1.

You have been fingerprinting connections while drilling the current well section with
Annular Pressure Loss (APL) 350 psi while circulating. On the last connection the drain
back and the return flow where faster than had been seen previously. The well is shut-in
giving a stabilized Shut In Casing Pressure (SICP) of 225 psi. There is a non-ported float in
the drill string so you do not have a Shut-In Drill Pipe Pressure (SIDPP) reading. What
action should you take to confirm potential kick indicator? (Choose 1 answer)
a) As the SICP is less than APL, open the BOP and continue with the connection.
b) As the SICP is less than APL, bleed off the SICP by 350 psi and monitor well.
c) Bump the float to get SIDPP. If the SICP is greater than SIDPP, this is normal you
can continue to make connection.
d) Bump the float to get SIDPP and if there is positive pressure on the drill pipe,
circulate the well through the open choke.

2. During well control operation with middle pipe ram closed and shut-in against 4000 psi. It
is decided to strip the tool joint through the middle pipe ram?
Rated Working Pressure 15000 psi
Nominal size 7 1/16
Closing ratio 6.9:1
Opening ratio 2.2:1
What is the driller’s next step? (Choose 1 answer)
a) Close bottom ram and bleed off pressure from above.
b) Initially close upper ram above tool joint then activate the by pass function on the
BOP panel to get sufficient opening pressure from the accumulator then open the
middle ram
c) Initially close upper ram above tool joint then open the middle pipe ram.
d) Initially close the upper pipe ram above the tool joint then pump 4000 psi
pressure between middle and upper pipe ram then open the middle piep ram.
e) SIDPP would be lower than expected.

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3. The measured gas percentage in the drilling fluid increased from 8% to 9% over the past
three days. What should you instruct the driller to do?? (Choose 1 answer)
a) Call the mud loggers to confirm that their instruments have been calibrated
within the last week.
b) Circulate bottoms up before making connections and monitor for an increase in
the gas percentage.
c) Increase WOB to compensate for the increase in gas and stop flow checking on
connections.
d) Carefully monitor for additional warning signs, as formation pressure maybe
increasing.
4. You are drilling through production casing into a reservoir section. In addition to the
drilling fluid which barrier element will make up the barrier envelope? (Choose 1 answer)
a) Cemented production casing, well head, wellhead side outlet valves, casing
hanger, the drilling BOP and IBOP.
b) Drilling BOP and IBOP, the drilling diverter system, and reservoir formation.
c) Ported drill string flapper valve, the reservoir formation and the cemented well
conductor.
d) The drilling diverter system, the cemented well conductor and the reservoir
formation.

5. What is the consequence of losing Bottom Hole Pressure (BHP) while drilling top hole
through a gas bearing formation? (Choose 1 answer)
a) An increase in cuttings build up.
b) Loss of BHP may cause the pipe to become stuck.
c) Top hole usually drilled with water so there is no loss of BHP.
d) Gas around the rig may lead to an increased risk of explosion.

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6. Using the trip sheet below, what action should the supervisor take?
Note: The pipe will be pulled dry.
DP Capacity = 0.0177 bbl/ft
DP Displacement = 0.0069 bbl/ft
Trip
Length Total Calculated tank
Stands
pulle Length Displacem Volu
Pulled
d (ft) (ft) ent (bbl) me
(bbl)
- - - - 15
1-5 462 462 3.2 11.8
6 - 10 464 926 3.2 8.6
11 - 20 930 1856 6.4 3
15 bbl added to trip tank 18
21 - 30 928 2784 6.4 11.6
31 - 40 927 3711 6.4 5.2

(Choose 1 answer)
a) Stop tripping, flow check the well. If flow is confirmed, run back to bottom.
b) Stop tripping, flow check the well. If there is no flow, circulate the well.
c) Stop tripping, flow check the well. If there is no flow, run back to bottom.
d) Stop tripping, flow check the well. If there is no flow, continue to POOH.

7. What is the indication that the annular preventer has deteriorated during routine well
operations? (Choose 1 answer)
a) Annular ‘closed’ light fails to illuminate.
b) Closing time on annular element decreases.
c) Drilling fluid leeks from annular weep hole.

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 d) Pieces of annular rubber found in the drilling fluid returns.

8. Why is hydrocarbon gas influx easier to detect in water-based drilling fluid than oil-based
drilling fluid?
(Choose 1 answer)
a) Hydrocarbon gas has a higher bubble point in water-based drilling fluid.
b) Hydrocarbon gas has a lower bubble point in water-based drilling fluid.
c) Hydrocarbon gas is insoluble in water-based drilling fluid.
d) Hydrocarbon gas is soluble in water-based drilling fluid.

9. After a connection the pit level does not return to the same volume level as before the
connection.
Accumulator Pressure 2900 psi and slowly decreasing
Manifold Pressure 1800 psi and increasing
Annular Pressure 1500 psi and constant

What do these gauge readings indicate? (Choose1 answer)

a) The hydraulic circuit is leaking.
b) There is a problem with the automatic hydro-electric pressure switch.
c) There is a problem with hydraulic pressure regulating valve.
d) The pressure readings are within normal operating range.

10. Can a vacuum degasser be used instead of a mud gas separator during well control
operations? (Choose 1 answer)
a) No, because its position and function makes it unsuitable to handle large volumes
of gas.
b) No, because the mud gas separator is used to determine the gas density.
c) Yes, because the flow rate used during a well kill I small.
d) Yes, because they perform the same function.

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11. What does a vacuum degasser do? (Choose 1 answer)
a) It is used to remove excess barite from the drilling fluid downstream on the shale shakers.
b) It removes drilled solids from the drilling fluid upstream of the shale shakers.
c) It removes large volumes of gas from the drilling fluid upstream of the shale shakers.
d) It removes gas from the drilling fluid downstream of the shale shakers.

12. You inflow test the 7 inch Liner Lap using a retrievable packer. The drill pipe is displaced
to light weight fluid and the packer is set above the Liner Lap. The BOPs are open and the
annulus is monitored on the trip tank.
After bleeding off the initial high pressure, you see an initial increase in the drill pipe
pressure before it stabilizes. The trip tank level remains constant. What could this indicate?
(Choose 1 answer)
a) This indicates the packer has set correctly.
b) This indicates there is a leak in the liner.
c) This indicates there is a leak in retrievable packer.
d) This indicates thermal expansion of the drilling fluid.

13. A kick is shut-in with a 10000 psi rated annular (pressure tested to 7500 psi)
During pressure up, you decide to close the upper pipe due to increasing pressure. The
final stabilised Shut In Casing Pressure (SICP) is 10800 psi. The pipe ram closing ratio is
7:1. You decide to close the middle ram, function test recorded a minimum of 300 psi to
close the ram due to internal friction.
What is the minimum operating pressure required to close the middle ram?(One Answer)
a) Approximately 1200 psi.
b) Approximately 1500 psi.
c) Approximately 1850 psi.
d) Approximately 3000 psi.

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14. Drill Pipe Safety valves (DPSVs) and Inside Blow Out Preventers (IBOPs) must be pressure
tested at the same time interval as the BOP stack. Per API Standard 53, what test
pressures should be applied at the initial test on the rig? (Choose 1 answer)
a) High pressure at 150% of the rated working pressure of the components followed
by low pressure of between 250 psi and 350 psi.
b) High pressure at the rated working pressure of the components low pressure
between 250 psi and 350 psi.
c) Low pressure of between 250 psi and 350 psi followed by a high pressure at 150%
the rated working pressure of the component.
d) Low pressure of between 250 psi and 350 psi followed by high pressure at the
rated working pressure of the component.
15. Drill Pipe Safety valves (DPSVs) and Inside Blow Out Preventers (IBOPs) must be pressure
tested at the same time interval as the BOP stack. Per API Standard 53, what test
pressures should be applied at the subsequent high pressure tests? (Choose 1 answer)
a) 150% of the rated working pressure.
b) Between 250 psi and 350 psi.
c) Rated working pressure of the component.
d) Maximum Anticipated Surface Pressure (MASP) for the hole section.

16. Accumulator test performed on a 15K stack. Once all functions are performed remaining
accumulator pressure is 1380 psi. Interpretation? (Choose 1 answer)
a) Pressure is too high, we need to reduce pressure.
b) Pressure is too low, we need to add more bottles.
c) Pressure is too low, we need to increase pre-charge.
d) Pressure is above the minimum pressure required.

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17. Main advantage of insert type diverter on large conventional annular type?(One Answer)
a) Can allow large diameter tools to be run without removing inserts.
b) Can hold higher pressure as compared to conventional annular type.
c) Has a lower closing volume and is faster to close.
d) Takes longer time to close and reduces shock on formation.
18. An accumulator drawdown test is carried out on a surface BOP stack to API Standard 53.
Accumulator bottle pressure 3000 psi.
Pre-charge pressure 1000 psi.
Final pressure recorded 1160 psi
After 15 min the pressure increased to 1240 psi. What should you do? (Choose 1 answer)
A )Fail, bleed down the bottles and check Pre-charge pressure. Continue with
operation.
B) Pass, activate the charge pumps to charge the bottles to normal operating
pressure.
C) Wait 15 min, if the final pressure is less than 1400 psi, class the test a fail. Check
the pre-charge pressures.
D) Wait 15 min, if the final pressure is more than 1400 psi, class the test a pass.
Continue with next operation.
19. An accumulator drawdown test is performed on a 15K surface BOP. Once all the required
functions were performed, the remaining pressure is 1380. What is your interpretation?
(Choose 1 answer)
a) The remaining pressure is too low, need to reduce the regulated pressure.
b) The remaining pressure is too low, need to add more bottles to the system.
c) The remaining pressure is tool low, need to increase the pre-charge pressure.
d) The remaining pressure is above minimum pressure required to work, continue
operations.

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20. You are drilling top hole from a platform rig using a surface BOP. An annular diverter has
been installed with a flowline located above it and the overboard valves below. The wind
is coming from the east. What pre-shift instructions would be given to the driller about
the diverter procedure for this day? (Choose 1 answer)
a) Close the diverter and close the overboard vent line to the east.
b) Close the flowline before opening the overboard vent line to the east.
c) Close the flowline before opening the overboard line to the west.
d) Open the overboard vent line to the east. Close the overboard vent line to the
west and close the diverter.

21. What is the purpose of an inflow test? (Choose 1 answer)

a) To test the barrier element from any direction of the flow by applying positive
pressure on the barrier element.
b) To circulate from drill string and take returns from the annulus.
c) To test the barrier element in the direction of flow by applying negative pressure
downstream of the barrier element.
d) To test the barrier element in the direction of flow by applying positive pressure
upstream of the barrier.

22. Your rig is equipped with a 15000 psi Surface BOP stack. What test-pump instrument and
equipment ratings are required to test this BOP? (Choose 1 answer)
a) 10,000 psi
b) 15,000 psi.
c) 16,000 psi.
d) 20,000 psi.

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23. surface BOP stack has RWP of 10,000 psi. Use the following graph to identify which well
control operations can be carried out using the annular preventer?

(Choose 2 answers)
a) Maintain a seal on 2 3/8” drill pipe with a well pressure of 1000 psi and an
annular pressure regulated to 650 psi.
b) Maintain a seal on 3 1/2” drill pipe with a well pressure of 1000 psi and an
annular pressure regulated to 400 psi.
c) Maintain a seal on 5” drill pipe with a well pressure of 1000 psi and an annular
pressure regulated to 375 psi.
d) Maintain a seal on 8” drill collar with a well pressure of 1000 psi and an annular
pressure regulated to 175 psi.
e) Maintain a seal with no pipe in the hole, with a well pressure of 1000 psi and an
annular pressure regulated to 1175 psi.

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24. The BOP test pump is connected to the kill line on a surface stack. A plug type tester is in
position and connected to the drill pipe. How can you tell if the test plug is leaking?
(Choose 1 answer)
a) Check for a pressure increase at the manual choke.
b) Check if the test pump can reach the required pressure.
c) Monitor for flow back up the drill pipe.
d) Open the choke line valves through the Mud Gas Separator.

25. According to API standards, how often should a function test on all the components of a
surface BOP be performed during well operations? (Choose 1 answer)
a) At least every 2 weeks (14 days).
b) At least every 3 weeks (21 days).
c) At least every week (7 days).
d) Before spudding or after installation.
26. How often should all operational components of BOP be functioned tested?
(Choose 1 answer)
a) Not exceeding 21 days
b) Once per week (weekly)
c) On installation
d) 2 months.

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 KEY ANSWER
1- D
2- D
3- D
4- A
5- D
6- C
7- D
8- C
9- C
10- A
11- D
12- D
13- C
14- D
15- D
16- D
17- C
18- B
19- D
20- A
21- C
22- D
23- C,E
24- C
25- C
26- B

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