Completion Operations Exam

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1 / 30

Figure COM-0010 shows a completed well that will be reverse circulated.

Figure COM-0010

All depths are TVD:

Sliding sleeve depth	7546 ft
Top formation depth	7825 ft
Oil/gas interface	5905 ft
Tubing head pressure	2412 psi
Gas gradient	0.0884 psi/ft
Oil density	7 ppg
Annulus fluid density	9 ppg
Annulus pressure	0 psi
Formation gradient	0.464 psi/ft

There is a tested plug in the tailpipe below the sliding sleeve.

What is the differential pressure across the sliding sleeve before opening?

2412 psi.

0 psi.

30 psi.

784 psi.

2 / 30

After a long period of production, a gas well is shut in at the flow wing valve.

Ice appears on the flow line downstream.

What could be the cause?

The outside temperature is less than the temperature of the well fluids.

A hydrate plug has melted.

The well fluids have been flowing at a very low temperature.

The flow wing valve is not holding pressure.

3 / 30

You plan to repair a failed lower master gate valve on a production well. What should be in place before a plug is set in the tubing hanger?

A tubing testing tool set deeper in the well.

An inflow-tested plug, set deeper in the well.

Verified and recorded annulus pressures.

A closed surface controlled subsurface safety valve (SCSSSV).

4 / 30

During a formation-injectivity test, there is a rapid decrease in pump pressure. What might have happened?

The surface controlled subsurface safety valve (SCSSSV) has closed.

The formation has fractured.

The perforations have become plugged.

The sliding sleeve has been forced to open.

5 / 30

Before an intervention operation on a gas producing well, you receive a signed handover document.

It shows that the last routine Xmas Tree integrity tests were successful.

What must you do before rigging up onto the well?

Integrity test the Xmas Tree valves.

Make copies of the test charts and continue with the operation.

Test the swab valve before removing the swab cap.

Review the integrity test charts before continuing.

6 / 30

After a well intervention operation, the PCE is bled down by one of the two bleed-down points available. The gauge shows zero pressure. How can you check that the pressure is zero?

Open the second bleed-down point to confirm the pressure is zero before breaking the connection.

Close the bleed-down point and monitor the gauge manifold for a pressure increase.

Rig up a pump to the gauge manifold and inject fluid into the PCE to confirm that there is no blockage in the manifold.

Tap the gauge manifold with a wrench to help confirm that there is no blockage.

7 / 30

Total depth (TD) of a vertical well is:	9900 ft
Depth of sliding sleeve:	8875 ft
Shut-in tubing head pressure (SITHP):	0 psi
Gradient of fluid in the production tube:	0.43 psi/ft
Gradient of fluid in the 'A' annulus:	0.48 psi/ft

What is the pressure differential across the sliding sleeve?

444 psi.

1495 psi.

1444 psi.

556 psi.

8 / 30

You have successfully pressure tested a barrier envelope. Before bleeding down, you see that the test pressure has increased. What is the reason for this pressure increase?

Pressure stabilisation.

Thermal expansion.

A failed barrier element.

Wind direction.

9 / 30

While circulating kill fluid you are asked to reduce the flow rate by 25%.

The current rate is 2 bbl/min.

The initial pump pressure was 2000 psi.

What will be the new pump pressure?

1732 psi.

3125 psi.

1125 psi.

1500 psi.

10 / 30

Before rigging up PCE onto a well, the shut-in tubing head pressure (SITHP) exceeds the maximum anticipated pressure stated in the intervention programme.

What should you do?

Check that the well pressure is less than the PCE test pressure and then continue with the operation.

Stop the operation and complete a management of change (MOC) process to assess the potential impact.

Continue with the operation as the SITHP in the intervention programme is only a guide.

Rig up onto the well and pump kill fluid to reduce the SITHP to the value in the intervention programme.

11 / 30

You open the 'A' annulus to reduce the pressure build up caused by thermal expansion.

Completion brine is bled off and is later replaced with fresh water. The 'A' annulus is now full and the pressure reads zero.

How could this affect well integrity?

Hydrates will form in the 'A' annulus.

The production packer will be overpressured.

Fresh water will damage the wellhead seals.

The MAASP will need to be recalculated .

12 / 30

A tubing string with control lines is across the BOPs.

Which barrier elements may not operate correctly? Choose two answers.

The annular BOP.

The 'A' annulus outlet valve.

The kill and choke line failsafe valves.

The BOP pipe rams.

The downhole check valves.

13 / 30

Gas pressure is being bled off from a lubricator through a gauge manifold.

The gas suddenly stops venting and the pressure gauge reads zero. The operator attempts to undo the lubricator quick-union, but it doesn't move.

What could be the problem?

The lubricator union was made up with too much torque.

The tool string is at the top of the PCE and is applying tension to the lubricator.

The lubricator union has become tight as the well fluids have heated up the PCE.

The gauge manifold is blocked with a hydrate, causing gas pressure to be trapped in the lubricator.

14 / 30

Figure COM-0007 shows a Xmas Tree with a pressure gauge on the swab cap.

Figure COM-0007

After well stimulation through the Xmas Tree kill wing, the pressure gauge on the swab cap reads zero.

What is the likely reason for this?

The kill wing valve has been left open.

The swab valve is holding pressure.

The swab cap gauge has been over-pressured during the stimulation.

The swab valve is leaking.

15 / 30

A Xmas Tree is connected to a production manifold system.

Before a well handover for an intervention operation, what actions are required to isolate the well from the production system? Choose two answers

Close, tag and isolate the supply pressure to the surface controlled subsurface safety valve (SCSSSV).

Close the lower master gate valve, and record the number of turns required to re-open it.

Close and tag the valves to isolate the well from the production manifold.

Open and tag the valves to isolate the well from the production manifold.

Shut down the location. Close, tag and isolate all wells from the production manifold.

16 / 30

While preparing for an intervention operation, you see that the BOP certification has just expired. Replacement BOPs are not immediately available.

What action should you take?

Continue with the operation as the expiry date can be extended.

Test the BOP to 1.5 times the working pressure on site.

Ask for dispensation from the location manager to continue with the operation.

Suspend the operation until certified BOPs arrive at location.

17 / 30

Where should a production packer be positioned to help ensure a successful inflow test?

In the middle of a casing joint.

In heavy-weight casing.

Across a casing connection.

Below the casing shoe.

18 / 30

How would you monitor for a leak while pressure testing a completion tubing string?

Check for flow from the tubing retrievable subsurface safety valve (TRSSSV) control line.

Monitor test pressure and check for flow from the 'A' annulus outlet.

Monitor test pressure and check for flow from the 'B' annulus outlet.

Monitor test pressure and check for flow from the kill line.

19 / 30

What is the main purpose of a wellsite pressure control drill?

To ensure that the crew understand their roles and the actions they must take.

To ensure that the supervisor can give clear instructions to the crew.

To help the crew locate escape routes, muster points and firefighting equipment.

To help brief the crews on the well integrity management system (WIMS).

20 / 30

An intervention operation is planned on a well that is not producing H2S. When the PCE arrives on location, the certification tells you that the equipment is suitable for sour service. What should you do?

Request non-sour service PCE to be sent to location.

Increase the planned test pressure by 10%.

Continue with the operation. It is acceptable to use sour service PCE in a non-sour well.

Immediately stop the operation.

21 / 30

When a new well is completed, what should be included within the pressure test documents to help to confirm well integrity?

The manufacturer, length and grade of each tubing joint.

The chemical properties of the test fluid used.

Copies of the engineering drawings of all the completion components.

Acceptance criteria for the well barrier envelope testing, and proof that it has been followed.

22 / 30

In a gas well, there is no communication path between the annulus and the tubing. The reservoir must be protected.

What is the most appropriate kill method to suspend this well?

Bullheading.

Reverse circulation.

Forward circulation.

Lubricate and bleed.

23 / 30

Figure COM-0012 shows a vertical well with the following data.

Pressure at the top perforation	12500 psi
Shut-in tubing head pressure (SITHP)	8972 psi
Gradient of the well fluid	0.35 psi/ft

Figure COM-0012

What is the true vertical depth (TVD) of the top perforation?

10080 ft.

35714 ft.

1235 ft.

25634 ft.

24 / 30

Figure COM-0006 shows a graph of tubing head pressure against time.

Figure COM-0006

After shutting in a producing well, you see a rapid increase in shut-in tubing head pressure. What is the reason for this pressure increase?

Temperature increase in the well.

Pressure buildup from the reservoir.

Gas migration in the well.

Crossflow in the reservoir.

25 / 30

The equipment operator reports that one of the lubricator pin ends is very loose when it is made up into the box.

The PCE is certified.

What should you do?

Replace the loose lubricator section before continuing with the operation.

Tell the equipment operator to continue with the operation as planned.

Rig up as planned and test the lubricator seal by applying well pressure.

Install larger outside diameter 0-ring seals to the lubricator.

26 / 30

Total depth (TD) of a vertical well is:	9630 ft
Depth of the sliding sleeve:	8000 ft
Shut-in tubing head pressure (SITHP):	0 psi
Shut-in casing head pressure (SICHP):	0 psi
Gradient of fluid in the production tubing:	0.44 psi/ft
Gradient of fluid in the 'A' annulus:	0.55 psi/ft

What SITHP is needed to equalise across the sliding sleeve?

880 psi.

845 psi.

440 psi.

1024 psi.

27 / 30

The completion tubing is punched just above the packer to reverse circulate between the tubing and annulus.

Soon after circulation starts, the pump pressure increases. What could be the cause?

The tubing has collapsed above the punched holes.

Debris in the annulus has blocked the punched holes.

The pumped fluid is heavier than the contents of the tubing and annulus.

The well has started to flow.

28 / 30

What happens to the volume of a gas bubble as it migrates up the tubing in a closed well?

It stays the same.

It increases.

It decreases.

29 / 30

What are the main conditions for a fluid column to be classified as a barrier? Choose two answers.

It must contain hydrate inhibitor.

It must be maintainable.

It must be supported by a mechanical plug.

It must be monitored.

It must be a clear completion fluid.

30 / 30

After a plug has been set and inflow tested, a well is suspended using the lubricate and bleed method. After the final bleed-off, the well is shut in.

After a short time, the shut in tubing head pressure begins to slowly increase. What is the most likely reason for this?

The residual gas is migrating.

The downhole plug has developed a leak.

The well is starting to flow.

The kill fluid is 'U-tubing'.

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