DRILLING EQUIPMENT SURFACE LEVEL 4 R2 EXAM

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1 / 46

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.

2 / 46

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 top drive inside blowout preventer (IBOP).

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

3 / 46

During a pressure test of a surface stack annular preventer, the closing pressure must be increased to achieve a successful test. What could be happening?

Regulated annular pressure should always be increased for pressure tests.

The annular element material is not correct for the drilling fluid type in the well.

The annular regulator is damaged, and should be repaired at the next casing point.

The annular element is starting to deteriorate, and may need to be replaced soon.

4 / 46

Figure A20-0018 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 the gauge readings indicate?

Thereis a leak in the manifold hydraulic circuit.

There is a problem with the charging pump.

There is a problem with the bypass valve.

These readings are normal.

5 / 46

During subsequent operational pressure testing of a surface BOP, what high-pressure value should drillpipe safety valves (DPSVs) and inside BOPs (IBOPs) be tested to?

To the maximum expected shut-in drillpipe pressure (SIDPP) based on a full column of fluid inside the drillstring.

To the lower of maximum anticipated surface pressure (MASP) for the hole section or 70% of the annular rated working pressure.

To the maximum anticipated surface pressure (MASP) of the hole section.

To the rated working pressure of the rotary hose.

6 / 46

During a trip out of hole, the driller shuts in the well using a full opening drillpipe safety valve (DPSV) and the annular preventer.

An IBOP (non-return valve) is installed above the DPSV.

With the DPSV open, which of the following is possible?

Circulation down the drillstring and up the annulus.

Circulation is only possible when. a double-box sub is installed between the IBOP and DPSV.

Circulation is possible when the IBOP has been opened by the operating key.

Reverse circulation.

7 / 46

After a drilling break, the driller does a flow check. The well is flowing, and the upper pipe ram is functioned to close. The driller notes and reports the following pressures:

Accumulator pressure is static at 3000 psi.
Annular pressure is static at 900 psi.
Manifold pressure decreased rapidly to 0 psi

Why is the manifold pressure reading zero?

The manifold pressure regulator is malfunctioning.

The hydraulic line to 'the upper pip/ram is blocked.

There is a leak in the hydraulic line to the upper pipe ram

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

8 / 46

Why should the side outlet valves below the test plug be kept in the open position while testing a surface BOP stack? Choose two answers.

To prevent potential damage to the casing or formation.

Because the test will create extreme hook load.

To check the position of the test plug.

If not kept open, reverse circulation will be needed to release the plug.

To monitor the wellbore for plug leakage.

9 / 46

Why is the recommended diameter for the choke manifold bleed line (the line that by-passes the chokes) the same diameter as the choke line?

To allow use of a flow meter during high volume bleed-off.

To prevent the over-loading of the mud gas separator (MGS) while maintaining back pressure on the well using the choke.

To allow the well to be circulated while maintaining a minimum back-pressure.

To prevent hydrates from forming.

10 / 46

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

You decide to strip back to bottom to perform the kill operation.

When should you adjust the closing pressure to manufacturer's recommendations while maintaining a seal?

When the shut-in casing pressure (SICP) stabilises.

When the pumps reach the kill speed.

When the gas reaches the BOP stack.

Before shutting in the well.

11 / 46

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.

12 / 46

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.

13 / 46

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 will be installed in the closed position.

14 / 46

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.

15 / 46

When a mud gas separator (MGS) is operating within its handling capacity, which design features create the back pressure on pressure gauge 'A' (shown in Figure A41-0003)?

The flow rate of hot mud into the MGS.

The height of the liquid seal.

The height and diameter of the siphon breaker.

The length and diameter of the vent line.

16 / 46

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.

17 / 46

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

Three ram BOPs, 13-5/8", 10000 psi rated working pressure.
One annular BOP, 13-5/8", 5000 psi rated working pressure.

After the well takes a kick, the well is closed in on 5" diameter pipe using the annular preventer.

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

The graph (figure A13-0007) 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.

18 / 46

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?

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.

19 / 46

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.

20 / 46

Given the volumes below, how much hydraulic fluid is required to complete the following operations (no safety margin)?

Operations	Close then open
Equipment	One annular preventer Two pipe rams
Volumes
Annular preventer	51 gallons to close. 45 gallons to open
Pipe ram	25 gallons to close. 22 gallons to open

152 gallons.

95 gallons.

190 gallons.

143 gallons.

21 / 46

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.

22 / 46

A conventional flapper type float valve is installed in the bit sub. What effect does this have on the operation when tripping into the well compared to a drillstring without a float? Choose three answers.

Reverse circulation will be possible.

The shut-in drillpipe pressure (SIDPP) will be equal to the shut-in casing pressure (SICP).

The drillpipe may collapse if it is not filled.

Back-flow through the drillstring will increase.

Surge pressure will increase.

Surge pressure on the formation will decrease.

There will be increased mud returns to the trip tank.

23 / 46

How does a vacuum degasser work?

Gas cut mud enters the degasser and forms a thin layer over the internal baffle plates. Atmospheric pressure in the vessel helps to remove the gas.

Gas cut mud enters the degasser and forms a thin layer over the internal baffle plates. It is vented to the overboard line.

Gas cut mud enters the degasser and forms a thin layer over the internal baffle plates. The vacuum inside the vessel helps remove the gas.

Gas cut mud enters the degasser and forms a thick layer over the external baffle plates. Excess pressure inside the vessel forces the gas to escape.

24 / 46

For which ram operation, is it most likely that the by-pass valve on a surface hydraulic BOP control unit will be used?

Variable bore rams.

Blind/shear rams.

Fixed bore pipe rams.

The annular preventer.

25 / 46

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.

26 / 46

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

When bleeding off the initial high pressure on the drillpipe from 500 psi in stages, you are unable to bleed below 250 psi. The trip tank level remains constant.

What could this indicate?

This indicates that there is a leak in the retrievable packer.

This indicates that there is a leak in the liner.

This indicates thermal expansion of the drilling fluid.

This indicates that the liner packer has correctly set.

27 / 46

Who should sign the pressure test documentation?

The driller, the tool pusher, and the cement pump operator.

The mechanic, the drilling contractor representative and the BOP engineer.

The mechanic, the installation/rig manager, and the electrician.

The pump operator, the drilling contractor representative, and the well operator representative.

28 / 46

When should well control equipment on a surface BOP installation be pressure tested? Choose two answers.

After the disconnection or repair of any pressure containment seal in the BOP system, choke line or choke manifold.

After circulating out a gas kick.

At intervals not exceeding two months.

When maximum anticipated surface pressure exceeds BOP rated pressure.

Upon initial installation.

29 / 46

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.

30 / 46

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.

31 / 46

Per API STD 53, when should you pressure test your drillpipe safety valves (DPSVs) and inside blowout preventers (IBOPs)?

Each time a new component is added to or removed from the BHA.

At each function test of the main BOP components.

Once a week or the first trip after the 7-day interval.

At intervals not exceeding 21 days.

32 / 46

You are supervising the weekly BOP function test on a surface 18-3/4 in x 10000-psi (1 OK) 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 secondslater 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.

33 / 46

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.

34 / 46

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.

35 / 46

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.

36 / 46

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.

37 / 46

What is the primary reason to use the vacuum degasser when circulating?

It has a limited volume capacity.

It vents recovered gas through the kill line to the rig flare line.

It removes entrained gas from the fluid returning to the mud pits.

It can handle large volumes of free gas.

38 / 46

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.

39 / 46

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 to be 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.

40 / 46

There is drillpipe in the hole, and you are monitoring the well on the trip tank (A63-0001 ). How can 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.

41 / 46

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.

Maintain a seal on 3-1/2 in drillpipe with a well pressure of 500 psi and with the annular pressure regulated to 500 psi.

Maintain a seal with no pipe in the hole with a well pressure of 500 psi and with the annular pressure regulated to 1200 psi.

Maintain a seal on an 8 in drill collar with a well pressure of 500 psi and with the annular pressure regulated to 350 psi.

Maintain a seal on 5 in drillpipe with a well pressure of 500 psi and with the annular pressure regulated to 400 psi.

42 / 46

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 (BRs)	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.

43 / 46

During a regular weekly function test of a 13-5/8 in surface stack, the supervisor records the following data. Does the stack pass its function test as per API STD 35?

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.

44 / 46

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 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 bottom hole 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.

45 / 46

Your rig is equipped with a Class 5-A1-R4 15000 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.

46 / 46

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.

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