Completion Equipment Exam

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1 / 30

A well has been completed with the liner set in a deviated section across the reservoir . What is the benefit of completing a well in this way?

The drilling of the reservoir does not need to be so precise.

The deviated section helps trapped water flow to surface.

There is more measured length of reservoir that can be produced.

It limits the amount of volume required in the 'A' annulus.

2 / 30

What is the primary function of a gas lift valve within a side pocket mandrel (SPM)?

It injects gas at a calculated pressure into the 'A' annulus from the completion tubing to help lift oil to surface.

It injects gas at a calculated pressure into the completion tubing from the 'A' annulus to help lift oil to surface.

It allows annulus fluid to enter the completion tubing and kill the well when the maximum allowable annular surface pressure (MAASP) is exceeded.

It prevents well fluids from the completion tubing entering the 'A' annulus.

3 / 30

How does hydraulic pressure in the control line reach the wireline retrie vable surface controlled subsurface safety valve (WRSCSSSV)?

Into the valve between two packing-seal stacks set in a polished bore.

Through a connection on the Xmas Tree and then down into the valve from above.

Directly into the valve through a threaded connection.

By sending a signal to a two-way valve above the SCSSSV.

4 / 30

Why would you install a circulating valve into a side pocket mandrel (SPM)?

It holds the check valves open to allow fluids to be circulated.

It helps to protect the polished bore within the SPM while circulating.

To ensure the pressure is equalised between the tubing and the 'A' annulus.

It makes sure that the circulating depth is correct.

5 / 30

A reservoir is suspended with a column of kill fluid. Lost circulation material (LCM) is positioned across the perforations.

When running the completion string close to the packer setting depth, which action could result in the LCM breaking down due to swabbing?

Moving the string down quickly, causing a pressure decrease below the wireline entry guide (WEG).

Running the completion string into the well with a plug installed in the tail pipe.

Circulating out the completion fluid when the packer is set.

Quickly picking up the completion string to remove a damaged tubing joint.

6 / 30

Downhole scale prevents a sliding sleeve being opened before the completion is retrieved.

What is a good alternative?

Open a downhole flow control valve.

Run a tubing punch to perforate the completion tubing above the packer.

Use a chemical injection line for reverse kill.

Install a circulating valve in the gas lift mandrel.

7 / 30

Why are some completion strings set in compression before the tubing hanger is landed into the wellhead?

To provide space for the Xmas Tree installation.

To compensate for the effect of tubing stresses.

To ensure that the internal diameter of the production tubing remains constant.

To ensure that the production packer will not release during production.

8 / 30

A permanent packer will be milled out and a new completion will be installed. The packer is set in a deviated section.

Where should the new packer be set when the well has been recompleted?

In the same position as the old packer setting point.

Below the deviated section.

Below the old packer setting point.

Above the old packer setting point.

9 / 30

How is an electric submersible pump (ESP) operated?

By performing an intervention to switch on the electric submersible pump.

By pumping fluid through a hydraulic control line clamped to the completion.

Through an integrated battery pack.

By using an electrical power cable clamped onto the completion.

10 / 30

An upper completion is installed into a polished bored receptacle (PBR) on top of a pre-set packer deep in the well.

There is a plug installed at the top of the packer tailpipe.

The space out calculations are incorrect, and the string must be pulled back to replace a tubing joint with a pup joint.

How could this affect integrity when the upper com letion is installed back into the PBR?

The plug in the tailpipe could fail.

The PBR seals may have been damaged.

The pup joint may not have been made up to the correct torque.

The surface controlled subsurface safety valve (SCSSSV) control line will have been cut and will no longer be continuous.

11 / 30

A Xmas Tree has failed integrity testing before rigging up for intervention. There is only one tested gate valve isolating the well. What is the first action to take?

Stop the operation and start the management of change (MOC) process.

Kill the well through the swab cap.

Repeat the inflow test on the single barrier.

Install another gate valve to the top of the Xmas Tree.

12 / 30

You have just completed a reverse circulation on a newly completed well. During the circulation, pressures were unstable.

It was difficult to close the sliding sleeve.

What could be the cause?

The surface lines are leaking.

There is debris in the 'A' annulus.

The fluid pump return valve is bypassing.

Pressures across the sliding sleeve are not equalised.

13 / 30

A well is expected to have a high tubing head temperature. What is the advantage of using an expansion device?

It will help to prevent the tailpipe from moving out of the liner polished bore receptacle (PBR).

It will help to reduce tubing stress when the well is in production.

It will help to reduce the tubing head temperature.

It will help to increase the production rate.

14 / 30

How does a gas lift valve prevent well fluids from entering the 'A' annulus?

There is a one-way check valve within the gas lift valve.

The gas lift valve is operated by a hydraulic control line.

There is always a positive pressure on the 'A' annulus side of a gas lift well.

The production packer is set above the gas lift valves.

15 / 30

At the end of an intervention operation, the swab valve is closed and attempts to bleed off the PCE are unsuccessful.

The upper master gate valve is closed and inflow tested successfully.

Which valve should be used to provide the second well barrier before lifting the PCE?

The kill wing valve.

The production manifold valve.

The subsurface safety valve (SSSV).

The lower master gate valve.

16 / 30

Well fluid will be removed from the tubing by reverse circulating through an open sliding sleeve.

During circulation, pump pressure unexpectedly begins to increase.

What might be the reason?

The sliding sleeve is only half open.

The completion fluid in the 'A' annulus has a high viscosity.

There is a small annular clearance between the casing and the tubing.

There is debris in the 'A' annulus.

17 / 30

Well fluids are leaking through the stem packings of an upper master gate valve. What should be done to make the well safe?

Isolate the well and bleed off all pressure from the Xmas Tree. Document the well barrier isolations.

Inject grease into the stem to energise the stem packings.

Close the lower master gate valve. Repair the upper master gate valve.

Install a cap onto the upper master gate actuator to prevent it from closing.

18 / 30

A completion string is being run and is close to packer setting depth. The driller reports a string weight loss. Depth calculations are checked and confirmed to be accurate. Intervention is attempted but the tools are unable to reach the tailpipe. What is the likely cause?

The well is starting to flow.

The clearance between the packer and the casing is too small.

The well was not sufficiently cleaned before running the completion.

The packer elastomer has expanded with the pressure of the fluid preventing downward movement of the completion string.

19 / 30

The upper master gate valve on a Xmas Tree has failed and will not close. What should be done before attempting intervention work to suspend the well and make the repair?

Flow the well to remove any debris.

Pump fluid into the well at high rate to remove debris from the gate valve cavity.

Confirm the integrity of all other Xmas Tree valves and install a shear/seal gate valve to the top of the Xmas Tree.

Increase the hydraulic pressure to the upper master gate valve.

20 / 30

Figure EQP-0003 shows a drilled but uncompleted well.

Figure EQP-0003

There are several layers of productive sands close to a water producing zone.

How would you expect this well to be completed?

With artificial lift to help to avoid water production from the well.

With a slotted liner across the reservoir.

With no liner across the reservoir.

With a cemented liner across the reservoir.

21 / 30

You set a plug in the tailpipe and inflow test it before displacing the well to kill fluid.

You then plan to set and test a second plug in the tubing hanger nipple before removing the Xmas Tree. This plug cannot be tested in the direction of well flow.

How should the second plug be configured so that a test from above will prove that it can hold pressure from below?

Without locking keys.

With all chevron packings facing upwards.

With an elastomeric sealing element.

With all chevron packings facing downwards.

22 / 30

A well has developed annulus pressure. The casing head pressure and the tubing head pressure both increase at the same rate once the well is shut in.

You suspect the packer element may be leaking. Which action would confirm this leak?

Apply pressure to the 'B' annulus and monitor the 'A' annulus.

Install a plug into the tailpipe and pressure test the completion string.

Run a temperature survey through the completion tailpipe.

Open the 'A' annulus and attempt to flow the well.

23 / 30

Why is it important that drilling fluids are cleaned out of the well before running a completion?

Drilling fluids left in the well could reduce well production rates.

Drilling fluid is expensive and can be recycled.

The well volumes are calculated by measuring the returns.

The process helps confirm casing shoe depths.

24 / 30

What is the main difference between a cased hole and an openhole completion?

An openhole completion has no production packer.

The cased hole completion always has a tubing retrievable surface controUed subsurface safety valve (TRSCSSSV).

An openhole completion is more likely to produce gas.

The cased hole completion needs to be perforated before the well can produce.

25 / 30

You plan to complete an oil producing well with a gas-lift system. What should you check for future intervention operations?

Access into the 'A' annulus to change gas lift valve.

Kickover tool access to the side pocket mandrels.

The water content of the lift gas.

The cable outlet position at the wellhead.

26 / 30

A bell type wireline entry guide (WEG) has been chosen for a deviated well. The tailpipe will be centralised within the liner. What should be considered when planning interventions into the liner?

The toolstring design should allow for easy recovery through the WEG.

The rope socket fishing neck should be removed to ensure the toolstring re-enters the WEG.

The toolstring length should be kept as short as possible.

The WEG should not be positioned adjacent to a liner connection.

27 / 30

A positive plug will be installed in a completion landing nipple and then inflow tested.

What is holding the plug in place?

The locking keys.

The packing element.

The no-go shoulder.

The equalising housing.

28 / 30

Figure EQP-0004 shows a cutaway of a wellhead, with tubing hanger installed.

Figure EQP-0004

After the production operator reports that there is pressure in the 'A' annulus, it is found that the tubing hanger seals are leaking.

What is the correct action to take?

Install valve removal (VR) plugs into the 'A' annulus outlets.

Install a plug in the tailpipe.

Close the Xmas Tree swab valve.

Reverse circulate the well to kill fluid.

29 / 30

The permanent packer external element has failed. The 'A' annulus is live. How should the well be made safe?

Kill the well and continue to monitor.

Install a plug in the completion tail pipe and inflow test it.

Close the Xmas Tree and 'A' annulus outlets.

Perforate just above the packer and circulate the well fluids out of the 'A' annulus.

30 / 30

What issues could be expected in a long horizontal well with a cemented liner?

The weight of the completion fluid would need to be very high.

The quality of the cement bond may be poor.

Scale is more likely to build up inside the tubing.

The completion string weight would need to be very high.

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