have in common?

To keep pump pressure equal to the slow rate circulating pressure.

To keep pump pressure equal to the shut-in drillpipe pressure (SIDPP).

To keep annular pressure at least equal to the shut-in casing pressure (SICP).

To keep bottomhole pressure (BHP) at least equal to formation pressure.

24 / 31

During operations on a subsea rig, the dynamic positioning system is unable to keep station. After shutting in the well, why is it important to hang-off quickly?

As the well may be swabbed in.

As the operational limits of the riser will be exceeded.

As the emergency disconnect sequence (EDS) means that unshearable tool joints may be positioned across the blind/shear rams.

As the drillstring may become stuck downhole.

25 / 31

When drilling from a floating rig in shallow gas areas, why is it normal to drill tophole without a marine riser?

It provides a buoyancy effect for the rig if there is shallow gas.

It is easier to control the bottomhole pressure (BHP) while drilling without a marine riser.

It is easier to detect a kick on the flow and pit level alarms without a marine riser.

It is easier to move the rig off location in an emergency without a marine riser.

26 / 31

Please use the blank Subsea kill sheets and well data to answer the following 6 questions

Level 2 Subsea 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)
Internal capabilities:
Drill pipe, 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 x 2-13/16 inch	length 1116 feet, capacity; 0.0077 bbl/ft
Choke line, 2-1/2inch 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
Drill pipe/HWDP in casing	0.0478 bbl/ft
Drill pipe in riser	0.3638 bbl/ft
Mud pump data
Dispalcement at 98% volumertic efficiency	0.12 bbl/stroke
Slow pump rate data
@ 45 spm through the riser	880 psi
@ 45 spm 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 10 ppg mud	2100 psi
Kick data
The well kicked at 11850 ft depth vertical
Shut in drill pipe pressure	580 psi
Shut in casing pressure	870 psi
Pit gain	15 bbl
Mud density	10 ppg

The well will be killed using the Wait and Weight method.

Q26: How many strokes are required to pump kill mud from surface to bit?

27 / 31

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

28 / 31

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

29 / 31

What is the kill mud density?

30 / 31

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

31 / 31

What is the total annulus/choke line volume?

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