DRILLING EQUIPMENT SURFACE LEVEL 3 EXAM

Enter your ACCESS PASSWORD

Fill in your information

NameEmailPhone Number

1 / 41

While pulling out of the well, there is a kick. The drop-in back pressure valve is dropped pumped down, and the well is shut in.

After a short duration, the pressure on the drillpipe gauge continues to increase.

What could cause this pressure increase? Choose two answers.

The drop-in back pressure valve is not yet seated.

The choke valve is still open.

The stabilisers are balled up.

The internal sealing surface of the sub is washed out by the mud flow.

The bit nozzles are plugged.

2 / 41

1 x 10000 psi rated annular preventer
1 x 10000 psi rated 5 in pipe rams
1 x 10000 psi rated blind/shear rams
1 x 15000 psi rated drilling spool
1 x 10000 psi rated 5 in pipe rams

What is the maximum wellbore rated pressure of this stack?

55000 psi.

10000 psi.

15000 psi.

20000 psi.

3 / 41

Figure A30-0002 shows a typical piping schematic for a surface BOP installation. The well is shut in on the annular BOP.

Mud will be circulated from the mud pumps through the drillstring and bled off through the remote choke to the mud tanks. Which groups of valves must be open?

Valve Nos. 2, 3, 5, 8, 9, 10, 11, 12, 15, 17, 20.

Valve Nos. 2, 3, 5, 8, 9, 10, 11, 12, 13, 18, 20.

Valve Nos. 1, 3, 4, 6, 7, 8, 9, 10, 11, 12, 15, 17, 20.

Valve Nos. 2, 3, 5, 8, 9, 10, 11, 14, 16, 19, 20.

4 / 41

What is the normal annular pressure gauge reading on a 3000 psi hydraulic BOP control unit?

500-1500 psi.

0 psi.

3000 psi.

250 psi.

5 / 41

Figure A23-0001 shows a hydraulic control schematic for a BOP control system. What valves should be closed while drilling?

Figure A23-0001

Typical blowout preventer closing unit arrangement

Valves; 2, 4, 8, 10, 11, 14.

Valves; 1, 4, 9, 10, 12, 15.

Valves; 3, 4, 6, 9, 11, 16.

Valves; 3, 5, 7, 9, 13, 18.

6 / 41

What is the purpose of an inflow test?

To test that there is flow through a downhole barrier element, by applying negative pressure upstream of the barrier element.

To test that there is no flow from a downhole barrier element, by pumping down the string and back up the annulus.

To test a well barrier in the direction of flow, while applying pressure downstream to give a pressure differential.

To test a well barrier in the direction of flow, while reducing pressure downstream to give a pressure differential.

7 / 41

What type of ring gaskets are pressure energised?

All ring gaskets.

Type BX.

Type R oval.

Type R octagonal.

8 / 41

The driller closes the upper rams from the remote control panel. The green light indicator turns off and the red light indicator does not turn on. The accumulator pressure and the manifold pressure readings decrease and then return to normal. What could be the cause of this malfunction?

There is a leakage on the hydraulic circuit.

There is an electrical fault with the lights.

The 3-position/4-way valves on the hydraulic BOP control unit did not move.

The rams did not close.

9 / 41

In the diagram of a 10000-psi (10K) surface BOP stack (Figure A60-0001), why is the kill line outlet placed below the lower pipe rams?

Figure A60-0001

To allow the well to flow to the flare line.

To be able to bullhead the well if the lower pipe rams is closed.

To allow the use of the volumetric method.

To kill the well using the driller's method or the wait and weight method.

10 / 41

The mud gas separator (MGS) shown in Figure A41-0001 has the following dimensions:

H1 - body height	30 ft
H2 - dip tube height	10 ft
H3 - derrick vent line height	150 ft
D1 - separator body diameter	5 ft
03 - derrick vent line diameter	10in
04 - mud/gas inlet diameter	4in
Drilling fluid density	10 ppg

What would be the maximum operating pressure of this MGS when an oil kick with a density of 6 ppg is circulated through it?

9.3 psi.

9.36 psi.

3.12 psi.

46.8 psi.

11 / 41

What does a vacuum degasser do?

It removes large volumes of gas from the drilling fluid upstream of the. shale shakers.

It removes gas from the drilling fluid downstream of the shale shakers.

It is used to remove excess barite from the drilling fluid downstream on the shale shakers.

It removes drill solids from the drilling fluid upstream of the shale shakers.

12 / 41

Why is a master control valve fitted to the remote BOP control panel on the rig floor?

To activate the open or close lights.

To adjust pipe ram closing pressure.

To activate power to the control unit charge pumps.

To ensure that all BOP functions are 'two hand' operated from the Driller's remote panel.

13 / 41

Which statements are correct about diverter vent lines? Choose two answers.

Diverter vent lines must have a large internal diameter to reduce back pressure.

Diverter vent lines must have bends to create back pressure.

Diverter vent lines must be routed directly to the mud gas separator (MGS).

Diverter vent lines must have small internal diameters to create back pressure.

Diverter vent lines must be as straight as possible.

14 / 41

When selecting the type of rubber for a surface annular preventer, what operating factors must you consider?

Drilling fluid type and the anticipated temperature.

Wear-resistance and wetted elastomeric type.

Circulating wellbore pressures.

Maximum shut-in pressures.

15 / 41

While drilling tophole with an insert type diverter, what must you do when running or pulling the bottomhole assembly (BHA)?

Reduce the diverter packer pressure to zero.

Open the vent line.

Remove the insert packer.

Grease the tool joints.

16 / 41

Which functions on a BOP are supplied from the manifold pressure? Choose two answers.

The ram BOPs.

No BOP stack functions.

All BOP stack functions.

The annular BOP.

The hydraulically operated choke and kill line valves.

17 / 41

While drilling, what would be the normal hydraulic pressure in the ram opening lines on a surface stack BOP?

500 psi.

3000 psi.

Zero.

1500 psi.

18 / 41

What is one function of a weep hole (drain or vent hole) on a ram type BOP?

To indicate that the primary ram shaft seal is leaking.

To indicate if the ram body rubbers are leaking.

To indicate if the closing chamber operating pressure is too high.

To indicate if the bonnet seals are leaking.

19 / 41

During a well control event, clean drilling fluid is circulated into the mud gas separator (MGS) through the 'hot loop'. Which tank must the drilling fluid come from to allow you to monitor pit levels?

The active tank.

The pre-mix tank.

The trip tank.

The reserve tank.

20 / 41

On a surface BOP installation, the driller simultaneously pushes the 'master' and 'choke open' buttons on the remote panel and the lights change colour. What do the changing lights confirm?

The panel has functioned correctly and the choke line valve is now closed.

The panel has correctly functioned and the choke line valve is now open.

The panel has not functioned correctly, but the choke line valve is now open.

The panel has correctly functioned and hydraulic opening pressure is applied to the choke line valve.

21 / 41

What are the main components of a diverter system? Choose two answers.

A high pressure ram type preventer with a large internal diameter.

A vent line of sufficient diameter to allow safe venting and disposal of flow from the well.

A vent line of sufficient diameter to permit safe venting using the mud gas separator (MGS).

A low pressure annular preventer with a large internal diameter.

A vent line of small diameter, sufficient to create a 'back pressure' on bottom while circulating.

22 / 41

What precautions should you take when fitting a BX ring gasket?

The gasket and ring groove should be wrapped in teflon tape and then fitted.

The gasket and ring groove should be coated in environmentally friendly oil and then fitted.

The gasket and ring groove should be coated in waterproof grease and then fitted.

The gasket and ring groove should be wiped clean and then fitted dry.

23 / 41

What happens when a diverter is closed?

The diverter and vent valve both open at the same time.

The diverter and vent valve close at the same time.

The diverter closes and then the vent valve opens.

The vent valve opens and then the diverter closes.

24 / 41

Some mud gas separators (MGSs) are fitted with hot mud inlets (shown in the diagram A41-0003).

What is the main reason for this feature?

Figure A41-0003

To fill the vessel with light fluid to increase MGS efficiency.

To displace the liquid seal to clean mud every 12 hours.

To keep the liquid seal full of clean, uncontaminated mud during well control operations.

To increase the rate at which mud and gas separates.

25 / 41

You shut in the well using the pipe rams on a surface BOP stack. What indications would you see at the BOP remote control panel to let you know that the pipe rams have closed correctly?

The pipe ram indicator light would change from green to red. The accumulator pressure would increase.

The pipe ram indicator light would change from green to red. The manifold pressure would drop and then build back up.

The pipe ram indicator light would change from green to red. The annular pressure would drop and then build back up.

The pipe ram indicator light would change from red to green. The manifold pressure would drop and then build back up.

26 / 41

If the liquid mud seal in a mud gas separator (MGS) is broken, what should be the first action to take?

Start the vacuum degasser.

Stop pumping and shut the well in

Reduce the pump speed by half.

Abandon the rig.

27 / 41

A kick is shut in with the bit 35 stands off bottom. A drillpipe safety valve (DPSV) (full opening type) installed on the drillpipe and then closed.

When starting to strip back to bottom, how would the equipment on the drillstring be installed?

An IBOP installed on top of a closed DPSV.

A DPSV installed in the closed position.

An IBOP installed in the closed position.

An IBOP installed on top of an open DPSV.

28 / 41

The BOP test-pump is connected to the kill line on a surface stack. A plug-type tester is in position and connected to the drillpipe.

How can you check if the test plug is leaking?

Check if the test-pump can reach the required test pressure.

Monitor for flow back up the drillpipe.

Open the choke line valves through to the mud gas separator (MGS).

Check for a pressure increase at the manual choke.

29 / 41

Which gauges on the remote BOP control panel would show a reduction in hydraulic when the annular preventer is closed? Choose two answers.

The annular pressure gauge.

The cement line pressure gauge.

The manifold pressure gauge.

The accumulator pressure gauge.

The air pressure gauge.

30 / 41

On a surface BOP installation, the driller activates the ram close function from the BOP remote control panel. Then the ram function lights change colour from green to red while the annular pressure, the manifold pressure, and the accumulator pressure remain constant.

What is the cause of malfunction?

The pressure switch for the pumps on the hydraulic BOP control unit is malfunctioning.

The hydraulic line between the hydraulic BOP control unit and the BOP is blocked.

The 3-position/4-way valve is stuck in the 'ram open position'.

The hydraulic line between the hydraulic BOP control unit and the BOP is leaking.

31 / 41

What are annular preventer sealing elements designed to do?

To seal around any type of drilling equipment at rated pressure.

To crush the casing

To seal around any size of tubular and seal off an empty well bore at rated pressure.

To hang-off the drillstring.

32 / 41

When would casing rams be installed in a surface BOP?

When the bit is at the shoe while tripping out the string.

Before pulling the bottomhole assembly (BHA).

While running electric logs.

While rigging up to run casing.

33 / 41

What will happen to a surface BOP stack if the ram function is operated on the remote BOP control panel without operating the master control valve?

The speed of the ram closing is unaffected by the master control valve.

The rams will not close.

The rams will closes lower.

The rams will close faster.

34 / 41

There is drillpipe in the hole, and you are monitoring the well on the trip tank (A63-0001). How can the BOP be configured to allow the choke line remotely-controlled side outlet valve

Figure A63-0001

The manual choke line valve and the drilling fluid.

The drilling fluid and the lower pipe rams.

Both manual valves.

The blind/shear rams and the manual valves.

35 / 41

If the manifold gauge on the remote BOP control panel reads zero and the other gauges read normal values, which BOP function can be operated?

The ram preventers.

The annular preventer.

No stack function.

All stack functions.

36 / 41

Why should 'space out distances' for the different BOP types on the stack be posted where the driller can see them?

To ensure that the annular is closed around a tool joint.

To prevent closing the shear ram on a tool joint.

To prevent a pipe ram closing around the pipe body.

To ensure the tool joint is opposite the flow line when closing a BOP.

37 / 41

What is the normal operating position of the 3-position/4-way valves on the hydraulic BOP control unit while drilling with a surface BOP stack installed?

All valves in the open position.

All valves in the neutral (block) position.

Open or closed depending on BOP stack function.

All valves in the closed position.

38 / 41

What is the purpose of a BOP function test?

To check that the accumulator bottles are at least 200 psi above pre-charge.

To check that all BOP functions operate using full manifold pressure

To check that all BOP functions operate correctly.

To check that the accumulator bottles have enough fluid to close the BOP

39 / 41

What is the purpose of the by-pass button on the driller's remote BOP control panel on a surface BOP installation?

To increase the hydraulic manifold pressure to the existing accumulator pressure.

To increase the manifold pressure to 2000 psi.

To increase the hydraulic annular pressure to the existing accumulator pressure.

To increase the accumulator pressure to 3000 psi.

40 / 41

During a well control situation, when should the top drive mounted safety valve be closed?

When the rotary kelly hose is being replaced.

When the swivel packing is being replaced.

When the surface pressures may exceed the rated working pressure of surface equipment.

When connections are made, to save the spilling of drilling fluid.

41 / 41

Figure A20-0013 shows a set of BOP remote control panel gauge readings. The BOP has not been operated and the BOP accumulator charge pumps (electric and air) are not running. What is the problem with these gauge pressures?

There is no problem. These gauge pressures are normal.

The annular pressure is too low.

The manifold pressure is too high.

The accumulator pressure is too low.

Your score is

0%