Workover and Completion Well Control Quiz
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Workover and completion are areas where well control can occur and personnel must understand well control correctly. In workover and completion, well control concepts are the same as drilling part and this quiz contains a total of 24 questions which are based on both IWCF and IADC well control. Additionally, learners can go to the list and select another question and each question will have the full explanations. In order to maximize your understanding, you need to carefully think through before selecting answer and you may need to use a calculator to figure out the answer in some questions.
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Question 1 of 24
1. Question
The information of the well is listed below;
- In the well, there is no tubing string.
- The gas migrates to surface therefore the upper part of casing is full with gas.
- The casing pressure is 1200 psi.
- The main objective is to reduce casing pressure using lubricate and bleed procedure. 150 psi pressure increment and 150 psi safety factor are planned for this operation.
According to the lubricate and bleed procedure, what is the first step?
Correct
The first step of lubricate and bleed is to pump mud that equal to planned hydrostatic pressure (for this case, it is 150 psi.)
Incorrect
The first step of lubricate and bleed is to pump mud that equal to planned hydrostatic pressure (for this case, it is 150 psi.)
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Question 2 of 24
2. Question
The information of the well is listed below (same as question 1);
- In the well, there is no tubing string.
- The gas migrates to surface therefore the upper part of casing is full with gas.
- The casing pressure is 1200 psi.
- The main objective is to reduce casing pressure using lubricate and bleed procedure. 150 psi pressure increment and 150 psi safety factor are planned for this operation.
According to the lubricate and bleed procedure, what is the second step?
Correct
After pumping the fluid into the well, casing pressure will increase to any number. At this step, the bottom hole pressure will increase due to additional hydrostatic pressure and increment of casing pressure. The second step is to bleed down to initial pressure which is 1200 psi. Once the well is bled off to 1200 psi, the bottom hole pressure will increase only safety factor of 150 psi which is given by fluid.
Incorrect
After pumping the fluid into the well, casing pressure will increase to any number. At this step, the bottom hole pressure will increase due to additional hydrostatic pressure and increment of casing pressure. The second step is to bleed down to initial pressure which is 1200 psi. Once the well is bled off to 1200 psi, the bottom hole pressure will increase only safety factor of 150 psi which is given by fluid.
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Question 3 of 24
3. Question
In worker and completion operation, what are the minimum number(s) of recommended barriers?
Correct
Two mechanical barriers are recommended.
Incorrect
Two mechanical barriers are recommended.
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Question 4 of 24
4. Question
For a normal bullheading performed on a producing well, what is the volume of kill fluid pumped into the well?
Correct
In a normal bullheading operation, volume of bullheading fluid is determined by tubing volume plus the volume below tubing to the top of perforations.
Incorrect
In a normal bullheading operation, volume of bullheading fluid is determined by tubing volume plus the volume below tubing to the top of perforations.
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Question 5 of 24
5. Question
A normal annular preventer will seal pressure on the dual string completion when closed. Is it true?
Correct
Annular preventer will not seal pressure on dual string because the rubber seal cannot seal the space between two strings completely.
Incorrect
Annular preventer will not seal pressure on dual string because the rubber seal cannot seal the space between two strings completely.
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Question 6 of 24
6. Question
What is the objective of the volumetric well control?
Correct
The volumetric well control is the method to allow gas to the surface while maintaining the bottom hole pressure constant.
Incorrect
The volumetric well control is the method to allow gas to the surface while maintaining the bottom hole pressure constant.
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Question 7 of 24
7. Question
Gas migration rate in brine solution will typically faster than the migration rate in drilling mud.
Is this statement true?
Correct
Gas migration rate in brine is generally faster than rate of migration in the mud.
Incorrect
Gas migration rate in brine is generally faster than rate of migration in the mud.
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Question 8 of 24
8. Question
Well bore influx (kick) is easier to detect in oil based mud as compared to water based mud.
Is this statement true?
Correct
Gas is soluble in oil based mud therefore it cannot be detected easily. Most of the time, you will see the well control indications when the gas is moved upwards from the TD.
Incorrect
Gas is soluble in oil based mud therefore it cannot be detected easily. Most of the time, you will see the well control indications when the gas is moved upwards from the TD.
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Question 9 of 24
9. Question
Well information: TD = 12,000’ MD / 10,000’ TVD.
Shut in tubing pressure = 500 psi.
Fluid weight in the tubing string = 4.0 ppg
What is the formation gradient (psi/ft) of a well?
Correct
Formation pressure = surface pressure + hydrostatic pressure
Formation pressure = 500 + (0.052 x 4 x 10,000) = 2580 psi
Pressure gradient = formation pressure ÷ depth
Pressure gradient = 2,580 ÷ 10,000 = 0.258 psi/ft
Incorrect
Formation pressure = surface pressure + hydrostatic pressure
Formation pressure = 500 + (0.052 x 4 x 10,000) = 2580 psi
Pressure gradient = formation pressure ÷ depth
Pressure gradient = 2,580 ÷ 10,000 = 0.258 psi/ft
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Question 10 of 24
10. Question
What is the main function of subsurface safety valve ?
Correct
The main function of subsurface safety valve is to stop to flow in the event of surface equipment failure.
Incorrect
The main function of subsurface safety valve is to stop to flow in the event of surface equipment failure.
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Question 11 of 24
11. Question
In workover operation, tripping speed is not important while pulling out of hole the completion string because the completion brine has less viscous therefore the swabbing will not be happened.
Is this statement true?
Correct
False. Swabbing effect can be happened every time while tripping out. It does not matter how viscous of fluid is.
Incorrect
False. Swabbing effect can be happened every time while tripping out. It does not matter how viscous of fluid is.
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Question 12 of 24
12. Question
What are the parameters which people should consider when determining the maximum pressure while bull heading?
Correct
There are several things which must take into account when determine the maximum pressure while bullheading as differential pressure across packer seals, formation fracture, tubing and surface equipment condition.
Incorrect
There are several things which must take into account when determine the maximum pressure while bullheading as differential pressure across packer seals, formation fracture, tubing and surface equipment condition.
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Question 13 of 24
13. Question
Formation pressure is 6,220 psi at 10,000’ TVD. If we consider thermal expansion by heat from the well, what is the brine weight just to balance formation pressure?
Correct
Kill weight mud = 6,220 ÷ (0.052 x 10,000) = 12.0 ppg. Thermal expansion will decrease weight of brine on the surface therefore you need kill weight mud more than 12.0 ppg.
Incorrect
Kill weight mud = 6,220 ÷ (0.052 x 10,000) = 12.0 ppg. Thermal expansion will decrease weight of brine on the surface therefore you need kill weight mud more than 12.0 ppg.
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Question 14 of 24
14. Question
After killing the well by bullheading, what should you do in order to hold constant pressure on the formation while you forward circulate to displace the annulus with kill weight mud?
Correct
According to the driller method, you need to hold pressure constant on the side that has the constant fluid. There is full column of kill weight fluid in the tubing so tubing pressure must be hold constant all the time while displacing the annulus with kill weight fluid.
Incorrect
According to the driller method, you need to hold pressure constant on the side that has the constant fluid. There is full column of kill weight fluid in the tubing so tubing pressure must be hold constant all the time while displacing the annulus with kill weight fluid.
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Question 15 of 24
15. Question
The annulus is full of 11.5 ppg fluid and the tubing is full of 7.0 ppg fluid.
What should you do in order to reverse circulate the well with 11.5 ppg while maintaining bottom hole pressure constant?
Correct
According to the driller method, you need to hold pressure constant on the side that has the constant fluid. Therefore, you need to hold casing pressure constant while circulating.
Incorrect
According to the driller method, you need to hold pressure constant on the side that has the constant fluid. Therefore, you need to hold casing pressure constant while circulating.
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Question 16 of 24
16. Question
The producing well is shut-in and the operator collect the following information from the well as listed below;
Shut In Tubing Pressure (SITP) = 4,500 psi
Formation fluid density = 2.0 ppg
Top of perforation = 12,000’ MD / 10,000’ TVD
What is the kill weight fluid required to kill this well?
Correct
Kill Weight fluid = 4,500 ÷ (0.052 x 10,000) + 2 = 10.7 ppg (round up figure)
Incorrect
Kill Weight fluid = 4,500 ÷ (0.052 x 10,000) + 2 = 10.7 ppg (round up figure)
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Question 17 of 24
17. Question
Currently, gas migrates to the surface by using volumetric method, what should you do next?
Correct
Once the gas reaches the surface, you need to pump mud and bleed gas. This process is called “lubricate and bleed”.
Incorrect
Once the gas reaches the surface, you need to pump mud and bleed gas. This process is called “lubricate and bleed”.
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Question 18 of 24
18. Question
15 bbl/hr of partial losses are recorded and there is no tubing in the well. If personnel fails to keep the hole full for 5 hours, what is bottom hole pressure reduction after 5 hours?
Casing capacity = 0.035 bbl/ft. Current mud weight = 9.2 ppg
Correct
Total volume losses in 5 hours = 15 x 5 = 75 bbl
Height of 75 bbl of mud loss = 75 ÷ 0.035 = 2143 ft
Hydrostatic loss = 0.052 x 2143 x 9.2 = 1025 psi
Incorrect
Total volume losses in 5 hours = 15 x 5 = 75 bbl
Height of 75 bbl of mud loss = 75 ÷ 0.035 = 2143 ft
Hydrostatic loss = 0.052 x 2143 x 9.2 = 1025 psi
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Question 19 of 24
19. Question
Sub surface safety valve is recently tested and the result is goo. Personnel can just only shut the well in using sub surface safety valve without installing back pressure valve and then remove the x-mas tree.
Is it true?
Correct
False – the sub surface safety valve must be installed before removing the tree.
Incorrect
False – the sub surface safety valve must be installed before removing the tree.
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Question 20 of 24
20. Question
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 annuls.
What does this indicator tell you?
Correct
Leakage of packer and increase in annular temperature can cause increasing in annulus pressure.
Incorrect
Leakage of packer and increase in annular temperature can cause increasing in annulus pressure.
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Question 21 of 24
21. Question
With gas migration in a shut in well, which one does not increase?
Correct
Gas bubble pressure will not increase with gas migration in a shut in well.
Incorrect
Gas bubble pressure will not increase with gas migration in a shut in well.
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Question 22 of 24
22. Question
Which production tree valve should not be operated in normal operations?
Correct
The lower master valve should not be used in normal operations. It must be use as a last resource to hold pressure.
Incorrect
The lower master valve should not be used in normal operations. It must be use as a last resource to hold pressure.
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Question 23 of 24
23. Question
As long as the fluid weight is more than formation pressure, you can use solid free brine to control the well which has high permeable zones.
Is this statement true?
Correct
False – Not only fluid weight but you need solid in the mud to plug off the formation in order to seal off the losses.
Incorrect
False – Not only fluid weight but you need solid in the mud to plug off the formation in order to seal off the losses.
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Question 24 of 24
24. Question
While working over the well in a zone at 9,000’ TVD with 9.2 ppg fluid, the well is shut in.
Shut In Tubing Pressure = 600 psi
Shut In Casing Pressure = 800 psi
What is the kill weight mud for this well?
Correct
Kill weight mud = 600 ÷ (0.052 x 9,000) + 9.2 = 10.5 ppg
Incorrect
Kill weight mud = 600 ÷ (0.052 x 9,000) + 9.2 = 10.5 ppg
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q 18 there is a mistake in partial loss 15bbl/hr not 15 bbl/min . thanks
Barchi,
Thanks for your comment. I’ve changed the unit already.
Regards,
Shyne
Hi Mr.shyne could u possibly have well controls quiz on coil tubing and snubbing aswell ?
Mario,
Thanks for your comment. We will add some quizzes about coiled tubing and snubbing later.
Regards,
Shyne.
Very good examples in how does it these steps.
Thanks a lot.
Good steps to start learning up about this WO & completion Wells in how its working.