1. Co Excercies 3&4
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International well control forum Well Intervention Pressure
1.
Which one of the following is a correct definition for a well barrier? No. required Answers
2.
1
A. A Plug that can prevent the flow of well bore fluids.
B. A well barrier is defined as anything that can prevent the well bore hydrocarbons to flow to surface.
C. Wireline Blow out plug.
What is the definition of a barrier? No. required Answers
3.
Level 3 & 4 Completion Operations
1
A. A closed-off area.
B. Something that prevents a flow of hydrocarbons from a well.
C. A fluid in over-balance.
D. A BOP locking mechanism.
E. A mechanical plug.
F. The warning tape around the work site.
What is the correct name of the various barriers? No. required Answers
1
A. First-line, second-line and third-line
B. Primary, secondary and tertiary
C. First, second and third.
Page 1 of 47
International well control forum Well Intervention Pressure
4.
Which of the following statements describe types of barriers? No. required Answers
5.
1
A. Positive and negative
B. Pump open and pump closed
C. Mechanical and liquid
D. Over-balanced and under-balanced
E. Primary and secondary
F. Upper and lower.
Which of the following is an active barrier during completion the well? No. required Answers
6.
Level 3 & 4 Completion Operations
1
A. BOP
B. Overbalance brine/fluid.
C. Cement Plug.
Which one of the following is considered as a secondary barrier during a well intervention operation? No. required Answers
1
A. BOP.
B. Hydrostatic Bottom Hole Pressure.
C. X-mass Tree.
Page 2 of 47
International well control forum Well Intervention Pressure
7.
You are completing a well, which barriers are in place? No. required Answers
8.
3
A. SSD.
B. BOP.
C. Casing & cementation.
D. Overbalanced brine.
E. DHSV.
While completing a producing well, why should a fluid barrier be clean? No. required Answers
9.
Level 3 & 4 Completion Operations
2
A. To prevent formation damage.
B. To prevent debris settling at the top of the packer.
C. To reduce the bottom hole pressure while pumping.
D. To provide a homogeneous fluid system for completion.
While running sand screens during completion, what safety equipment should be on the rig floor all the time? No. required Answers
1
A. Back Pressure valve.
B. X-over with safety head.
C. Non-return valve
Page 3 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
10. Do wells on artificial lift (gas lift, SRP, etc…..) need the same well control barriers as those with self flow? No. required Answers
A. Yes
B. No
1
11. What does the term “positive plug” mean? No. required Answers
1
A. It prevents flow from above
B. It prevents flow from below
C. It prevents flow from both directions.
12. How is a mechanical plug installed? No. required Answers
2
A. The well pressure closes it
B. The well flow closes it
C. By the freezing method
D. By Wireline or Coiled tubing
E. The control line pressure closes it.
Page 4 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
13. Which of the following mechanical barriers can be installed by means of intervention methods? No. required Answers
6
A. Wireline plug
B. Pump-through plug
C. Circulation valve
D. Differential pressure valve
E. Pump-open plug
F. Float valve
G. Retainer
H. Hi-vis pill
I. Orifice valve
J. Check valve.
K. Expandable plug
L. Pressure cycling valve
14. Which of the following are closable barriers? No. required Answers
1
A. Tubing hanger plug
B. Pump-out plug
C. BOP
D. Packer
E. Check valve.
Page 5 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
15. In which direction should a barrier be tested? No. required Answers
1
A. From above
B. From below
C. In any direction
D. In the direction of flow.
16. How is the inflow test performed? No. required Answers
1
A. By bleeding down the tubing pressure till the fluids reach the surface.
B. Monitoring the pressure rise carefully before commencing new operation.
C. Increase the hydrostatic pressure below the plug.
17. What does the term “inflow test” mean? No. required Answers
1
A. To apply pressure above a plug
B. To apply pressure below a plug
C. To bleed of pressure above a plug
D. To equalize pressure across a plug.
Page 6 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
18. If an inflow test cannot be performed, should the equipment be tested from above? No. required Answers
A. Yes.
B. No.
1
19. What item of equipment should be pressure tested before we rig up intervention equipment? No. required Answers
1
A. Xmas tree
B. Tubing hanger
C. Packer.
D. Annulus.
20. Which of the following fluids are common fluid barriers? No. required Answers
A. Seawater
B. Diesel oil
C. Packing fluid
D. Nitrogen
E. Condensate
F. Drilling fluid.
3
Page 7 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
21. Which of the following types of barrier is a fluid barrier? No. required Answers
A. Primary
B. Secondary
C. Tertiary.
1
22. How do we select a kill fluid? No. required Answers
1
A. By calculating its acid content
B. By calculating its yield point
C. By calculating its viscosity
D. By calculating its hydrostatic pressure.
23. How can a mechanical barrier stop the well-flow? No. required Answers
1
A. By leading the flow down the kill-line
B. By applying a slight over-balance
C. By closing off the flow route
D. By closing Xmas tree valves.
Page 8 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
24. How a plug (BPV, Positive plug, etc…) is used to shut off flow? No. required Answers
1
A. By creating a 100 psi overbalance.
B. By installing the plug in tubing hanger.
C. By keeping the pressure below the swab valve.
D. By sealing the perforations.
E. By installing in the flow path & sealing against tubing or casing Wall.
25. A Xmas tree is to be changed out on a production well. A deep-set positive plug has been set in the tailpipe below the packer. A second plug will be set in the tubing hanger before the tree can be removed. What is the correct first action to take before setting the second plug? No. required Answers
1
A. Inflow test the deep-set plug.
B. Pressure up on the tubing to test the deep-set plug.
C. Pressure up on the annulus to test the deep-set plug from below.
D. If the wellhead pressure is not rising, the second plug can be run immediately.
26. So that a Xmas tree can be changed out on a producing well, a deep-set positive plug has been set in the nipple below the packer. A second plug will be set in the tubing hanger before removing the tree. After setting the first plug, what is the correct first action to test it? No. required Answers
1
A. Pressure up on the annulus.
B. Pressure up on the tubing.
C. Bleed down tubing pressure.
D. If the wellhead pressure is static, a test is not required.
Page 9 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
27. In the drawing below, identify the barrier elements (envelope) that: 1.
Maintain well pressure
(FIVE ANSWERS)
2.
Prevent outflow from the annulus.
(FOUR ANSWERS)
Question 1 (FIVE ANSWERS)
Question 2 (FOUR ANSWERS)
A. B. C. D. E. F. G. H.
A. B. C. D. E. F. G. H.
Xmas tree Tubing hanger/wellhead Tubing spool outlet valves Production string Completion fluid Well fluid Casing Production packer.
Xmas tree Tubing hanger/wellhead Tubing spool outlet valves Production string Completion fluid Well fluid Casing Production packer
Page 10 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
28. What do we need in order to be able to select the correct kill fluid? No. required Answers
2
A. To have the possibility of pumping at a lower rate
B. To minimize the formation over-pressure
C. To have the possibility of maintaining a high pumping pressure
D. To ensure correct fluid compatibility with the formation
E. To reduce losses in the annulus.
29. Which of the following statements are true? No. required Answers
2
A. Losses always occur in the lowest zone of the formation
B. Losses always occur in the uppermost formation zone
C. Losses can occur in any formation zone
D. Losses can occur in one zone while another zone is producing
E. Pumping a heavy liquid will cure the losses.
30. Personnel observe that the annulus pressure on a producing well increases from 0 psi to 300 psi. The well has the packer set to isolate annulus. What does this indicator tell you? No. required Answers
1
A. The packer is leaking.
B. Temperature in the annulus increases.
C. Both causes are possible.
Page 11 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
31. Which of the following can reduce the swab pressure if you are to pull out a packer assembly after it is unset? No. required Answers
2
A. Circulate at slow rate while pulling the packer to surface.
B. Keep the annulus pressured as the completion tubing is pulled to surface.
C. Reduce the puling speed considerably.
D. Viscosity the brine to prevent debris settling.
32. What are consequences of having a blow-out? No. required Answers
5
A. Environmental damage
B. Competitors shall gain an advantage.
C. Loss of human life.
D. Loss of equipment
E. The responsible person will be fired and will not find a job easily.
F. Loss of reputation
G. If the blow is controlled before it catches fire, no real consequences are expected.
H. Financial damages.
Page 12 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
33. What is „‟fracture pressure‟‟?
No. required Answers
1
A. The Pressure applied to the formation when it breaks down.
B. The Pressure applied at the surface which will cause the formation at the shoe to break down.
C. The Pressure applied to the formation at the bottom of the well by the column of mud in the well.
D. The Pressure applied to the formation at the casing shoe by the column of the mud in the well.
34. Identify the top three reasons for holding the pre-job safety meeting?
No. required Answers
3
A. To get to know other team members.
B. To discuss & agree on logistical issues.
C. Define roles and responsibilities within the teams.
D. Make sure that procedures are understood by all.
E. Discuss emergency procedures and evacuation plan.
35. Which of the following statements are applicable to tasks that are Performed well and safely?
No. required Answers
3
A. Always use Xmas tree as the primary barrier.
B. Hold a pre-job safety meeting with all personnel involved.
C. Always warn the foreman before shutting in the well.
D. Make sure that the foreman is always in position near the well.
E. Make sure that all personnel know what to do if a problem should arise.
F. Only use tested, inspected and well-maintained equipment.
Page 13 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
36. Who shuts in the well and is responsible for safe working if a problem occurs during an intervention operation? No. required Answers
1
A. The operator‟s representative (well foreman).
B. The well service manager.
C. The production manager.
D. The leader of the intervention team.
E. The operator of the intervention equipment.
37. Which of the following are required for pre job safety meeting for Well control , best three answers?
No. required Answers
3 1
A. To discuss the well incident in details.
B. To get to know other team member.
C. To decide roles and responsibility of each for shutting in and controlling the well if an incident occurs.
D. Get all those involved in the work to attend the meeting before the work starts and go through the plan, encourage feedback, adjust the plan if required and ensure everyone understood properly.
Page 14 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
38. Which of the following best describes a good toolbox meeting?
No. required Answers
1
A. Get all those involved in the work to attend the meeting before the work starts and explain to them exactly what will happen during the job.
B. Get all those involved in the work to attend the meeting before the work starts and go through the plan, encourage feedback, adjust the plan if required, and ensure everyone understands properly
C. Get all those involved in the work to attend the meeting before the work starts and read them the office management team plan. Explain that there can be no deviations from this plan.
39. During a well control incident which one of the following is correct.
No. required Answers
1
A. The intervention crew, the operator representative, and the well services supervisor have a meeting during the incident to decide how best to bring the well back under control.
B. The intervention crew, the operator representative, and the well services supervisor have had a pre-job meeting to decide roles and responsibilities for shutting-in and controlling the well if an incident occurs.
C. The intervention crew, the operator representative, and the well services supervisor have a meeting during the incident to learn from the office management response team how they wish the problem solved.
D. The intervention crew, the operator representative, and the well services supervisor have a meeting during the incident with the mud engineer to seek advice on the best well kill method.
Page 15 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
40. A problem has occurred with a well and it has been shut in. What do you do now?
No. required Answers
1
A. Delegate the problem to the well manager (operator‟s representative) and wait for the end of your shift.
B. Read the instructions in the well program, ring the onshore organization and ask for advice
C. Monitor the well while the personnel are being evacuated
D. Involve the local contingency organization and request them to remain on stand-by
E. Hold a meeting with all parties involved and draws up a plan. Ask the onshore organization for its comments.
41. In order to perform a well intervention operation what type of document should be made that describes correctly the recommended tasks to be carried out & the responsibilities of the personnel deputed?
No. required Answers
1
A. Well data handbook
B. Joint operation manual
C. Local authority regulations
D. Emergency policy document
E. Well intervention contract
Page 16 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
42. Who is responsible for maintaining pressure control during an intervention operation? No. required Answers
1
A. Company man.
B. Well service supervisor.
C. The person nominated in the joint operations manual.
D. The production supervisor.
E. The tool pusher.
43. In a planned kill operation, which killing method will probably be used? No. required Answers
1
A. Concurrent
B. Reverse circulation.
C. Wait and weight.
D. Forward circulation.
E. Lubrication and bleed.
44. What are the advantages of utilising reverse circulation? No. required Answers
4
A. The surface pressure is kept low
B. There is less danger of formation damage
C. It is a slow process
D. We have to utilize Wireline
E. Dirt can plug up the formation
F. The production tubing and annulus end up with pure killing fluid
G. All wells can normally be killed using this method.
Page 17 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
45. During a well operation a problem arises that requires the well to be killed. Which of the following is the most appropriate killing method?
No. required Answers
1
A. Lubrication and bleed.
B. Reverse circulation.
C. Wait and weight up.
D. Bullheading.
E. Concurrent.
46. During an intervention operation it becomes necessary to kill the well after a problem. Would bull heading be the most appropriate kill method? No. required Answers
A. False.
B. True.
1
47. Which of the following determine whether it is possible to bullhead?
No. required Answers
2
A. Working pressure rating of the surface equipment.
B. The completion string‟s collapse pressure.
C. The position of the blind ram.
D. The permeability of the formation.
E. The type of Workover string in use.
Page 18 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
48. In which of the following wells will bull heading be preferable to bleeding down and lubricating? No. required Answers
2
A. A well that has stopped producing gas due to internal sand and scale
B. A well in which a plug is stuck in the tailpipe
C. A well in which the sliding sleeve is stuck in closed position
D. A well with a serious leak in the control line to the DHSV
E. A well whose casing has severely collapsed just above the perforations.
49. In which of the following situations would bull heading be a likely kill method? No. required Answers
3
A. A well with a failed DHSV that cannot be pulled
B. When speed is important
C. When insufficient information is available to calculate a reverse circulation kill.
D. When there is a risk of formation damage.
E. In a well with a plug stuck in the tailpipe.
50. Which of the following s tatements regarding bull heading are correct? No. required Answers
2
A. It can only be carried out if the perforations are open
B. It can be carried out before the intervention begins when there is a two-way check valve in the tubing hanger
C. It may plug the formation
D. It is normally done instead of the alternative of opening the sliding sleeve
E. The method is more difficult than bleeding off and lubricating.
Page 19 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
51. A live well is to be killed by bull heading. Which of these factors limit the maximum allowable surface pressure?
No. required Answers
3
A. Completion size.
B. Maximum pump speed.
C. SIWHP.
D. Maximum safe working pressure of the surface equipment.
E. Completion burst limits.
F. DHSV operating pressure.
G. Possible formation fracture.
52. In an emergency situation in which it is impossible to bullhead, what will be the most suitable killing method?
No. required Answers
1
A. Volumetric.
B. Forward Circulation.
C. Wait and weight up.
D. Bleed off and lubricate.
E. Reverse circulation.
Page 20 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
53. Which of the following best describes the killing method of bleeding down and lubricating?
No. required Answers
1
A. It is carried out by bleeding down the well pressure to zero and circulating in kill fluid.
B. It is carried out by bleeding down the well pressure to zero and topping up the tubing with kill fluid.
C. It is carried out by pumping in one tubing volume of kill fluid and then bleeding down the well pressure to zero.
D. It is carried out by repeatedly pumping in a small volume of kill fluid and then bleeding down back to the same pressure as we had before starting pumping.
54. Which of the following indicates that a gas cap may be forming in a live well that has just been shut in at the tree?
No. required Answers
1
A. Initial SIWHP slowly falls.
B. Initial SIWHP slowly rises.
C. Initial SIWHP remains steady.
D. Annulus pressure slowly falls.
E. Annulus pressure slowly rises.
F. Annulus pressure remains steady.
Page 21 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
55. A flowing well has been shut in at the tree & the well head pressure quickly builds up to 1550 psi & then slowly increases to 2250 psi in next two hours. Which of the following is correct? No. required Answers
1
A. It indicates that DHSV is stuck in closed position.
B. It indicates that the perforations are getting plugged.
C. It is normal & due to gas cap formation
56. Which of these are true about tubing plugs? No. required Answers
3
A. Check that the pressure ratting is correct.
B. Check that the pressure are equalized before setting.
C. Check that the contingency exists if solids might settle on the plug top.
D. Check that the plug is to be installed as near the tree as possible.
E. Check that the plug is holding pressure after setting.
57. Before any well intervention operation on a well, the X-Mass tree must be pressure tested. What is the correct action after the pressure test has been recorded? No. required Answers
1
A. X-Mass Tree is regularly test and it is not required to be on the chart and there is no record keeping is required.
B. All valves are pressure tested, but only the pressure test for Master valve is recorded on the chart recorded and kept for well file.
C. X-Mass Tree valve pressure test is an integral part of well barrier system.
D. All pressure test must be recorded on chart and signed by the designated authorized supervisor and it should be kept in well file for at least 6 months.
Page 22 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
58. While pulling out of the well on a slick line operation, the tool string got stuck in the X-Mass Tree. Which one of the following is the correct procedure to make the well secure?
No. required Answers
1
A. Rig up a tool bar and push the tool string down.
B. Close the Wireline BOP and prepare for a fishing operation.
C. Close the upper master valve and cut the tool string and free the cable before shutting in the wireline BOP.
59. A closed gate valve has a differential of 2500 psi across it. Which of the following statements are true about opening this valve?
No. required Answers
2
A. The mechanical force required to turn handle can damage or break the stem
B. The high differential pressure assists the gate movement when opening
C. Pressure on only one side of the valve reduces the change of it being pressure locked.
D. The equalizing poppet in the gate equalizes the pressure as the gate starts to move
E. The sudden pressure surge on opening can damage piping equipment downstream.
Page 23 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
60. In the production well in the schematic below, the components and fluids have each been identified with a letter. Answer the questions on the page following the schematic by placing a latter in each of the boxes provided.
A Xmas Tree B Well Fluid C Tubing Hanger/Hanger Spool D Production Casing E Tubing Spool Outlet Valves F Packer G Production Tubing H DHSV I Overbalanced Completion Fluid
Page 24 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
a) Pressure has been observed in the completion annulus. If the DHSV is closed and the wellhead pressure bled off, the annulus pressure falls with it. A leak at which two barrier elements could cause this?
b) There is a leak at the flange between the tubing hanger spool and the Xmas tree. What can be closed to stop this leak?
c) There is a leak at the packer. What initially prevents the wellbore fluids from reaching the production casing?
61. In workover and completion operation, what are the minimum number(s) of recommended barriers? No. required Answers
A. One.
B. Two.
C. Three.
1
62. A normal annular preventer will seal pressure on the dual string completion when closed. Is it true? No. required Answers
A. True.
B. False.
1
Page 25 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
63. Can tree gate valve be primary barrier? No. required Answers
A. Yes
B. No
1
64. Which of the parameters below should be recorded in a pressure test graph as per API-RP-59 recommendations? No. required Answers
5
A. Fluid type.
B. Test pressure
C. Pressure rating of the equipment
D. Test volume pumped.
E. Name & signature of the authorized supervisor.
F. Rig Operators Name.
G. Manufacturers recommended pressure test.
65. Why do we perform low pressure test? No. required Answers
1
A. To give confidence that seals are holding pressure on low pressure as well.
B. Because it is company policy.
C. Because it is written in the program.
D. There is no need for low pressure test as long as equipment hold on high pressure test.
Page 26 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
66. A newly completed well has a sliding sleeve (SSD) just above the packer. The sleeve has just been closed with the tubing full of diesel and the annulus full of brine. The tubing is open to the perforation. How should the SSD be tested to ensure it is closed?
No. required Answers
1
A. Flow the well.
B. Pressure up the annulus.
C. Bleed down the annulus.
D. Bleed down the tubing.
67. A valve has been tested to 110% of its working pressure and failed. Should it be replaced? No. required Answers
A. Yes.
B. No.
1
68. When bleeding down oil from a lubricator system on an offshore platform, which of the following is correct? No. required Answers
1
A. Will be vented to a flare line.
B. Will go directly to the separator
C. Will be vented to the atmosphere
D. Will be bled down to an enclosed tank
Page 27 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
69. What is a good practice to run completion?
No. required Answers
3
A. Setting slips slowly to prevent scratch marks on the tubing.
B. Completions are designed for high flow rates so they should be run quickly to secure well.
C. Use small amount of grease.
D. RIH slowly to prevent damage to completion accessories.
E. Always use oil base mud as completion fluid to prevent corrosion.
70. The flow rate from a naturally flowing production well has been slowly and steadily reducing. It has been checked that the tree valves and the DHSV are all fully open. It is though that there may be a blockage forming in the well bore. What is the first correct action to take?
No. required Answers
1
A. Pressure up on the well to try to clear any blockage
B. Bleed down the well to try to move the blockage
C. Run a gauge cutter on wire line to look for the blockage.
D. Pressure up on the annulus to try and loosen the blockage.
E. Bleed down the annulus to try and loosen the blockage.
Page 28 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
71. A retrievable straddle packer leaks after attempting to set it. What should be the correct action? No. required Answers
1
A. RIH with another packer.
B. Set a cement pug on top of it.
C. Mill it.
D. Pull it out and replace it.
72. A production well is to be shut in after pulling out of the hole with the intervention tool string. Which is the first correct action? No. required Answers
1
A. Close the LMV
B. Close the LMV while counting turns
C. Close the Swab valve while counting turns
D. Close the DHSV
E. Close the DHSV while measuring returns
73. Does all kicks causing blow out? No. required Answers
A. Yes
B. No.
1
Page 29 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
74. Does Frictional Pressure determine how fast a fluid can move through the well bore. No. required Answers
A. Yes.
B. No.
1
75. How do high temperatures affect the hydrostatic gradient of a fluid, if so how? No. required Answers
A. Increase it.
B. Decrease it.
1
76. Formation damage reduces the well production and restricts the hydrocarbon flow back. A workover job can improve this productivity. Which one of the following will help improve the well productivity?
No. required Answers 1
A. Perform the clean out job with hydrochloric acid and use compatible clean filtered brine during the entire workover operation.
B. Use Oil Base mud to perform the workover operation as it is more compatible with the produced reservoir fluids.
C. Use fresh potable water without filtering during the workover operation.
Page 30 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
77. Which of the following measures can prevent or remove hydrates? No. required Answers
3
A. Rapid bleed-off of gas from the topside system
B. Use of water/glycol mixture during pressure testing
C. Pressure testing up to close-in pressure
D. Raising the temperature of the equipment used
E. Injecting methanol into the equipment.
78. Hydrate happened in wireline stuffing box and not able to remove the wire which of the following actions can help remove hydrates after they have formed No. required Answers
2
A. Check for external ice to find the location of the hydrates.
B. Close the lowest BOP, bleed off the pressure above it, open the connection above the BOP and clear the hydrates.
C. Inject Methanol.
D. Try to warm up the equipment with a steam cleaner, etc.
E. Work the pipe or wire up and down whilst bleeding surface pressure.
79. Hydrates can only form in the presence of free (liquid) water. No. required Answers
A. TRUE.
B. FALSE.
1
Page 31 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
80. Which of the following measures can help to remove hydrates? No. required Answers
3
A. Pull out of the well and fill the topside equipment with diesel oil
B. Check for the presence of external ice in order to locate the hydrates
C. Close the lowest BOP, bleed down the pressure above it, open the connection above the BOP and remove the hydrates
D. Inject methanol.
E. Try to warm up the hydrates using a high-pressure steamer.
F. Work the string up and down while you bleed off the surface pressure.
81. Injecting brine into the flow stream can reduce the formation of Hydrates. No. required Answers
A. True
B. False
1
82. Injecting distilled water into the flow stream can reduce the formation of hydrates. No. required Answers
A. True
B. False
1
83. Hydrates are likely to form at emergency blow down lines. ? No. required Answers
A. True.
B. False.
1
Page 32 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
84. Hydrates are likely to form at pressure relief valves? No. required Answers
A. True.
B. False.
1
85. Hydrates are common downstream of chokes No. required Answers
A. True.
B. False.
1
86. Temperatures below the freezing point of water are necessary for hydrate formation. No. required Answers
A. True
B. False.
1
87. Hydrates are less likely to form if injecting Glycol No. required Answers
A. True.
B. False.
1
88. For the same pressure, hydrates melt at the same temperature as they formed No. required Answers
A. True.
B. False.
1
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
89. Hydrates will form at low rather than high pressures No. required Answers
A. True
B. False
1
90. Hydrates can cause damage if they become loose. No. required Answers
A. True.
B. False.
1
91. Hydrates can damage well bore and intervention equipment. No. required Answers
A. True.
B. False.
1
92. Given the following data: Tubing depth 8,750 ft MD (7,525 ft TVD) Tubing capacity 0.0034 bbl/ft Annular capacity 0.0088 bbl/ft Pump rate 1.25 bpm. a) Calculate the time to pump bottoms-up Min b) Calculate the time for a complete circulation Min
Page 34 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
93. A gas well has the following information: Total depth 12540‟MD (10950‟TVD) Packer depth 10180‟MD (9245‟ TVD).Annulus fluid 9.0 ppg brine , Gas gradient 0.2 psi/ft. SIWHP 2500 psi . What is the pressure differential between the tubing and the annulus at the underside of the tubing hanger? No. required Answers
1
A.850 psi. more in annulus than the tubing.
B.850 psi. more in the tubing than the annulus.
C.1385 psi. more in the annulus than the tubing.
D.1385 psi. more in the tubing than the annulus.
E. 2500 psi. more in the annulus than the tubing.
F. 2500 psi. more in the tubing than the annulus.
94. A producing oil well has been shut in and the SSD is to be opened before killing the well. Calculate the differential pressure that exists across the sleeve before it is opened. Tubing shoe 11350‟MD & 8750‟TVD Completion fluid density 9.0 ppg Packer depth 11000‟ MD & 8600‟TVD Oil density 6.8ppg SSD depth 10950‟MD & 8550‟TVD SIWHP 1000 psi No. required Answers
1
A. The tubing and annulus are in balance.
B. There is 23 psi more in the tubing than the annulus.
C. There is 23 psi more in the annulus than the tubing.
D. There is 253psi more in the tubing than the annulus.
E. There is 253 psi more in the annulus than the tubing.
F. There is 300 psi more in the tubing than the annulus.
G. There is 300 psi more in the annulus than the tubing.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
95. A well is to be killed with 9.0 ppg brine. The MD is 10,525‟ ,TVD 9,250‟ The formation pressure is 4,430 psi. Which statement is true?
1
No. required Answers
A. There will be a 100 psi overbalance at the formation
B. There will be a 50 psi overbalance at the formation
C. The formation will be balanced
D. There will be a 50 psi underbalance at the formation
E. There will be a 100 psi underbalance at the formation.
96. Given the following data, calculate the time required to pump one full circulation. Tubing depth 9,250 ft MD (8,600 ft TVD) Tubing capacity 0.0035 bbl/ft Annular capacity 0.0062 bbl/ft Pump rate 0.70 bpm. No. required Answers
A. 120 min
B. 128 min
C. 60 min
D. 64 min
E. 88 min
F. 95 min.
1
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
97. A well is to be killed using packing fluid with a density of 8.99 ppg. The measured depth is 10528 ft and vertical depth is 10260 ft. Formation pressure is 4756 psi. Which of the following statements is correct? No. required Answers
1
A. There will be an overpressure of 99 psi.
B. There will be an overpressure of 44 psi.
C. The formation will be in balance.
D. There will be an under pressure of 42 psi.
E. There will be an under pressure of 99 psi.
98. Given the following data: Casing capacity 0.03049 bbls/ft Tubing nominal weight 10.2 lbs/ft Tubing capacity 0.00729 bbl/ft Closed end tubing displacement 0.01290 bbl/ft Pump displacement 0.0899 bbl/stroke Kill rate 100 strokes/min Well depth MD 11,200 ft Well depth TVD 10,100 ft a) Calculate how many strokes to displace tubing string. No. required Answers
1
A. 565 strokes
B. 908 strokes
C. 1,125 strokes.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
b) Calculate how many strokes to displace the entire wellbore. No. required Answers
1
A. 2,511 strokes.
B. 3,100 strokes.
C. 5,005 strokes.
99. Given the following data: Depth of tubing: 8750 ft MD / 8125 ft TVD Tubing capacity: 0.00387 bbl/ft Annulus capacity: 0.00970 bbl/ft Pumping rate: 1.25 bbl/min a) Calculate the time required to pump up the well Min
b) Calculate the time required for full circulation. Min
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
100. Well data: Casing 9 5/8”, 53.5 lb/ft Tubing 3 ½” Production packer at 9750 ft MD. With the aid of the information in the table below which represent the annular volume, calculate the total volume of the annulus above the production packer. Write your answer n the box below. Type
Weight (lbs/ft)
Lin ft / ft3
Bbl/ft
9 5/8”
47
2.7723
0.0642
9 5/8
53.5
2.8835
0.0618
9 5/8
58.4
3.0229
0.0580
9 5/8
59.4
3.0892
0.0577
The total volume of annulus
101.
bbl
Answer the following questions on the basis of the data given for a gas well:
Well depth 9150 ft MD / 7900 ft TVD Formation gradient: 0.57 psi/ft Gas gradient: 0.08 psi/ft a) What is the bottom-hole pressure? psi
b) What will be the maximum surface pressure? Psi
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
c) What is the correct working pressure for the wellhead/Xmas tree? No. required Answers
A. 2000 psi
B. 3000 psi
C. 5000 psi
1
d) If the well is to be killed, what will be the minimum density of the killing fluid? No. required Answers
A. 10 ppg.
B. 12 ppg.
C. 11 ppg.
1
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
102. Well control kill sheet data:
Gradients: Brine in annulus Oil in tubing Gas in tubing
o o o o o o o
0.49 psi/ft 0.35 psi/ft 0.12 psi/ft
Transition from gas to oil inside tubing at 4,000 ft (Gas Cap) Sliding sleeve at 7,450 ft (in open position) Permanent packer at 7,500 ft Top perforations at 7,700 ft Formation pressure 3,740 psi Closed in tubing head pressure (THP) 1,965 psi Closed in casing head pressure (CHP) 0 psi (Annulus is full to surface)
The diagram on the next page shows the configuration of the well, and the table below shows a reverse circulation kill graph, tubing containing gas and oil with a completion brine in the annulus. The kill fluid gradient is 0.52 psi/ft and is being pumped through the annulus via the sliding sleeve until the hydrocarbons and completion fluids have been circulated out entirely. NOTE:
During the well kill operation we maintain an overbalance of 200 psi above the formation pressure at top perforations.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
Page 42 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
a) What is the bottom-hole pressure at the sliding sleeve at point ( C ) ? psi
b) After 62 bbls of kill fluid have been pumped, the tubing head pressure stabilises at 202 psi (point C Figure 1). This pressure remains unchanged until we have pumped 188 bbls (point E Figure 1). Why does the pressure stabilize at 202 psi? No. required Answers
1
A. The gas coming out of the tubing is not expanding anymore
B. The oil is coming out of the well and the choke opening remains unchanged
C. The tubing is filled with original completion brine and the hydrostatic head remains unchanged
D. The fluid level in the tubing has dropped to below surface.
c) What is the total volume of the annulus between wellhead and sliding sleeve? (Figure 1) Bbl
d) If the tubing head pressure between point C and point D is kept at 150 psi instead of 202 psi, the well will be under balanced? (Figure 1) No. required Answers
A. True.
B. False.
1
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
e) At what point does the new kill fluid fill part of the annulus and all of the gas has just been displaced out of the tubing string? (Figure 1)
No. required Answers
A. Point „A‟.
B. Point „B‟.
C. Point „C‟.
D. Point „D‟.
E. Point „E‟.
F. Point „F‟.
1
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
103. The kill graph below (Figure 3) shows the pressure during a reverse circulation kill. The tubing and casing IDs and ODs do not vary. The kill fluid being pumped is the lighter than the completion fluid in the annulus. There are oil and gas inside the completion.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
a) What is the total volume of the well? (Figure 3)
Bbl
b) What is the tubing pressure at start of the kill? (Figure 3)
Psi
c) What is the tubing pressure after pumping 200 bbls? (Figure 3)
Psi
d) What is the annulus pressure after pumping 200 bbls? (Figure 3)
Psi
e) At what point does the fluid in the tubing overbalance the formation pressure? No. required Answers
A. Point „A‟.
B. Point „B‟.
C. Point „C‟.
D. Point „D‟.
E. Point „E‟.
F. Point „F‟.
1
Page 46 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
f) At what point does the kill fluid fill the annulus? No. required Answers
A. Point „A‟.
B. Point „B‟.
C. Point „C‟.
D. Point „D‟.
E. Point „E‟.
F. Point „F‟.
1
Page 47 of 47
1.
Which one of the following is a correct definition for a well barrier? No. required Answers
2.
1
A. A Plug that can prevent the flow of well bore fluids.
B. A well barrier is defined as anything that can prevent the well bore hydrocarbons to flow to surface.
C. Wireline Blow out plug.
What is the definition of a barrier? No. required Answers
3.
Level 3 & 4 Completion Operations
1
A. A closed-off area.
B. Something that prevents a flow of hydrocarbons from a well.
C. A fluid in over-balance.
D. A BOP locking mechanism.
E. A mechanical plug.
F. The warning tape around the work site.
What is the correct name of the various barriers? No. required Answers
1
A. First-line, second-line and third-line
B. Primary, secondary and tertiary
C. First, second and third.
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International well control forum Well Intervention Pressure
4.
Which of the following statements describe types of barriers? No. required Answers
5.
1
A. Positive and negative
B. Pump open and pump closed
C. Mechanical and liquid
D. Over-balanced and under-balanced
E. Primary and secondary
F. Upper and lower.
Which of the following is an active barrier during completion the well? No. required Answers
6.
Level 3 & 4 Completion Operations
1
A. BOP
B. Overbalance brine/fluid.
C. Cement Plug.
Which one of the following is considered as a secondary barrier during a well intervention operation? No. required Answers
1
A. BOP.
B. Hydrostatic Bottom Hole Pressure.
C. X-mass Tree.
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International well control forum Well Intervention Pressure
7.
You are completing a well, which barriers are in place? No. required Answers
8.
3
A. SSD.
B. BOP.
C. Casing & cementation.
D. Overbalanced brine.
E. DHSV.
While completing a producing well, why should a fluid barrier be clean? No. required Answers
9.
Level 3 & 4 Completion Operations
2
A. To prevent formation damage.
B. To prevent debris settling at the top of the packer.
C. To reduce the bottom hole pressure while pumping.
D. To provide a homogeneous fluid system for completion.
While running sand screens during completion, what safety equipment should be on the rig floor all the time? No. required Answers
1
A. Back Pressure valve.
B. X-over with safety head.
C. Non-return valve
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
10. Do wells on artificial lift (gas lift, SRP, etc…..) need the same well control barriers as those with self flow? No. required Answers
A. Yes
B. No
1
11. What does the term “positive plug” mean? No. required Answers
1
A. It prevents flow from above
B. It prevents flow from below
C. It prevents flow from both directions.
12. How is a mechanical plug installed? No. required Answers
2
A. The well pressure closes it
B. The well flow closes it
C. By the freezing method
D. By Wireline or Coiled tubing
E. The control line pressure closes it.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
13. Which of the following mechanical barriers can be installed by means of intervention methods? No. required Answers
6
A. Wireline plug
B. Pump-through plug
C. Circulation valve
D. Differential pressure valve
E. Pump-open plug
F. Float valve
G. Retainer
H. Hi-vis pill
I. Orifice valve
J. Check valve.
K. Expandable plug
L. Pressure cycling valve
14. Which of the following are closable barriers? No. required Answers
1
A. Tubing hanger plug
B. Pump-out plug
C. BOP
D. Packer
E. Check valve.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
15. In which direction should a barrier be tested? No. required Answers
1
A. From above
B. From below
C. In any direction
D. In the direction of flow.
16. How is the inflow test performed? No. required Answers
1
A. By bleeding down the tubing pressure till the fluids reach the surface.
B. Monitoring the pressure rise carefully before commencing new operation.
C. Increase the hydrostatic pressure below the plug.
17. What does the term “inflow test” mean? No. required Answers
1
A. To apply pressure above a plug
B. To apply pressure below a plug
C. To bleed of pressure above a plug
D. To equalize pressure across a plug.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
18. If an inflow test cannot be performed, should the equipment be tested from above? No. required Answers
A. Yes.
B. No.
1
19. What item of equipment should be pressure tested before we rig up intervention equipment? No. required Answers
1
A. Xmas tree
B. Tubing hanger
C. Packer.
D. Annulus.
20. Which of the following fluids are common fluid barriers? No. required Answers
A. Seawater
B. Diesel oil
C. Packing fluid
D. Nitrogen
E. Condensate
F. Drilling fluid.
3
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
21. Which of the following types of barrier is a fluid barrier? No. required Answers
A. Primary
B. Secondary
C. Tertiary.
1
22. How do we select a kill fluid? No. required Answers
1
A. By calculating its acid content
B. By calculating its yield point
C. By calculating its viscosity
D. By calculating its hydrostatic pressure.
23. How can a mechanical barrier stop the well-flow? No. required Answers
1
A. By leading the flow down the kill-line
B. By applying a slight over-balance
C. By closing off the flow route
D. By closing Xmas tree valves.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
24. How a plug (BPV, Positive plug, etc…) is used to shut off flow? No. required Answers
1
A. By creating a 100 psi overbalance.
B. By installing the plug in tubing hanger.
C. By keeping the pressure below the swab valve.
D. By sealing the perforations.
E. By installing in the flow path & sealing against tubing or casing Wall.
25. A Xmas tree is to be changed out on a production well. A deep-set positive plug has been set in the tailpipe below the packer. A second plug will be set in the tubing hanger before the tree can be removed. What is the correct first action to take before setting the second plug? No. required Answers
1
A. Inflow test the deep-set plug.
B. Pressure up on the tubing to test the deep-set plug.
C. Pressure up on the annulus to test the deep-set plug from below.
D. If the wellhead pressure is not rising, the second plug can be run immediately.
26. So that a Xmas tree can be changed out on a producing well, a deep-set positive plug has been set in the nipple below the packer. A second plug will be set in the tubing hanger before removing the tree. After setting the first plug, what is the correct first action to test it? No. required Answers
1
A. Pressure up on the annulus.
B. Pressure up on the tubing.
C. Bleed down tubing pressure.
D. If the wellhead pressure is static, a test is not required.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
27. In the drawing below, identify the barrier elements (envelope) that: 1.
Maintain well pressure
(FIVE ANSWERS)
2.
Prevent outflow from the annulus.
(FOUR ANSWERS)
Question 1 (FIVE ANSWERS)
Question 2 (FOUR ANSWERS)
A. B. C. D. E. F. G. H.
A. B. C. D. E. F. G. H.
Xmas tree Tubing hanger/wellhead Tubing spool outlet valves Production string Completion fluid Well fluid Casing Production packer.
Xmas tree Tubing hanger/wellhead Tubing spool outlet valves Production string Completion fluid Well fluid Casing Production packer
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
28. What do we need in order to be able to select the correct kill fluid? No. required Answers
2
A. To have the possibility of pumping at a lower rate
B. To minimize the formation over-pressure
C. To have the possibility of maintaining a high pumping pressure
D. To ensure correct fluid compatibility with the formation
E. To reduce losses in the annulus.
29. Which of the following statements are true? No. required Answers
2
A. Losses always occur in the lowest zone of the formation
B. Losses always occur in the uppermost formation zone
C. Losses can occur in any formation zone
D. Losses can occur in one zone while another zone is producing
E. Pumping a heavy liquid will cure the losses.
30. Personnel observe that the annulus pressure on a producing well increases from 0 psi to 300 psi. The well has the packer set to isolate annulus. What does this indicator tell you? No. required Answers
1
A. The packer is leaking.
B. Temperature in the annulus increases.
C. Both causes are possible.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
31. Which of the following can reduce the swab pressure if you are to pull out a packer assembly after it is unset? No. required Answers
2
A. Circulate at slow rate while pulling the packer to surface.
B. Keep the annulus pressured as the completion tubing is pulled to surface.
C. Reduce the puling speed considerably.
D. Viscosity the brine to prevent debris settling.
32. What are consequences of having a blow-out? No. required Answers
5
A. Environmental damage
B. Competitors shall gain an advantage.
C. Loss of human life.
D. Loss of equipment
E. The responsible person will be fired and will not find a job easily.
F. Loss of reputation
G. If the blow is controlled before it catches fire, no real consequences are expected.
H. Financial damages.
Page 12 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
33. What is „‟fracture pressure‟‟?
No. required Answers
1
A. The Pressure applied to the formation when it breaks down.
B. The Pressure applied at the surface which will cause the formation at the shoe to break down.
C. The Pressure applied to the formation at the bottom of the well by the column of mud in the well.
D. The Pressure applied to the formation at the casing shoe by the column of the mud in the well.
34. Identify the top three reasons for holding the pre-job safety meeting?
No. required Answers
3
A. To get to know other team members.
B. To discuss & agree on logistical issues.
C. Define roles and responsibilities within the teams.
D. Make sure that procedures are understood by all.
E. Discuss emergency procedures and evacuation plan.
35. Which of the following statements are applicable to tasks that are Performed well and safely?
No. required Answers
3
A. Always use Xmas tree as the primary barrier.
B. Hold a pre-job safety meeting with all personnel involved.
C. Always warn the foreman before shutting in the well.
D. Make sure that the foreman is always in position near the well.
E. Make sure that all personnel know what to do if a problem should arise.
F. Only use tested, inspected and well-maintained equipment.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
36. Who shuts in the well and is responsible for safe working if a problem occurs during an intervention operation? No. required Answers
1
A. The operator‟s representative (well foreman).
B. The well service manager.
C. The production manager.
D. The leader of the intervention team.
E. The operator of the intervention equipment.
37. Which of the following are required for pre job safety meeting for Well control , best three answers?
No. required Answers
3 1
A. To discuss the well incident in details.
B. To get to know other team member.
C. To decide roles and responsibility of each for shutting in and controlling the well if an incident occurs.
D. Get all those involved in the work to attend the meeting before the work starts and go through the plan, encourage feedback, adjust the plan if required and ensure everyone understood properly.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
38. Which of the following best describes a good toolbox meeting?
No. required Answers
1
A. Get all those involved in the work to attend the meeting before the work starts and explain to them exactly what will happen during the job.
B. Get all those involved in the work to attend the meeting before the work starts and go through the plan, encourage feedback, adjust the plan if required, and ensure everyone understands properly
C. Get all those involved in the work to attend the meeting before the work starts and read them the office management team plan. Explain that there can be no deviations from this plan.
39. During a well control incident which one of the following is correct.
No. required Answers
1
A. The intervention crew, the operator representative, and the well services supervisor have a meeting during the incident to decide how best to bring the well back under control.
B. The intervention crew, the operator representative, and the well services supervisor have had a pre-job meeting to decide roles and responsibilities for shutting-in and controlling the well if an incident occurs.
C. The intervention crew, the operator representative, and the well services supervisor have a meeting during the incident to learn from the office management response team how they wish the problem solved.
D. The intervention crew, the operator representative, and the well services supervisor have a meeting during the incident with the mud engineer to seek advice on the best well kill method.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
40. A problem has occurred with a well and it has been shut in. What do you do now?
No. required Answers
1
A. Delegate the problem to the well manager (operator‟s representative) and wait for the end of your shift.
B. Read the instructions in the well program, ring the onshore organization and ask for advice
C. Monitor the well while the personnel are being evacuated
D. Involve the local contingency organization and request them to remain on stand-by
E. Hold a meeting with all parties involved and draws up a plan. Ask the onshore organization for its comments.
41. In order to perform a well intervention operation what type of document should be made that describes correctly the recommended tasks to be carried out & the responsibilities of the personnel deputed?
No. required Answers
1
A. Well data handbook
B. Joint operation manual
C. Local authority regulations
D. Emergency policy document
E. Well intervention contract
Page 16 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
42. Who is responsible for maintaining pressure control during an intervention operation? No. required Answers
1
A. Company man.
B. Well service supervisor.
C. The person nominated in the joint operations manual.
D. The production supervisor.
E. The tool pusher.
43. In a planned kill operation, which killing method will probably be used? No. required Answers
1
A. Concurrent
B. Reverse circulation.
C. Wait and weight.
D. Forward circulation.
E. Lubrication and bleed.
44. What are the advantages of utilising reverse circulation? No. required Answers
4
A. The surface pressure is kept low
B. There is less danger of formation damage
C. It is a slow process
D. We have to utilize Wireline
E. Dirt can plug up the formation
F. The production tubing and annulus end up with pure killing fluid
G. All wells can normally be killed using this method.
Page 17 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
45. During a well operation a problem arises that requires the well to be killed. Which of the following is the most appropriate killing method?
No. required Answers
1
A. Lubrication and bleed.
B. Reverse circulation.
C. Wait and weight up.
D. Bullheading.
E. Concurrent.
46. During an intervention operation it becomes necessary to kill the well after a problem. Would bull heading be the most appropriate kill method? No. required Answers
A. False.
B. True.
1
47. Which of the following determine whether it is possible to bullhead?
No. required Answers
2
A. Working pressure rating of the surface equipment.
B. The completion string‟s collapse pressure.
C. The position of the blind ram.
D. The permeability of the formation.
E. The type of Workover string in use.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
48. In which of the following wells will bull heading be preferable to bleeding down and lubricating? No. required Answers
2
A. A well that has stopped producing gas due to internal sand and scale
B. A well in which a plug is stuck in the tailpipe
C. A well in which the sliding sleeve is stuck in closed position
D. A well with a serious leak in the control line to the DHSV
E. A well whose casing has severely collapsed just above the perforations.
49. In which of the following situations would bull heading be a likely kill method? No. required Answers
3
A. A well with a failed DHSV that cannot be pulled
B. When speed is important
C. When insufficient information is available to calculate a reverse circulation kill.
D. When there is a risk of formation damage.
E. In a well with a plug stuck in the tailpipe.
50. Which of the following s tatements regarding bull heading are correct? No. required Answers
2
A. It can only be carried out if the perforations are open
B. It can be carried out before the intervention begins when there is a two-way check valve in the tubing hanger
C. It may plug the formation
D. It is normally done instead of the alternative of opening the sliding sleeve
E. The method is more difficult than bleeding off and lubricating.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
51. A live well is to be killed by bull heading. Which of these factors limit the maximum allowable surface pressure?
No. required Answers
3
A. Completion size.
B. Maximum pump speed.
C. SIWHP.
D. Maximum safe working pressure of the surface equipment.
E. Completion burst limits.
F. DHSV operating pressure.
G. Possible formation fracture.
52. In an emergency situation in which it is impossible to bullhead, what will be the most suitable killing method?
No. required Answers
1
A. Volumetric.
B. Forward Circulation.
C. Wait and weight up.
D. Bleed off and lubricate.
E. Reverse circulation.
Page 20 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
53. Which of the following best describes the killing method of bleeding down and lubricating?
No. required Answers
1
A. It is carried out by bleeding down the well pressure to zero and circulating in kill fluid.
B. It is carried out by bleeding down the well pressure to zero and topping up the tubing with kill fluid.
C. It is carried out by pumping in one tubing volume of kill fluid and then bleeding down the well pressure to zero.
D. It is carried out by repeatedly pumping in a small volume of kill fluid and then bleeding down back to the same pressure as we had before starting pumping.
54. Which of the following indicates that a gas cap may be forming in a live well that has just been shut in at the tree?
No. required Answers
1
A. Initial SIWHP slowly falls.
B. Initial SIWHP slowly rises.
C. Initial SIWHP remains steady.
D. Annulus pressure slowly falls.
E. Annulus pressure slowly rises.
F. Annulus pressure remains steady.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
55. A flowing well has been shut in at the tree & the well head pressure quickly builds up to 1550 psi & then slowly increases to 2250 psi in next two hours. Which of the following is correct? No. required Answers
1
A. It indicates that DHSV is stuck in closed position.
B. It indicates that the perforations are getting plugged.
C. It is normal & due to gas cap formation
56. Which of these are true about tubing plugs? No. required Answers
3
A. Check that the pressure ratting is correct.
B. Check that the pressure are equalized before setting.
C. Check that the contingency exists if solids might settle on the plug top.
D. Check that the plug is to be installed as near the tree as possible.
E. Check that the plug is holding pressure after setting.
57. Before any well intervention operation on a well, the X-Mass tree must be pressure tested. What is the correct action after the pressure test has been recorded? No. required Answers
1
A. X-Mass Tree is regularly test and it is not required to be on the chart and there is no record keeping is required.
B. All valves are pressure tested, but only the pressure test for Master valve is recorded on the chart recorded and kept for well file.
C. X-Mass Tree valve pressure test is an integral part of well barrier system.
D. All pressure test must be recorded on chart and signed by the designated authorized supervisor and it should be kept in well file for at least 6 months.
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International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
58. While pulling out of the well on a slick line operation, the tool string got stuck in the X-Mass Tree. Which one of the following is the correct procedure to make the well secure?
No. required Answers
1
A. Rig up a tool bar and push the tool string down.
B. Close the Wireline BOP and prepare for a fishing operation.
C. Close the upper master valve and cut the tool string and free the cable before shutting in the wireline BOP.
59. A closed gate valve has a differential of 2500 psi across it. Which of the following statements are true about opening this valve?
No. required Answers
2
A. The mechanical force required to turn handle can damage or break the stem
B. The high differential pressure assists the gate movement when opening
C. Pressure on only one side of the valve reduces the change of it being pressure locked.
D. The equalizing poppet in the gate equalizes the pressure as the gate starts to move
E. The sudden pressure surge on opening can damage piping equipment downstream.
Page 23 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
60. In the production well in the schematic below, the components and fluids have each been identified with a letter. Answer the questions on the page following the schematic by placing a latter in each of the boxes provided.
A Xmas Tree B Well Fluid C Tubing Hanger/Hanger Spool D Production Casing E Tubing Spool Outlet Valves F Packer G Production Tubing H DHSV I Overbalanced Completion Fluid
Page 24 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
a) Pressure has been observed in the completion annulus. If the DHSV is closed and the wellhead pressure bled off, the annulus pressure falls with it. A leak at which two barrier elements could cause this?
b) There is a leak at the flange between the tubing hanger spool and the Xmas tree. What can be closed to stop this leak?
c) There is a leak at the packer. What initially prevents the wellbore fluids from reaching the production casing?
61. In workover and completion operation, what are the minimum number(s) of recommended barriers? No. required Answers
A. One.
B. Two.
C. Three.
1
62. A normal annular preventer will seal pressure on the dual string completion when closed. Is it true? No. required Answers
A. True.
B. False.
1
Page 25 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
63. Can tree gate valve be primary barrier? No. required Answers
A. Yes
B. No
1
64. Which of the parameters below should be recorded in a pressure test graph as per API-RP-59 recommendations? No. required Answers
5
A. Fluid type.
B. Test pressure
C. Pressure rating of the equipment
D. Test volume pumped.
E. Name & signature of the authorized supervisor.
F. Rig Operators Name.
G. Manufacturers recommended pressure test.
65. Why do we perform low pressure test? No. required Answers
1
A. To give confidence that seals are holding pressure on low pressure as well.
B. Because it is company policy.
C. Because it is written in the program.
D. There is no need for low pressure test as long as equipment hold on high pressure test.
Page 26 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
66. A newly completed well has a sliding sleeve (SSD) just above the packer. The sleeve has just been closed with the tubing full of diesel and the annulus full of brine. The tubing is open to the perforation. How should the SSD be tested to ensure it is closed?
No. required Answers
1
A. Flow the well.
B. Pressure up the annulus.
C. Bleed down the annulus.
D. Bleed down the tubing.
67. A valve has been tested to 110% of its working pressure and failed. Should it be replaced? No. required Answers
A. Yes.
B. No.
1
68. When bleeding down oil from a lubricator system on an offshore platform, which of the following is correct? No. required Answers
1
A. Will be vented to a flare line.
B. Will go directly to the separator
C. Will be vented to the atmosphere
D. Will be bled down to an enclosed tank
Page 27 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
69. What is a good practice to run completion?
No. required Answers
3
A. Setting slips slowly to prevent scratch marks on the tubing.
B. Completions are designed for high flow rates so they should be run quickly to secure well.
C. Use small amount of grease.
D. RIH slowly to prevent damage to completion accessories.
E. Always use oil base mud as completion fluid to prevent corrosion.
70. The flow rate from a naturally flowing production well has been slowly and steadily reducing. It has been checked that the tree valves and the DHSV are all fully open. It is though that there may be a blockage forming in the well bore. What is the first correct action to take?
No. required Answers
1
A. Pressure up on the well to try to clear any blockage
B. Bleed down the well to try to move the blockage
C. Run a gauge cutter on wire line to look for the blockage.
D. Pressure up on the annulus to try and loosen the blockage.
E. Bleed down the annulus to try and loosen the blockage.
Page 28 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
71. A retrievable straddle packer leaks after attempting to set it. What should be the correct action? No. required Answers
1
A. RIH with another packer.
B. Set a cement pug on top of it.
C. Mill it.
D. Pull it out and replace it.
72. A production well is to be shut in after pulling out of the hole with the intervention tool string. Which is the first correct action? No. required Answers
1
A. Close the LMV
B. Close the LMV while counting turns
C. Close the Swab valve while counting turns
D. Close the DHSV
E. Close the DHSV while measuring returns
73. Does all kicks causing blow out? No. required Answers
A. Yes
B. No.
1
Page 29 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
74. Does Frictional Pressure determine how fast a fluid can move through the well bore. No. required Answers
A. Yes.
B. No.
1
75. How do high temperatures affect the hydrostatic gradient of a fluid, if so how? No. required Answers
A. Increase it.
B. Decrease it.
1
76. Formation damage reduces the well production and restricts the hydrocarbon flow back. A workover job can improve this productivity. Which one of the following will help improve the well productivity?
No. required Answers 1
A. Perform the clean out job with hydrochloric acid and use compatible clean filtered brine during the entire workover operation.
B. Use Oil Base mud to perform the workover operation as it is more compatible with the produced reservoir fluids.
C. Use fresh potable water without filtering during the workover operation.
Page 30 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
77. Which of the following measures can prevent or remove hydrates? No. required Answers
3
A. Rapid bleed-off of gas from the topside system
B. Use of water/glycol mixture during pressure testing
C. Pressure testing up to close-in pressure
D. Raising the temperature of the equipment used
E. Injecting methanol into the equipment.
78. Hydrate happened in wireline stuffing box and not able to remove the wire which of the following actions can help remove hydrates after they have formed No. required Answers
2
A. Check for external ice to find the location of the hydrates.
B. Close the lowest BOP, bleed off the pressure above it, open the connection above the BOP and clear the hydrates.
C. Inject Methanol.
D. Try to warm up the equipment with a steam cleaner, etc.
E. Work the pipe or wire up and down whilst bleeding surface pressure.
79. Hydrates can only form in the presence of free (liquid) water. No. required Answers
A. TRUE.
B. FALSE.
1
Page 31 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
80. Which of the following measures can help to remove hydrates? No. required Answers
3
A. Pull out of the well and fill the topside equipment with diesel oil
B. Check for the presence of external ice in order to locate the hydrates
C. Close the lowest BOP, bleed down the pressure above it, open the connection above the BOP and remove the hydrates
D. Inject methanol.
E. Try to warm up the hydrates using a high-pressure steamer.
F. Work the string up and down while you bleed off the surface pressure.
81. Injecting brine into the flow stream can reduce the formation of Hydrates. No. required Answers
A. True
B. False
1
82. Injecting distilled water into the flow stream can reduce the formation of hydrates. No. required Answers
A. True
B. False
1
83. Hydrates are likely to form at emergency blow down lines. ? No. required Answers
A. True.
B. False.
1
Page 32 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
84. Hydrates are likely to form at pressure relief valves? No. required Answers
A. True.
B. False.
1
85. Hydrates are common downstream of chokes No. required Answers
A. True.
B. False.
1
86. Temperatures below the freezing point of water are necessary for hydrate formation. No. required Answers
A. True
B. False.
1
87. Hydrates are less likely to form if injecting Glycol No. required Answers
A. True.
B. False.
1
88. For the same pressure, hydrates melt at the same temperature as they formed No. required Answers
A. True.
B. False.
1
Page 33 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
89. Hydrates will form at low rather than high pressures No. required Answers
A. True
B. False
1
90. Hydrates can cause damage if they become loose. No. required Answers
A. True.
B. False.
1
91. Hydrates can damage well bore and intervention equipment. No. required Answers
A. True.
B. False.
1
92. Given the following data: Tubing depth 8,750 ft MD (7,525 ft TVD) Tubing capacity 0.0034 bbl/ft Annular capacity 0.0088 bbl/ft Pump rate 1.25 bpm. a) Calculate the time to pump bottoms-up Min b) Calculate the time for a complete circulation Min
Page 34 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
93. A gas well has the following information: Total depth 12540‟MD (10950‟TVD) Packer depth 10180‟MD (9245‟ TVD).Annulus fluid 9.0 ppg brine , Gas gradient 0.2 psi/ft. SIWHP 2500 psi . What is the pressure differential between the tubing and the annulus at the underside of the tubing hanger? No. required Answers
1
A.850 psi. more in annulus than the tubing.
B.850 psi. more in the tubing than the annulus.
C.1385 psi. more in the annulus than the tubing.
D.1385 psi. more in the tubing than the annulus.
E. 2500 psi. more in the annulus than the tubing.
F. 2500 psi. more in the tubing than the annulus.
94. A producing oil well has been shut in and the SSD is to be opened before killing the well. Calculate the differential pressure that exists across the sleeve before it is opened. Tubing shoe 11350‟MD & 8750‟TVD Completion fluid density 9.0 ppg Packer depth 11000‟ MD & 8600‟TVD Oil density 6.8ppg SSD depth 10950‟MD & 8550‟TVD SIWHP 1000 psi No. required Answers
1
A. The tubing and annulus are in balance.
B. There is 23 psi more in the tubing than the annulus.
C. There is 23 psi more in the annulus than the tubing.
D. There is 253psi more in the tubing than the annulus.
E. There is 253 psi more in the annulus than the tubing.
F. There is 300 psi more in the tubing than the annulus.
G. There is 300 psi more in the annulus than the tubing.
Page 35 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
95. A well is to be killed with 9.0 ppg brine. The MD is 10,525‟ ,TVD 9,250‟ The formation pressure is 4,430 psi. Which statement is true?
1
No. required Answers
A. There will be a 100 psi overbalance at the formation
B. There will be a 50 psi overbalance at the formation
C. The formation will be balanced
D. There will be a 50 psi underbalance at the formation
E. There will be a 100 psi underbalance at the formation.
96. Given the following data, calculate the time required to pump one full circulation. Tubing depth 9,250 ft MD (8,600 ft TVD) Tubing capacity 0.0035 bbl/ft Annular capacity 0.0062 bbl/ft Pump rate 0.70 bpm. No. required Answers
A. 120 min
B. 128 min
C. 60 min
D. 64 min
E. 88 min
F. 95 min.
1
Page 36 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
97. A well is to be killed using packing fluid with a density of 8.99 ppg. The measured depth is 10528 ft and vertical depth is 10260 ft. Formation pressure is 4756 psi. Which of the following statements is correct? No. required Answers
1
A. There will be an overpressure of 99 psi.
B. There will be an overpressure of 44 psi.
C. The formation will be in balance.
D. There will be an under pressure of 42 psi.
E. There will be an under pressure of 99 psi.
98. Given the following data: Casing capacity 0.03049 bbls/ft Tubing nominal weight 10.2 lbs/ft Tubing capacity 0.00729 bbl/ft Closed end tubing displacement 0.01290 bbl/ft Pump displacement 0.0899 bbl/stroke Kill rate 100 strokes/min Well depth MD 11,200 ft Well depth TVD 10,100 ft a) Calculate how many strokes to displace tubing string. No. required Answers
1
A. 565 strokes
B. 908 strokes
C. 1,125 strokes.
Page 37 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
b) Calculate how many strokes to displace the entire wellbore. No. required Answers
1
A. 2,511 strokes.
B. 3,100 strokes.
C. 5,005 strokes.
99. Given the following data: Depth of tubing: 8750 ft MD / 8125 ft TVD Tubing capacity: 0.00387 bbl/ft Annulus capacity: 0.00970 bbl/ft Pumping rate: 1.25 bbl/min a) Calculate the time required to pump up the well Min
b) Calculate the time required for full circulation. Min
Page 38 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
100. Well data: Casing 9 5/8”, 53.5 lb/ft Tubing 3 ½” Production packer at 9750 ft MD. With the aid of the information in the table below which represent the annular volume, calculate the total volume of the annulus above the production packer. Write your answer n the box below. Type
Weight (lbs/ft)
Lin ft / ft3
Bbl/ft
9 5/8”
47
2.7723
0.0642
9 5/8
53.5
2.8835
0.0618
9 5/8
58.4
3.0229
0.0580
9 5/8
59.4
3.0892
0.0577
The total volume of annulus
101.
bbl
Answer the following questions on the basis of the data given for a gas well:
Well depth 9150 ft MD / 7900 ft TVD Formation gradient: 0.57 psi/ft Gas gradient: 0.08 psi/ft a) What is the bottom-hole pressure? psi
b) What will be the maximum surface pressure? Psi
Page 39 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
c) What is the correct working pressure for the wellhead/Xmas tree? No. required Answers
A. 2000 psi
B. 3000 psi
C. 5000 psi
1
d) If the well is to be killed, what will be the minimum density of the killing fluid? No. required Answers
A. 10 ppg.
B. 12 ppg.
C. 11 ppg.
1
Page 40 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
102. Well control kill sheet data:
Gradients: Brine in annulus Oil in tubing Gas in tubing
o o o o o o o
0.49 psi/ft 0.35 psi/ft 0.12 psi/ft
Transition from gas to oil inside tubing at 4,000 ft (Gas Cap) Sliding sleeve at 7,450 ft (in open position) Permanent packer at 7,500 ft Top perforations at 7,700 ft Formation pressure 3,740 psi Closed in tubing head pressure (THP) 1,965 psi Closed in casing head pressure (CHP) 0 psi (Annulus is full to surface)
The diagram on the next page shows the configuration of the well, and the table below shows a reverse circulation kill graph, tubing containing gas and oil with a completion brine in the annulus. The kill fluid gradient is 0.52 psi/ft and is being pumped through the annulus via the sliding sleeve until the hydrocarbons and completion fluids have been circulated out entirely. NOTE:
During the well kill operation we maintain an overbalance of 200 psi above the formation pressure at top perforations.
Page 41 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
Page 42 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
a) What is the bottom-hole pressure at the sliding sleeve at point ( C ) ? psi
b) After 62 bbls of kill fluid have been pumped, the tubing head pressure stabilises at 202 psi (point C Figure 1). This pressure remains unchanged until we have pumped 188 bbls (point E Figure 1). Why does the pressure stabilize at 202 psi? No. required Answers
1
A. The gas coming out of the tubing is not expanding anymore
B. The oil is coming out of the well and the choke opening remains unchanged
C. The tubing is filled with original completion brine and the hydrostatic head remains unchanged
D. The fluid level in the tubing has dropped to below surface.
c) What is the total volume of the annulus between wellhead and sliding sleeve? (Figure 1) Bbl
d) If the tubing head pressure between point C and point D is kept at 150 psi instead of 202 psi, the well will be under balanced? (Figure 1) No. required Answers
A. True.
B. False.
1
Page 43 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
e) At what point does the new kill fluid fill part of the annulus and all of the gas has just been displaced out of the tubing string? (Figure 1)
No. required Answers
A. Point „A‟.
B. Point „B‟.
C. Point „C‟.
D. Point „D‟.
E. Point „E‟.
F. Point „F‟.
1
Page 44 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
103. The kill graph below (Figure 3) shows the pressure during a reverse circulation kill. The tubing and casing IDs and ODs do not vary. The kill fluid being pumped is the lighter than the completion fluid in the annulus. There are oil and gas inside the completion.
Page 45 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
a) What is the total volume of the well? (Figure 3)
Bbl
b) What is the tubing pressure at start of the kill? (Figure 3)
Psi
c) What is the tubing pressure after pumping 200 bbls? (Figure 3)
Psi
d) What is the annulus pressure after pumping 200 bbls? (Figure 3)
Psi
e) At what point does the fluid in the tubing overbalance the formation pressure? No. required Answers
A. Point „A‟.
B. Point „B‟.
C. Point „C‟.
D. Point „D‟.
E. Point „E‟.
F. Point „F‟.
1
Page 46 of 47
International well control forum Well Intervention Pressure
Level 3 & 4 Completion Operations
f) At what point does the kill fluid fill the annulus? No. required Answers
A. Point „A‟.
B. Point „B‟.
C. Point „C‟.
D. Point „D‟.
E. Point „E‟.
F. Point „F‟.
1
Page 47 of 47
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