DRILLING EQUIPMENT COMBINED SURFACE/SUBSEA LEVEL 4 R1 EXAM

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1 / 52

Which one of the following statements about an inside blowout preventer (IBOP) is correct?

It can be opened by drilling fluid pumped down the drillstring.

It allows reverse circulation when installed in the drillstring.

It requires a double box sub in order to be installed in the drillstring.

It can be opened or closed by turning a wrench connected to an operating crank .

2 / 52

What information must be included in the 'space out diagram' for the surface BOP stack?

Total depth (TD) of the current well section below the rotary table.

The distance from the well head to the shear ram.

The distance from the BOP to the overshot packer.

The distance from the rotary table to the shear ram.

3 / 52

What is the API Standard 53 definition of 'rated working pressure'?

The maximum internal pressure that the BOP equipment is designed to contain or control.

Twice the rated working pressure of the test tool used.

The highest surface pressure predicted to be encountered while the well control equipment is installed.

The proof test pressure of a body or shell member.

4 / 52

A surface BOP stack is made up as follows (from the wellhead up):

Three ram BOPs, 13-5/8 in, 10000 psi rated working pressure.

One annular BOP, 13-5/8 in, 5000 psi rated working pressure.
After the well takes a kick, the well is closed in on 5 in diameter pipe using the annular preventer.

The stabilised shut-in casing pressure (SICP) is 1000 psi.

Figure A13-0007

The graph (figure A 13-0007) shows a manufacturer's recommended closing pressures according to well pressure. Use this graph to select the 'minimum pressure range' from the options below for
the annular BOP.

450 - 500 psi.

550 psi or above.

250 - 300 psi.

350 - 400 psi.

5 / 52

When operating a stack function from the remote BOP panel on a surface BOP installation, the open light goes out, the close light does not illuminate and the manifold pressure drops and later rises back up. Which malfunction does this indicate?

There is a leak in the hydraulic line to the BOP.

The hydraulic closing line to the BOP is plugged.

The 3-position/4-way valve on the hydraulic BOP control unit failed to shift.

The close function light bulb has blown.

6 / 52

The well has just been shut in using the upper pipe ram.

The flow meter reads 7.2 gallons.
The accumulator pressure has returned to 3000 psi.
The manifold pressure has returned to 1500 psi.

Function	Volume to close (gallons)	Volume to open (gallons)
Annular	43	35
Top ram	12.5	12.5
Lower ram	12.5	12.5
Choke remotely-operated side-outlet valve	2.1	2.1
Kill remotely-operated side-outlet valve	2.1	2.1

Using the data in the table, has the BOP closed successfully?

Yes, all pressures values are correct.

No, the flow meter value is too low.

Yes, the flow meter value is correct.

No, the flow meter value is correct but the manifold pressure is too low.

7 / 52

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.

8 / 52

The force required to shear the pipe can be a lot greater than the force required for a pipe ram to seal around drillpipe.

What are the features of a shear ram that create the required shearing force?

The shear ram opening ratio and opening pressure.

The length of piston stroke and closing pressure.

The ram rod diameter and closing pressure.

The shear ram closing ratio and closing pressure.

9 / 52

You are drilling top-hole from a jack-up rig. An annular diverter has been installed with the flow line located above it and the overboard valves below.

Due to a shallow gas kick, you operated the diverter and the automated sequence opened both vent lines and then closed the diverter.

The wind is coming from the east. What is the next action?

Close the valve on the west vent line.

Close the valve on the east vent line.

Close the flow line before opening the west vent line.

Close the flow line before opening the east vent line.

10 / 52

Your rig is equipped with a Class 5-A1-R415000 psi (15K) BOP stack. What test-pump instrument and equipment rating is suitable to test this BOP?

20000 psi.

5000 psi.

10000 psi.

15000 psi.

11 / 52

On a surface BOP installation, the driller closes the pipe ram at the remote panel. The close light illuminates but the manifold pressure does not drop. What could have caused this problem?

The 3-position/4-way valve on the hydraulic BOP control unit failed to operate.

The annular preventer has malfunctioned.

The hydraulic line to the BOP is leaking.

The hydraulic closing'line to the BOP is plugged.

12 / 52

The driller shuts in the well on a kick with the annular preventer on a surface BOP stack. The shut in pressures have stabilised.

The driller activates the middle pipe ram close function to protect the annular preventer.

The pressures are
Accumulator pressure static	3000 psi
Annular pressure static	1200 feet
Manifold pressure	0 psi

Why is the manifold pressure reading 0 psi?

The manifold pressure regulator is malfunctioning.

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

There is a leak in the hydraulic line to the annular preventer.

The hydraulic line to the upper pipe ram is blocked.

13 / 52

In which situation would you choose to do an inflow test to verify a well barrier element?

When testing a liner lap.

When testing the annular preventer.

When testing the topdrive inside blowout preventer (IBOP).

When testing the choke manifold valve upstream of the remote choke.

14 / 52

While circulating out a kick, pressure begins to build-up in the MGS. Why can this be dangerous?

Pressure build-up in the MGS may allow gas to enter the shale-shaker area.

Pressure build-up in the MGS may allow gas to be diverted up the derrick vent line.

Pressure build-up in the MGS will make it difficult to adjust the choke.

Pressure build-up in the MGS will increase the risk of lost circulation.

15 / 52

When a mud gas separator (MGS) is working within its handling capability, which design feature creates the back pressure on pressure gauge 'A' (shown in Figure A41-0003)?

The height of the liquid seal.

The length and diameter of vent line.

The height and diameter of the siphon breaker.

The flow rate of hot mud into the MGS.

16 / 52

A drillpipe safety valve (DPSV) should be placed on the rig floor at all times, ready for use, to fit the tubulars in use.

Which statements are correct for this type of valve? Choose three answers.

It is easier to stab than an inside BOP (IBOP) when there is flow up the drillstring.

It has to be pumped open to read shut-in drillpipe pressure (SIDPP).

It is kept in the open position by a rod secured by a T-handle.

It will not allow wireline to be run inside the drillstring.

It requires a key to open and close.

It should not be run in the hole in the closed position.

Its rated operating pressure is less than that of the drilling BOPs.

It wil lbe installed in the closed position.

17 / 52

A surface stack BOP has one 10000 psi (10K) rated annular preventer. Use the graph (Figure A13-0007) below to identify which well control operations can be carried out using the annular preventer. Choose two answers.

Maintain a seal on 3-1/2 in drillpipe with a well pressure of 1000 psi and with the annular pressure regulated to 400 psi.

Maintain a seal on 5 in drillpipe with a well pressure of 1000 psi and with the annular pressure regulated to 375 psi.

Maintain a seal with no pipe in the hole with a well pressure of 1000 psi and with the annular pressure regulated to 1200 psi.

Maintain a seal on an 8 in drill collar with a well pressure of 1000 psi and with the annular pressure regulated to 175 psi.

Maintain a seal on 2-3/8 in drillpipe with a well pressure of 1000 psi and with the annular pressure regulated to 650 psi.

18 / 52

Figure A20-0015 shows a set of BOP remote control panel gauge readings. The BOP has not been operated and the electrically driven pump is not running. What do these gauge readings indicate?

There is a problem with the annular regulator.

There is a problem with the automatic hydro-electric pressure switch.

There is a problem with the manifold regulator.

The hydraulic circuit is leaking.

19 / 52

Figure A20-0002 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 are the possible reasons for the low accumulator pressure reading? Choose two answers.

The accumulator pre-charge pressure is too low.

There is a leak in the hydraulic accumulator unit.

The accumulator pre-charge pressure is too high.

There is a leak at the BOP.

The accumulator charge pump pressure switches have failed.

20 / 52

Why do choke manifolds have two chokes?

To provide a backup if there are problems with the active choke.

To direct returns to the mud gas separator (MGS).

To direct returns to the mud pits.

To direct returns to the flare.

21 / 52

You plan to batch-drill six top-hole sections with a diverter system which is rigged up below the rig floor. Which type of vent line will help minimise the pressure build up in the well if there is a shallow gas or water flow?

A vent line from the diverter to the mud gas separator (MGS).

A large internal diameter (ID) vent line to discharge fluids a safe distance away from the rig.

A large internal diameter (ID) vent line from the diverter to the top of the derrick.

A small internal diameter (ID) vent line rigged to discharge fluids a safe distance away from the rig.

22 / 52

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 repair to 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.

23 / 52

You are planning a routine slip and cut operation with the bit at the casing shoe. Which item of equipment must be installed to make the operation safe?

A circulating head in the closed position.

An inside blowout preventer (IBOP) in the closed position.

A drillpipe safety valve (DPSV) in the open position and an inside blowout preventer (IBOP) in the closed position.

A full opening drillpipe safety valve (DPSV) in the open position .

24 / 52

You are tripping out of the well and are 5000 ft off bottom when the well starts to flow.

What should you do to secure the well and prepare to strip back to bottom?

Install a float valve on the pipe to secure well, close the annular BOP then add a non• return inside BOP (IBOP) above for stripping.

Install a full-opening type DPSV, close it and close the annular BOP to secure the well. Then install a non-return type inside BOP (IBOP) above and reopen the DPSV for stripping.

Install a non-return type IBOP to secure the well. Then add a full-opening type DPSV above for stripping.

Drop a dart valve into the string and pump to the dart sub to secure the well. Then add a non-return type inside BOP (IBOP) for stripping and close the annular BOP.

25 / 52

While tripping out of the hole, the wellbore pressure-assisted annular BOP is shut in due to an influx.

If the shut-in casing pressure (SICP) is 500 psi and the manufacturer's chart recommends a minimum closing pressure of 400 psi, when would the driller adjust the closing pressure?

Before shutting in the well.

When the pumps are up to kill speed.

When the gas reaches the BOP stack.

Before stripping in the hole.

26 / 52

What is the main limitation of drillstring flapper valves when stripping to bottom?

You must run wireline inside the drillstring to open the flapper valve.

The shut-in drillpipe pressure (SIDPP) cannot be read on surface.

The flapper valve is a not a tested barrier.

You must reverse circulate before stripping to bottom.

27 / 52

Why is the manual valve and remotely-controlled side outlet valve installed in the position shown in the diagram (Figure A61-0001)?

Figure A61-0001

The manual valve acts as a barrier if the remotely-controlled side outlet valve needs maintained or repaired.

To increase the back pressure downhole for a safety margin.

To protect the remotely-controlled side outlet valve from eroding while cementing.

To minimise the build-up of cuttings at the drilling spool side outlets.

28 / 52

When a ram type BOP on a surface stack is closed, what happens to the operating fluid displaced from the opening chamber?

The fluid is used to boost the closing pressure.

The fluid drains into the well bore.

The fluid is vented into the cellar.

The fluid is returned to the unit reservoir.

29 / 52

You inflow test the 7 in liner lap using a retrievable packer. The drillpipe is displaced to lightweight fluid and the packer is set above the liner lap. The BOPs are open and the annulus is monitored on the trip tank.

While reducing the drillpipe pressure by small amounts, you notice the trip tank level is decreasing.
What does this indicate?

The liner lap is leaking.

The packer is correctly set.

Thermal expansion of the drilling fluid.

The retrievable packer is leaking.

30 / 52

You are closing a pipe ram from the remote panel on a surface BOP.

The close light illuminates and the manifold pressure gauge initially drops and then returns to normal.

What causes these changes in manifold pressure?

A pilot signal is being sent to the manifold regulator valve.

Fluid is flowing into the pipe ram opening chamber.

Fluid is flowing into the pipe ram closing chamber.

The accumulator 4-way valve has shifted to the 'neutral' position.

31 / 52

How often should all operational components of the surface BOP stack equipment systems function tested according to API STD 53?

Once every 14 days.

At least once a week.

Only after installation of the BOP stack.

Once a shift.

32 / 52

When testing the BOP stack with a test plug or cup type tester, why should pressure communication be maintained from below the tool to atmosphere?

To avoid extreme hook load.

To avoid swabbing a kick during the test.

Otherwise reverse circulation will be needed to release the tool.

To avoid potential damage to the casing/open hole.

33 / 52

Per API Standard 53 (2018), drillpipe safety valves (DPSVs) and inside blowout preventers (IBOPs) must be pressured tested as frequently as the BOP stack. After the BOP is installed, what test pressure should be used in the subsequent high-pressure tests?

150% of the rated working pressure of the component.

Rated working pressure of the component.

250 psi to 350 psi.

Maximum anticipated surface pressure of the hole section.

34 / 52

What is the advantage of a self-adjusting ram lock?

The ram closes quickly to minimise the size of the influx.

The ram piston moves the same distance each time the ram is operated.

As the ram rubber wears, the closing pressure can be reduced to minimise further wear.

As the ram rubber wears, the lock position changes to maintain a seal around the pipe.

35 / 52

What is the main advantage of an insert type diverter compared to a conventional large annular type of diverter?

An insert type diverter can allow large diameter tools to be run without removing the insert.

An insert type diverter can hold higher pressures than a conventional diverter.

An insert type diverter has a lower closing volume and is faster to close on a flowing well.

An insert type diverter takes longer to close and reduces hydraulic shock on top hole formations.

36 / 52

You are supervising the weekly BOP function test on a surface 18-3/4 in x 10000-psi (10K) BOP stack. The regulated manifold pressure is 1500 psi and regulated annular pressure is 1000 psi. What would tell you that the annular has closed correctly?

The ram light changes from 'open' to 'close', and 23 seconds later the manifold pressure reaches 1000 psi.

The ram light changes from 'open' to 'close', and 23 seconds later the manifold pressure returns to 1500 psi.

The annular light changes from 'open' to 'close', and 60 seconds later the annular pressure returns to 1000 psi.

The annular light changes from 'open' to 'close', and 43 seconds later the annular pressure returns to 1000 psi.

37 / 52

What design feature do diverter systems have to minimise back-pressure on the well?

The diverter element closes before the selector valve opens.

Targeted bends and maximum length vent lines with small internal diameters.

Straight and minimum length vent lines with large internal diameters.

Dual active vent lines with minimum bore control valves.

38 / 52

When circulating out a gas kick at 30 SPM, the pressure inside the mud gas separator (MGS) increases close to the maximum allowable pressure.

What should you do to reduce the risk of liquid seal loss in the MGS U-tube?

Shut in the well in and bleed the gas to reduce the casing pressure.

Shut in the well and then re-establish circulation at a lower SPM.

Shut in the well and bullhead the gas back to the casing shoe.

Increase the SPM to circulate the gas through the MGS faster.

39 / 52

What is a locking device on a ram-type preventer designed to do?

Locks the manifold pressure so it cannot be changed.

Assist the annular preventer to create a seal against well pressure.

Preient the ram from opening if there is loss of hydraulic power.

Allows the ram to close around the drillpipe.

40 / 52

A 15000 psi rated surface BOP stack has rams with the following closing ratios:

5 in pipe rams	10.2: 1 closing ratio
Blind/shear rams	6.8: 1 closing ratio
Variable bore rams (VBRs)	8.7: 1 closing ratio

Which operation can be completed using 1500 psi manifold operating pressure when the BOP
stack is used at full-rated working pressure?

Shear 5 in pipe at the full-rated pressure for the stack.

Shut in on 6-5/8 in drill pipe at the full-rated pressure for the stack.

Shut in on 5 in pipe at the full-rated pressure for the stack.

Strip 5 in pipe to bottom ram to ram at the full-rated pressure for the stack.

41 / 52

A surface stack BOP consists of (from top to bottom):

1 x 10000 psi rated annular preventer
1 x 10000 psi rated 5 in - 7 in variable bore pipe ram (VBR)
1 x 10000 psi rated blind/shear rams
1 x 15000 psi rated drilling spool with 10000 psi rated remotely operated side outlet valves
1 x 10000 psi rated 5 in pipe rams

Which operation can you do with the string 3000 ft off bottom, with an influx at the bottom of the well, while keeping control of the bottomhole pressure (BHP)?

Circulating out the influx immediately while shut-in on 6-5/8 in pipe.

Stripping 6-5/8 in pipe to bottom, VBR to lower pipe ram.

Stripping 5 in pipe through the annular preventer.

Circulating out an influx while shut in on the lower pipe rams.

42 / 52

During a regular weekly function test of a 13-5/8 in surface stack, the supervisor records the following data. Does this stack pass its function test as per API STD 53?

Function	Closing pressure (psi)	Time (seconds)	Volume to close (gallons)	Volume to open (gallons)
Annular	500	47	43	35
Upper pipe ram	1500	23	11.5	13.6
Middle pipe ram	1500	37	11.4	13.6
Lower pipe ram	1500	22	11.5	13.5
Choke line remotely-operated hydraulic valve.	1500	4	2.1	2.2
Kill line remotely-operated hydraulic valve	1500	5	2.0	2.0

Yes - more than half of the BOP functions meet the requirements.

Yes - all values meet requirements.

No - all kill and choke line valves exceed the minimum ram response time.

No - the middle pipe ram and the annular preventer closing times are too long.

43 / 52

A kick is shut in with a 10000 psi rated annular (pressure tested to 7500 psi). Rams are rated for 15000 psi.

During the pressure build-up, you decide to close the upper pipe ram due to increasing pressure.

The final stabilised shut-in casing pressure (SICP) is 10800 psi
The pipe ram closing ratio is 7:1

You then decide to close the middle pipe ram.
Function tests recorded a minimum of 300 psi to close the ram due to internal friction.

What is the minimum operating pressure required to close the middle ram?

Approximately 1500 psi.

Approximately 1200 psi.

Approximately 3000 psi.

Approximately 1850 psi.

44 / 52

The maximum operating pressure allowed in a mud gas separator (MGS) is often calculated assuming that there is mud in the liquid seal.

What would be the effect on this maximum operating pressure as a condensate (or oil) kick is circulated through the MGS?

Maximum operating pressure would increase.

There would be no effect.

Maximum operating pressure would decrease.

45 / 52

When testing a subsea BOP stack with inverted test rams, how will the string weight affect the pressure test requirements?

A high hook load requires the string to be hung-off on the test rams.

Tension in the drillstring will lower the pipe collapse pressure.

String weight will not affect test requirements.

Hook load is less than the pipe tensile strength, so closing pressure can be reduced to 1000 psi.

46 / 52

How many SPM valves in one subsea pod move when opening the upper annular preventer?

3.

4.

1.

2.

47 / 52

When drilling ahead on a floating rig with an electro-hydraulic BOP control system, the driller tells you that the low surface accumulator pressure alarm has activated and the surface flow meter is counting rapidly. No BOP functions have been operated.

What could be the cause of the problem?

The main power fluid line to the BOP is leaking .

A pipe ram BOP regulator has malfunctioned and is leaking.

A shuttle valve in the lower marine riser package (LMRP) is leaking.

The slip joint packer has failed.

48 / 52

What is one advantage of using inverted rams during a subsea BOP test?

Allows an additional ram cavity to be added to the subsea BOP stack.

Allows subsea BOP testing without having to run the BOP test plug.

Allows more subsea BOP stack configurations during well operations.

Allows subsea BOP testing, including the blind shear rams, without having to run the BOP test plug.

49 / 52

On a rig with an electro-hydraulic BOP control system, you are supervising a function test. The driller tells you that there is a problem with the upper annular BOP 'close' function. The light on the BOP panel changes to 'close' but there is no flow count or pressure drop on the annular BOP readback pressure gauge.

What could be the problem?

The accumulator charge pump has failed.

There is a loss of operating pressure to the upper annular BOP shuttle valve.

There is a leak in the upper annular BOP closing line.

The signal from the electronic module to the upper annular BOP 'close' solenoid valve has failed.

50 / 52

What is the purpose of having pre-charged accumulator bottles mounted on a subsea BOP stack?

Choose two answers.

To act as a back-up if the surface control system fails.

To reduce the usable fluid in the surface accumulator bottles.

To ensure faster BOP closing times.

To balance the hydrostatic pressure in the riser.

To reduce the BOP closing pressure.

51 / 52

While using the yellow pod to operate the subsea BOP Stack, the upper annular 'close' function does not operate.

The subsea engineer switches to the blue pod, and the upper-annular BOP 'close' function operates as normal.

What is the most likely cause of the yellow pod upper-annular BOP 'close' function failure?

The upper annular BOP 'open' sub-plate mounted (SPM) valve failed to operate.

The upper annular BOP 'close' sub-plate mounted (SPM) valve failed to operate.

The shuttle valve is leaking.

The sub-plate mounted (SPM) has sent the wrong pilot pressure to the shuttle valve.

52 / 52

What is the role of the sub-plate mounted (SPM) valve in the subsea BOP control system?

Operated by pilot pressure, it allows the BOP function to be operated by regulated hydraulic control fluid.

It is fitted to each control circuit, to reduce harmful water-hammer effect.

It is used to increase the pressure of the hydraulic control fluid to operate the intended BOP function in the circuit.

It regulates hydraulic control fluid to operate the intended BOP function in the circuit.

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