DAY ONE. 2. Referring to the last question, what mud weight would be required to BALANCE normal formation pressure?

DAY ONE 1. Normal formation pressure gradient is generally assumed to be: A..496 psi/ft B..564 psi/ft C..376 psi/ft D..465 psi/ft 2. Referring to the last question, what mud weight would be required to BALANCE normal formation pressure? A. 9.33 ppg B. 10.85 ppg C. 8.94 ppg D. 7.23 ppg 3. What mud weight is required to BALANCE a formation pressure of 2,930 psi at 5,420 ft. TVD? A. 9.8 ppg B. 10.4 ppg C. 10.2 ppg D. 9.6 ppg 4. If the fluid level dropped 550 feet in a 9,600 foot hole containing 10.6 ppg mud, what would the hydrostatic pressure be? A. 5,596 psi B. 4,988 psi C. 5,843 psi D. 5,100 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 1

5. What is the primary means of preventing kicks? (what is primary well control) A. The slow circulating rate used in the kill process B. The use of mud hydrostatics to balance fluid pressure in the formation C. The use of blowout preventers to close in a well that is flowing D. The use of pit volume and flow rate measuring devices to recognize a kick 6. The part of the system pressure loss (standpipe pressure) that is exerted on the formation is: A. Pressure loss of the surface equipment B. Pressure loss in the annulus C. Pressure loss through the drill string D. Pressure loss through the bit DATA FOR QUESTION 7 Mud weight TVD MD Surface equipment pressure loss Drill string pressure loss Bit nozzle pressure loss Annular pressure loss 10.3 ppg 11,600 feet 12,500 feet 100 psi.08 psi/ft 1500 psi.02 psi/ft 7. What is the circulating pressure? A. 1,600 psi B. 760 psi C. 2,850 psi D. 3,000 psi 8. What is the bottom hole pressure while circulating? A. 6,445 psi B. 6,463 psi C. 627 psi D. 6,945 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 2

9. What is meant by Abnormal Pressure (over-pressure) with regard to fluid pressure in the formation? A. The excess pressure due to circulating mud at high rates B. The excess pressure that needs to be applied to cause leak-off into a normally pressured formation C. High density mud used to create a large overbalance D. Formation fluid pressure that exceeds normal formation water hydrostatic pressure 10. Abnormal formation pressures can be caused by? A. Thick sandstone sections B. Insufficient mud weight C. Formation fluids supporting part of the overburden D. All of the above 11. Throughout the world, what is the most common cause of abnormal formation pressures? A. Thick sandstone sections B. Under-compacted shale C. Faults D. Uplift and erosion 12. A gas bearing formation is overpressured by an artesian effect. Which of the following conditions has created the overpressure? A. A formation water source located at a higher level than the rig floor. B. The difference in density between formation gas and formation liquid. C. Compaction of the formation by shallower, overlying formations. 13. The gas/water contact in this well occurs at 3950 feet where a formation pressure gradient of.464 psi/ft exists. ( Gas gradient of.1 psi/ft) What is the pressure at the top of the gas reservoir at 3470 feet? A. 1056 psi B. 1610 psi C. 1785 psi D. 1833 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 3

14. Which of the following statements best describes formation porosity? A. The ratio of the pore spaces to the total volume of the rock B. The ability of the fluid and gas to move within the rock C. The presence of sufficient water volume to provide gas lift D. All of the above 15. Which of the following statements best describes formation permeability? A. The ratio of the pore spaces to the total volume of the rock B. The ability of fluid and gas to move within a rock C. The presence of sufficient water volume to provide gas lift D. All of the above 16. Why is a 20 bbl kick in a small annulus more significant than a 20 bbl kick in a large annulus? A. The kill weight mud can not be easily calculated B. It results in higher annular pressures C. The kicks are usually gas D. The pipe is more prone to getting stuck 17. While tripping out of the hole the well is swabbed in. The mud weight is 10 ppg and the well depth is 10,500 feet. The formation pressure is 5410 psi. If the swab pressure is 125 psi and the formation has sufficient permeability, will the well flow? A. YES B. NO 18. A heavy mud pill is circulated in the well without stopping the pump at any time. At what moment will BHP start to increase? A. As soon as the pill starts to be pumped into the drill pipe B. Once the pill is in the annulus C. Once the pill starts to be displaced into the annulus Intertek Consulting & Training Unpublished work. All rights reserved. Page 4

19. A light pill is circulated into the well without stopping the pump at any time. At what moment will BHP start to decrease? A. As soon as the pill enters the drill pipe B. Once the pill has been displaced into the annulus C. Once the pill starts to be displaced into the annulus 20. When pumping, the standpipe pressure will be slightly lower than the pressure at the pump. What is the most likely reason for this? A. The standpipe gauge is situated at a higher elevation than the pump gauge B. The dynamic pressure loss from the pump to the standpipe C. The hydrostatic pressure of the mud in the standpipe 21. The principle involved in the CONSTANT BOTTOM HOLE PRESSURE method of well control is to maintain a pressure that is: A. Equal to the slow circulating rate pressure B. At least equal to formation pressure C. Equal to the SIDPP D. At least equal to the SICP 22. If the cuttings load in the annulus was high and the well is shut in on a kick. (Answer YES or NO to each question.) A. Would the drill pipe pressure be higher than in a clean well? B. Would the casing pressure be higher than in a clean well? C. Would the casing pressure be lower than in a clean well? 23. The mud weight is 10.2 ppg. At 10,000 feet the bit has drilled into a salt water zone with a pressure of 6560 psi. With the well closed in what will the stabilized SIDPP be? psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 5

24. There will be little or no difference between the SIDPP and SICP as long as the influx stays in the horizontal section of the well. What is the reason for this? A. The influx has little or no effect on the hydrostatic head in the annulus while it is in the horizontal section of the hole B. In horizontal wells, there is usually little or no difference between the density of the drilling fluid and the density of the influx C. In horizontal wells, the influx can also enter the drill string because the BHA is usually very short in comparison with those used in vertical wells D. The influx migration rate differs in vertical wells as compared to horizontal wells 25. During normal drilling operations a 30 bbl slug of light fluid is pumped into the drill string followed by original drilling fluid. WELL DATA Well depth TVD Drill pipe capacity Original fluid density Light fluid density 9600 feet.0178 bbl/ft 12.3 ppg 10.5 ppg Calculate the bottom hole pressure once the light slug is in the drill pipe. A. 158 psi B. 6,140 psi C. 5,982 psi D. 4,779 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 6

26. While drilling a severe loss of returns occurs. After the pumps were stopped it was observed that the fluid level in the well dropped far below the flow line. The well was then filled to the top with sea water. Drilling fluid density Sea water density Equivalent height of sea water 10.3 ppg 8.5 ppg 240 feet What is the reduction in hydrostatic pressure after this action compared to before the losses occurred? A. 407 psi B. 189 psi C. 22 psi D. 17 psi 27. 13 3/8 61 lbs/ft casing is being run in the hole with a conventional float valve. The casing capacity is.1521 bbl/ft. Due to a problem with the fill up line, the casing was not filled. Twelve 40 foot joints are run in the hole. If the float valve suddenly were to fail, how would this affect bottom hole pressure? The mud weight is 11.5 ppg and the annular capacity is.124 bbl/ft. A. BHP decreases by 73 psi B. BHP decreases by 158 psi C. BHP decreases by 264 psi D. BHP decreases by 480 psi 28. A gas kick is taken with the bit on bottom while drilling a vertical well. Well depth Casing shoe Mud Weight Formation Pressure Gradient Drill Pipe Capacity Height of the influx Influx gradient 13,940 feet TVD 11,500 feet TVD 13.4 ppg.715 psi/ft.0175 bbl/ft 425 feet.15 psi/ft What will the expected pressure at the casing shoe be after the well is shut in and pressures have stabilized? A. 6459 psi B. 8203 psi C. 8499 psi D. 6755 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 7

29. A gas kick has been circulated out. At the time the gas reaches the casing shoe at 3126 feet TVD the pressure at the top of the bubble is 2200 psi. If the OWM is 11.6 ppg, what is the casing pressure at the surface? A. 314 psi B. 442 psi C. 542 psi D. 506 psi 30. The flow sensor shows a total loss of returns. You pick up and check for flow. The mud level in the hole is out of sight. What action would you take? A. Pump at a reduced rate while mixing LCM B. Continue drilling blind C. Close the well in and check for pressures D. Begin filling the annulus with fluid ( water ) noting how many barrels are required to fill the hole 31. Which of the following would be affected by the permeability of a formation from which a kick occurred? (TWO ANSWERS) A. The time required for surface pressures to stabilize B. The calculated kill mud density C. The Initial Circulating Pressure D. The size of the influx in the wellbore E. The shut in drill pipe pressure 32. In which of the following cases would you most likely swab in a kick? A. When the bit is pulled into the casing B. When the first few stands are being pulled off bottom C. About halfway out of the hole 33. Which THREE of the following practices are likely to increase the chance of swabbing? A. Pulling pipe slowly B. Maintaining high mud viscosity C. Pulling through tight spots with the pump off D. Pulling through tight spots with the pump on E. Pulling pipe quickly F. Pumping out of the hole Intertek Consulting & Training Unpublished work. All rights reserved. Page 8

34. In which of the following circumstances would a kick be most likely to occur through failure to fill the hole? A. When the first few stands are pulled off bottom B. When pulling the drill collars C. When the drill collars enter the casing 35. While pulling out of the hole it is noticed that mud required to fill the hole is less than calculated. What action must be taken? A. Flow check. If negative, displace a 100 foot heavy slug into the annulus and continue to pull out of the hole B. Flow check. If negative, run/ strip back to bottom and monitor returns C. Pump remaining stand out of the hole D. Flow check. If negative, continue pulling the pipe out of the hole E. Shut the well in and circulate the hole clean 36. The driller is tripping pipe out of a 12 ¼ diameter hole. 25 X 92 foot stands of 5 pipe have been removed. There are 85 more stands to pull. The calculated displacement of the 9 ½ collars is.08 bbl/ft. The capacity of the drill pipe is.01776 bbl/ft and the metal displacement is.0075 bbl/ft. The trip tank volume has reduced from 27 bbl to 15 bbl. What action should be taken in this situation? A. Flow check. If negative continue to pull B. Shut the well in and circulate the hole clean C. Flow check. If negative, displace a 100 foot heavy slug into the annulus and continue to pull out of the hole D. Flow check. If negative, return back to bottom and monitor returns E. Pump the remaining stands out of the hole Intertek Consulting & Training Unpublished work. All rights reserved. Page 9

37. A well was drilled to a TVD of 8,200 feet. Casing Shoe TVD Mud Density Open Hole Capacity Pipe Metal Displacement Casing Capacity Pore Pressure Length of 1 stand 4,500 feet 13.9 ppg.0702 bbl/ft.0080 bbl/ft.157 bbl/ft.700 psi/ft 93 feet How many FULL STANDS (complete stands) of drill pipe can the driller pull dry BEFORE the hole level reduces the bottom hole pressure enough to cause the well to go underbalanced? Stands 38. You are pulling out of the hole. Two 93 stands of 8 drill collars have been stood back in the derrick. The displacement is.0549 bbl/ft. According to your Assistant Driller 5.1 bbl should be pumped into the well. It only takes 5 bbl to fill the hole. (Answer YES or NO to each question) A. Are the calculations correct? B. Have you taken a 5 bbl influx? C. All OK, keep going? 39. If the driller pulls 400 feet of 8 X 2 13/16 collars from the hole, including the bit, without filling the hole, what would be the reduction in bottom hole pressure? Mud weight Casing capacity Metal displacement 11.8 ppg.1545 bbl/ft.0545 bbl/ft psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 10

DATA FOR QUESTIONS 40a & 40b BELOW Drill pipe capacity Drill pipe displacement Average stand length.01776 bbl/ft.0076 bbl/ft 93 feet Calculate: 40a. Mud required to fill the hole per stand when pulling dry. bbl 40b. Mud required to fill the hole per stand when pulling wet. bbl 41. Gas cut drilling mud normally does not reduce bottom hole pressure enough to cause a well to kick. But BHP is reduced most when: A. The gas is near the surface B. The gas is at or near bottom C. The gas is about halfway up the hole D. All are about the same Intertek Consulting & Training Unpublished work. All rights reserved. Page 11

Data for questions 42, 43, 44, Prior to pulling out of the hole from a depth of 10,485 feet TVD, the pipe is full of 10.4 ppg mud. The pipe capacity is.01776 bbl/ft. A 25 bbl slug weighing 12.0 ppg is pumped into the drill pipe causing the level to drop inside the drill pipe. 42. What is the drop in bottom hole pressure due to pumping the slug into position? A. 25 psi B. 0 psi C. 117 psi D. 135 psi 43. How many bbl of mud will be observed in the mud pits due to the U-Tube (backflow) effect? A. 3.24 bbl B. 3.85 bbl C. 4.75 bbl D. 6.26 bbl 44. How many feet of dry pipe will there be after the slug is in position? A. 182 feet B. 217 feet C. 267 feet D. 352 feet 45. Which TWO of the following indications suggest that mud hydrostatic pressure and formation pressure are almost equal? A. Increase in flow out of the well B. Increasing background gas, trip gas, and connection gas C. Temperature anomalies D. Pit gain E. All of the above Intertek Consulting & Training Unpublished work. All rights reserved. Page 12

46. Prior to starting to POOH a heavy slug was pumped into the drill pipe. DATA: Drill pipe capacity Annulus capacity (DP/Csg) Density of drilling fluid Density of slug Volume of slug inside the drill pipe Well depth.0174 bbl/ft.0510 bbl/ft 13.2 ppg 16.5 ppg 20 bbl 9,600 feet Use the data to calculate the vertical distance between the drilling fluid level in the drill pipe and in the flow line after the slug has been pumped. A. 287 feet B. 270 feet C. 207 feet D. 362 feet 47. Which of the following can be considered the SECOND RELIABLE indication that an influx has entered the well while drilling? A. Gas cut mud B. A drilling break C. A decrease in pump pressure D. Gain in pit volume E. Change in the nature of the cuttings 48. Which of the following would not be a warning sign that the bottom hole pressure is approaching formation pressure? (ONE ANSWER) A. Large crescent shaped cuttings B. Well flowing with pumps off C. Increase in chloride content of the mud D. Increase in connection gas Intertek Consulting & Training Unpublished work. All rights reserved. Page 13

49. A driller observes a warning sign of a kick. Why is it better to continue pumping while raising the pipe to shut in position? A. To minimize down time B. To minimize the amount of influx by keeping annular pressure loss as long as possible C. The driller should shut off the pump before picking up to identify the influx as soon as possible D. To prevent the pipe from getting stuck 50. Which of the following situation would be more difficult to detect? A. A gas kick in oil-based mud B. A gas kick in water-based mud 51. While drilling along at a steady rate the derrickman calls to ask if the mud pumps can be slowed down so the shakers can handle the increase in the cuttings coming back in the mud returns. What would be the safest course of action? A. Check for flow if none, then continue at the same rate allowing the excess to bypass the shakers and get caught on the sand trap which can be dumped later B. Slow down the mud pumps until the shakers can handle the volume of cuttings in the returns as requested by the derrickman C. Check for flow if none, then return to the original drilling parameters D. Check for flow if none, then circulate bottoms up at a reduced rate so the shakers can handle cuttings volume, flow check periodically during circulation 52. Which of the following is the FIRST RELIABLE indication that you have taken a kick while drilling? A. Increase in torque B. Gas cut mud C. Decrease in pump pressure D. Increase in flow rate Intertek Consulting & Training Unpublished work. All rights reserved. Page 14

53. Of the following warning signs, which TWO would leave little room for doubt that the well is kicking? A. Flowline temperature increase B. Increase in rotary torque C. Flow rate increase D. Decreased string weight E. Pit volume gain F. Increase in rate of penetration 54. It can be said that closing in the well promptly is one of the most important duties of a driller. Any delay may make the well potentially more difficult to kill. From the list of practices below, choose the SIX MOST LIKELY to lead to an increase in the size of the influx. A. Switching off the flow meter alarms B. Regular briefings for the derrickman on his duties regarding the monitoring of pit levels C. Drilling a further 20 feet after a drilling break before checking for flow D. Running regular pit drills for crews E. Maintaining stab-in valves F. Testing stab-in valves during regular BOP tests G. Excluding the drawworks from the SCR assignment H. Keeping air pressure at the choke panel at 10 psi I. Calling the tool pusher to the floor prior to shutting in the well J. Not holding down the master air valve on the remote BOP control panel while functioning a preventer 55. Which TWO of the following drilling practices should be considered when connection gas is noticed? A. Pump a low viscosity pill around the bit to assist in reduction of balled bit or stabilizers B. Control drilling rate so that only one slug of connection gas is in the hole at any one time C. Pulling out of the hole to change the bit D. Raising the mud yield point E. Minimizing the time during connections when the pumps are switched off Intertek Consulting & Training Unpublished work. All rights reserved. Page 15

56. While tripping in the actual volume of mud displaced is less than the calculated volume. What could cause this? A. The well is flowing B. A kick may have been swabbed in C. A formation is taking fluid 57. If flow through the drill pipe occurs while tripping, what should be the first action to take? A. Pick up and stab the kelly/ top drive B. Run back to bottom C. Close the annular preventer D. Stab a full opening safety valve 58. What are the advantages/disadvantages of using float in the drill string? A. Reverse circulating Advantage Disadvantage B. Reading the SIDPP Advantage Disadvantage C. Cuttings flowback on connections Advantage Disadvantage D. Surge pressure Advantage Disadvantage 59. After a round trip at 8960 feet with 10.9 ppg mud we kick the pump in and start circulating. An increase in flow is noticed and the well is shut in with 0 psi on the drill pipe and 300 psi on the casing. What is the required mud weight to kill the well? (there is no float in the drill string) A. No way of knowing B. 11.5 ppg C. 10.9 ppg D. 12.0 ppg 60. What was the most probable cause of the influx in the last question? A. Abnormal formation pressure B. The mud weight was not high enough to contain formation pressure C. The well was swabbed in or the hole was not adequately filled during the trip D. It s impossible to tell based on the information given Intertek Consulting & Training Unpublished work. All rights reserved. Page 16

61. While tripping out of the hole a kick was taken and a full bore kelly cock (full opening safety valve) was stabbed and closed. A safety valve (inside BOP) was made up to the top of the kelly cock prior to stripping in. Answer YES or NO to each question. A. Should the kelly cock be closed? B. If the kelly cock is left in the open position, can a wireline be run inside the drill string? 62. While running pipe back into the hole, it is noticed that the normal displacement of mud into the trip tank is less than calculated. After reaching bottom and commencing circulation the return flow meter is observed to reduce from 50% to 42%. A pit loss of 2 bbl is noted. What is the most likely cause of these indications? A. Partial loss of circulation B. Total loss of circulation C. A kick has been taken D. The well has been swabbed in 63. After the well has stabilized, while waiting for kill mud to be mixed, both the drill pipe and the annulus pressures start to increase. What type of influx does this indicate? A. Fresh water B. Salt water C. Oil D. Gas 64. A gas kick is being circulated up the hole. What is the surface pit volume most likely to do? A. Increase B. Stay the same C. Decrease 65. After shutting in on a kick the SIDPP and SICP pressures have been stable for 15 minutes then they both start slowly rising by the same amount. Which one of the following is the cause? A. Another influx has entered the well B. The influx is migrating C. The gauges are faulty D. The BOP stack is leaking Intertek Consulting & Training Unpublished work. All rights reserved. Page 17

66. While preparing to circulate kill weight mud, the gas bubble begins to migrate. If no action is taken, what will the pressure in the gas bubble do as gas rises? A. Increase B. Decrease C. Remain approximately the same 67. What will happen to bottom hole pressure? A. Increase B. Decrease C. Remain approximately the same 68. What will happen to SICP? A. Increase B. Decrease C. Remain approximately the same 69. What will happen to the pressure at the casing seat? A. Increase B. Decrease C. Remain approximately the same 70. A gas kick has been shut in while out of the hole. A stabilized SICP was observed. One hour later the SICP was observed to have risen by 100 psi due to gas migration. The hole capacity is.07323 bbl/ft and the mud weight is 15.4 ppg. How far has the bubble moved up the hole? feet Intertek Consulting & Training Unpublished work. All rights reserved. Page 18

71. If the original closed in pressures were 300 psi SIDPP and 500 psi SICP and both started rising close to the maximum allowable would you. A. Bleed off until the annulus pressure was 500 psi B. Bleed off until the drill pipe pressure was 300 psi C. Bleed off until the annulus pressure was 300 psi 72. A vertical well with a surface BOP stack in use has been shut in after a kick. The surface pressures are: SIDPP = 500 psi; SICP = 800 psi; MW = 10 ppg The well is left shut in for some time during which the gas migrates 600 feet up the well. (there is no float in the drill string). What will be the expected pressures at the surface at this moment? Drill Pipe Pressure Casing Pressure A. 500 psi 1112 psi B. 812 psi 1112 psi C. 812 psi 800 psi D. 500 psi 800 psi 73. While drilling, a gas kick is taken and the surface pressures are: SIDPP = 300 psi SICP = 475 psi There is a total pump failure and the influx starts to migrate. The surface pressures start to increase. If the casing pressure is held constant by adjusting the choke, what affect will this have on BHP? A. It will stay constant B. It will increase C. It will decrease 74. A 15 bbl influx of gas was swabbed in at 13200 feet. The formation pressure is 9300 psi and the mud weight in use is 14.2 ppg. What would the expanded volume of the gas be at a depth of 8000 feet. The hole is left open and assume no change in temperature. A. 16.3 bbl B. 23.6 bbl C. 26.3 bbl D. 29.6 bbl Intertek Consulting & Training Unpublished work. All rights reserved. Page 19

75. When tripping out of the hole, with 30 stands remaining it is noticed that the well is flowing. Which one of the following actions should be taken to close the well in using the SOFT SHUT-IN? A. Close the BOP. Stab in the full opening safety valve Close the safety valve Open choke Record pressures B. Stab a full opening safety valve Close the safety valve Open BOP side outlet valve Close the BOP Close the choke Record pressures C. Stab full opening safety valve Open BOP side outlet valve Close BOP Close choke Record pressures D. Open BOP side outlet valve Close BOP Stab full opening safety valve Close safety valve Close choke 76. Which list below (a, b, c, or d) describes how the choke manifold will most likely be set up for a SOFT SHUT-IN while drilling. BOP Side Outlet Hydraulic Valve Remote Choke Degasser Valve A. Open Closed Closed B. Open Open Closed C. Closed Open Open D. Closed Closed Open Intertek Consulting & Training Unpublished work. All rights reserved. Page 20

77. Listed below are two procedures shutting in a kicking well: 1. With the choke already open, pick up off bottom, shut down the pumps, open the BOP side outlet hydraulic valve, close the BOP, close the choke, record pressures. 2. With the choke already closed, pick up off bottom, shut down the pumps, close the BOP, open the BOP side outlet hydraulic valve, record pressures Match the procedures to the title below, put the number in the spaces provided. A. Soft Shut-in B. Hard Shut-in 78. The difference between the hard shut in and the soft shut in is that the hard shut in: A. The blind rams are used B. The BOP is closed with the choke open C. The BOP is closed with the choke closed D. The kick is diverted 79. The main advantage of the soft shut in procedure over the hard shut in procedure is: A. To minimize the hydraulic shock on the formation. B. To prevent further influx of formation fluids C. To allow pressures to be determined D. All of the above 80. When a kick occurs, why is it important to shut the well in as soon as possible? A. A larger pit gain will result in higher SIDPP and heavier KWM TRUE FALSE B. A larger pit gain will result in higher SIDPP and SICP TRUE FALSE C. A larger pit gain will result in higher SICP but the SIDPP will remain the same TRUE FALSE Intertek Consulting & Training Unpublished work. All rights reserved. Page 21

81. We are planning to circulate out a kick with the Wait and Weight Method. The volume of the surface lines on the rig is 20 bbl. Identify the best procedure for dealing with the surface line volume. A. Re-zero the stroke counter once KWM reaches the bit B. Subtract 20 bbl (adjusted for pump strokes) from the strokes to bit total on the kill sheet C. Ignore the surface line volume D. Re-zero the stroke counter when KWM starts down the drill pipe 82. Why do we need to take into account surface line volume (from the mud pumps to the rig floor) when preparing the kill sheet with the Wait and Weight Method? (TWO ANSWERS) A. If we don t, following the drill pipe pressure graph will result in a BHP that is too low. B. If we don t, there will be no effect on BHP. C. If we don t, following the drill pipe pressure graph will result in a BHP that is too high. D. If we don t, the total time for killing the well will be shorter than calculated E. If we don t the total time for killing the well will be longer than calculated. 83. Why must pit volume be monitored during a well killing operation? A. To determine KWM B. To determine the influx volume C. To determine if lost returns are occurring D. To determine the gain due to barite additions 84. You have to increase the drill pipe pressure by approximately 100 psi by manipulating the choke during a well kill operation. Of the following options, which one would you choose? A. Keep closing the choke until you see the drill pipe pressure start to increase B. Close the choke to increase the casing pressure by 100 psi and wait for the drill pipe pressure to increase. Intertek Consulting & Training Unpublished work. All rights reserved. Page 22

85. WELL DATA Slow Circulating Rate Pressure SIDPP SICP 500 psi @ 40 SPM 800 psi 1100 psi The well is shut in Circulation is started with original weight mud. While the pump is being brought up to 40 spm, which pressure is to remain constant to maintain a constant BHP? A. 800 on the drill pipe pressure gauge B. 2300 on the drill pipe pressure gauge C. 1100 on the casing gauge D. 1600 on the casing gauge 86. A kick is being circulated out at 30 SPM with a drill pipe pressure reading of 550 psi and a casing pressure of 970 psi. It is decided to slow the pump to 20 spm while maintaining 970 psi on the casing gauge. How will this affect BHP? A. Increase B. Decrease C. Stay the same D. No way of knowing 87. If a well was closed in after the first circulation of the Driller's Method, what value would you expect on the drill pipe pressure gauge and the casing pressure gauge? SIDPP = 100 psi SICP = 525 psi A. Both pressures would be equal to the original SIDPP B. Both pressure should be reading 0 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 23

88. If the pump speed is increased, what happens to the friction losses in the annulus? A. Decreases B. Stays the same C. Increases 89. The main purpose of the Leak-Off Test is to: A. Determine formation pressure at the shoe B. Test the surface equipment for pressure integrity C. Determine the strength of the formation below the casing shoe D. Test the cement and casing for pressure leaks 90. Which of the following is usually the main limiting factor in determining the MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE? A. The maximum pressure that the casing will hold B. The maximum pressure that the formation below the casing shoe will hold Intertek Consulting & Training Unpublished work. All rights reserved. Page 24

91. Which of the following defines MAASP? A. The pressure in excess of mud hydrostatic that, if exceeded, is likely to cause losses at the shoe formation B. The total pressure applied at the shoe formation that is likely to causes losses C. The maximum BHP allowed during a kill operation D. The maximum pressure allowed on the drill pipe gauge during a kill operation 92. Which of the following best describes fracture pressure? A. The pressure in excess of mud hydrostatic, that if exceeded, is likely to cause losses at the shoe formation B. The total pressure applied to the shoe formation that is likely to cause losses C. The maximum BHP during a kill operation D. The maximum pressure allowed on the drill pipe gauge during a kill operation 93. Which of the three following conditions are essential for the calculation of an accurate formation strength test? (CHOOSE THREE ANSWERS) A. Mud volume pumped until leak-off starts B. Measured depth of the casing shoe C. Mud volume in the casing D. Weight of the mud being used E. True vertical depth of the casing shoe 94. When should a leak-off test be conducted? A. Immediately after running and cementing casing B. Immediately before running casing C. After drilling out the casing shoe 5 to 15 feet into new formation D. Immediately before drilling out the casing shoe 95. How often should MAASP be calculated? A. After each bit change B. After a change in mud weight C. After every 500 foot interval is drilled Intertek Consulting & Training Unpublished work. All rights reserved. Page 25

96. Indicate the leak-off pressure from the graph below. Leak-Off psi 2,000 1,900 1,800 1,700 1,600 1,500 Pump Pressure (psi) 1,000 500 Casing Setting Depth = 10,040 ft. Mud Density = 13.1 ppg 97. Use the data from Question 96 to calculate the fracture pressure. psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 26

98. Indicate the leak-off pressure from the graph below. Leak-Off psi 1,100 1,000 900 800 Pressure (psi) 700 600 500 400 300 200 Casing Setting Depth = 8,550 ft. Mud Density = 12.5 ppg 100 0 99. Use the data from Question 98 to calculate the fracture pressure. psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 27

100. Casing has been set and cemented. The well program calls for a leak-off test but the mud weight in the active pits has been increased to.5 ppg higher than the mud weight in the hole. Which of the following would provide the most accurate leak-off test results? A. Use a cement pump to pump down the drill pipe and record pressures and barrels pumped B. Circulate and condition the mud until the density is the same throughout the system C. Use a cement pump to pump down the annulus and record pressures and barrels pumped D. It is impossible to obtain accurate test results so use pressures from a previous test 101. Which of the following would contribute to higher fracture gradients? A. Casing setting depth close to the surface B. Casing setting depth far from the surface C. A small difference existing between the mud hydrostatic pressure and fracture pressure D. A large difference existing between the mud hydrostatic pressure and fracture pressure 102. The mud weight in the well was increased by 1.2 ppg. What will the new MAASP be if the casing shoe is set at 5,675 feet MD and 5,125 feet TVD? A. 354 psi lower than previous MAASP B. 320 psi higher than previous MAASP C. 320 psi lower than previous MAASP D. 354 psi higher than previous MAASP 103. The fracture gradient of an open hole formation at 3680 feet is.618 psi/ft. The drilling mud currently in use is 9.8 ppg. Approximately how much surface casing pressure can be applied to the well before the formation breaks down? A. 350 to 375 psi B. 2275 to 1195 psi C. 630 to 692 psi D. 382 to 398 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 28

DATA FOR QUESTIONS 104 &105 13 3/8 surface casing is set and cemented at 3126 TVD. The cement is drilled out together with 15 feet of new hole using 10.2 ppg mud. A Leak-Off Pressure of 670 psi is observed. 104. What is the formation fracture gradient? A..619 psi/ft B..837 psi/ft C..7447 psi/ft D..530 psi/ft 105. What is the MAXIMUM ALLOWABLE ANNULAR SURFACE PRESURE for 11.4 ppg mud in use at 6500 feet TVD? A. 865 to 869 psi B. 471 to 475 psi C. 449 to 454 psi D. 563 to 569 psi 106. At 40 spm with 10 ppg mud the pump pressure is 1000 psi. What would the pump pressure be if the pump rate were decreased to 25 spm and the mud weight was increased to 11.4 ppg? A. 713 psi B. 550 psi C. 445 psi D. 390 psi 107. Pick Five (5) situations from the following list under which you would consider taking a new SCRP: A. Every shift B. Mud weight changes C. Significant mud property changes D. Before and after a leak-off test E. After each connection when drilling with a top drive F. When long sections of hole are drilled rapidly G. After recharging pulsation dampeners H. When returning to drilling after killing a kick Intertek Consulting & Training Unpublished work. All rights reserved. Page 29

108. Many factors should be considered when selecting a kill pump rate. Hhowever, the objective should be to regain control of the well. Choose the one answer that meets this objective. A. By using the slowest pump rate B. Before the end of the tour C. As safe as possible considering all aspects of the kill D. As fast as possible by using the maximum pump rate 109. If flow rate is kept constant which TWO of the following factors will INCREASE the circulating pressure? A. When the mud density in the well is lowered B. When the well depth is increased C. When the bit nozzle sizes are increased D. When the length of the drill collars is increased 110. Shut-in Casing Pressure is used to calculate: A. KWM B. Influx gradient and type when the influx volume and well geometry are known C. Maximum Allowable Annular Surface Pressure D. Initial Circulating Pressure Intertek Consulting & Training Unpublished work. All rights reserved. Page 30

111. At what point while correctly circulating out a gas kick is it possible for the pressure at the casing shoe to be at its maximum? (THREE ANSWERS) A. At initial shut in B. When kill mud reaches the bit C. When kill mud reaches the casing shoe D. When the top of the gas reaches the casing shoe 112. Which three of the following conditions in the well increases the risk of exceeding the MAASP during a well killing operation? A. Long open hole section B. Large differences between formation breakdown pressure and the mud hydrostatic pressure C. Small volume of influx D. Short open hole section E. Large volume of influx F. Small differences between formation breakdown pressure and mud hydrostatic pressure 113. What is the reason for circulating out a kick at a slow pump rate? A. Obtains a smaller expansion of the gas influx thereby reducing casing pressure during the kill process B. Create a sufficient pressure loss in the circulating system to give a greater overbalance for a safer kill operation C. Minimize excess pressure exerted on formation during the kill process 114. A kick was taken and is being circulated out of a deep well with a deep casing shoe. The casing pressure is approaching the maximum allowable and the influx is still in the open hole. Of the actions listed below, which would be the most appropriate? A. Start pumping mud at least 2 ppg heavier than KWM down the drill pipe B. Maintain the casing pressure at the maximum allowable by adjusting the choke C. Minimize any extra pressure in the annulus without allowing BHP to drop below formation pressure Intertek Consulting & Training Unpublished work. All rights reserved. Page 31

115. Which of the following is NOT a warning sign of when a kick may be occurring? A. Flow rate increase B. Increased torque C. Pit gain D. Well flowing with the mud pumps off Intertek Consulting & Training Unpublished work. All rights reserved. Page 32

Day 2 1. What is the correct meaning of the term Secondary Well Control? A. Preventing flow of formation fluid into the wellbore by maintaining drilling fluid hydrostatic equal to or greater than formation pressure B. Preventing the flow of formation fluid into the well by maintaining a sum of drilling fluid hydrostatic and dynamic pressure loss C. Preventing the flow of formation fluids into the well by maintaining the dynamic pressure loss in the annulus equal to formation pressure D. Preventing flow of formation fluids into the well by using BOP equipment in combination with the hydrostatic pressure of the mud to balance formation pressure 2. Company policy states: while killing a well you will always attempt to kill the well using a method that minimizes the pressure on the stack and upper casing. Which method would you choose? A. Wait and Weight B. Driller s C. Lubricate and Bleed D. Volumetric 3. You are circulating out a gas kick using the Wait & Weight Method. What will happen to BHP in each of the following situations? A. If drill pipe pressure is held constant while kill mud is being pumped to the bit. a. Increase b. Decrease c. Stay the same B. If drill pipe pressure is held constant while kill weight mud is pumped up the annulus. a. Increase b. Decrease c. Stay the same C. If SPM is increased and drill pipe pressure is held constant. a. Increase b. Decrease c. Stay the same D. If the gas bubble is not allowed to expand. a. Increase b. Decrease c. Stay the same Intertek Consulting & Training Unpublished work. All rights reserved. Page 33

4. The following diagrams depict approximately the pressure changes at various points in a well being killed using the Wait and Weight Method and maintaining the correct bottom hole pressure. (The diagrams are not to scale) Match the following names to the correct graphs write the appropriate number in the answer boxes provided. 1. Drill Pipe Pressure 2. Bottom Hole Pressure 3. Casing Shoe Pressure 4. Surface Casing Pressure Intertek Consulting & Training Unpublished work. All rights reserved. Page 34

5. When starting a kill operation with a surface BOP, the choke pressure is held constant while bringing the pump up to speed. The drill pipe pressure gauge now reads 250 psi higher than the calculated initial circulating pressure. To maintain constant BHP, what is the best action to take? A. Open the choke and let the standpipe pressure drop to the calculated initial circulating pressure. B. Continue to circulate with the new initial circulating pressure and adjust the drill pipe graph accordingly C. There will now be a 250 pi overbalance on the bottom which is acceptable. Nothing needs to be done. 6. A well is being killed correctly using a constant BHP method. At what stage during the kill operation can the choke pressure reading exceed the MAASP without breaking down at the shoe? A. Kill mud circulated to the bit B. Influx in the casing annulus C. Influx around the BHA. D. Influx in the open hole annulus 7. On the second circulation of the Driller's Method if the casing pressure was held constant until KWM reached the surface what would happen to BHP? A. Increase B. Decrease C. Stay the same Intertek Consulting & Training Unpublished work. All rights reserved. Page 35

8. A well is being killed using the Driller's Method. Original SIDPP = 500 psi Original SICP = 900 psi After the first circulation the well is shut in and pressures allowed to stabilize. They then read: SIDPP = 500 psi SICP = 650 psi It is decided not to spend any more time circulating original mud. Which one of the following actions should be taken first. A. Prepare to use the Wait and Weight Method B. Bullhead annulus until the SICP is reduced to 500 psi C. Reverse circulate until the SICP is reduced to 500 psi D. Continue with the second circulation of the Driller's Method 9. For each of the following statements note whether it relates to the Driller's Method or the Wait and Weight method. Circle the correct method. A. Minimizes pressures experienced on surface. Driller s Wait and Weight B. Removes influx from the hole before pumping KWM Driller s Wait and Weight C. Pump KWM while circulating the influx up the annulus Driller s Wait and Weight D. Maintain a constant drill pipe pressure for the first circulation Driller s Wait and Weight 10. Under which circumstances would the Wait and Weight Method provide lower equivalent pressure at the casing shoe than the Driller's Method? A. When the drill string volume is greater than the open hole annular volume B. When the drill string volume is less than the open hole annular volume C. The pressure at the casing shoe will be the same regardless of the method used Intertek Consulting & Training Unpublished work. All rights reserved. Page 36

11. Which statement is correct when comparing the Driller's Method and the Wait and Weight Method? A. The Driller's Method will give the lowest casing shoe pressure when the open hole annular volume is larger than the drill string volume B. The Wait and Weight Method will give the lowest casing shoe pressure when the open hole annular volume is smaller than the drill string volume C. The Wait and Weight Method will give the lowest casing shoe pressure when the open hole volume minus the gain is larger than the drill string volume D. The Wait and Weight Method will always give a lower maximum pressure at the casing shoe than the Driller's Method 12. An influx is being circulated out using the Driller's Method and using 1,100 psi at 30 spm.. The operator decreases the pump speed to 25 spm but holds the PUMP PRESSURE constant. Does this have any affect on bottom hole pressure? A. Increases BHP B. Decreases BHP C. BHP remains approximately the same 13. An influx is being circulated out using the Driller's Method and using 1,100 psi @ 30 spm. The operator increases the pump rate to 35 spm but holds the pump pressure constant. Does this have any impact on bottom hole pressure? A. Increases BHP B. Decreases BHP C. BHP remains approximately the same 14. While in the process of killing a well partial loss of return occurs. What can be done to reduce the pressure at the loss zone? A. Reduce the pump speed thus reducing annular friction pressure B. Keep the drill pipe pressure as close to the actual pressure that is supposed to be on the drill pipe gauge with no safety factor C. Used the exact mud density to kill the well with no additional weight as a safety factor D. All of the above Intertek Consulting & Training Unpublished work. All rights reserved. Page 37

15. It is decided to use the volumetric procedure. That is, bleed enough mud to keep the drill pipe pressure constant at 450 psi, (SIDPP = 350 psi plus 100 psi safety margin). What would the pressure in the gas bubble do as the gas rises? A. Increase B. Decrease C. Remain approximately the same 16. What would happen to bottom hole pressure? A. Increase B. Decrease C. Remain approximately the same 17. What would happen to the SICP? A. Increase B. Decrease C. Remain approximately the same 18. What would happen to pressure at the casing seat with the bubble below the casing seat? A. Increase B. Decrease C. Remain approximately the same 19. What would happen to pressure at the casing seat as the bubble is passing the casing seat (some of the influx is in the casing and some is still in the open hole)? A. Increase B. Decrease C. Remain the same 20. What would happen to pressure at the casing seat while the bubble is above the casing seat? A. Increase B. Decrease C. Remain approximately the same Intertek Consulting & Training Unpublished work. All rights reserved. Page 38

21. Which of the following statements are good operating practices in top hole (surface hole) that have a risk of gas bearing formations. (TWO ANSWERS) A. Use a high density mud (minimum of 15 ppg) to create a maximum overbalance B. Pump out of the hole on trips C. Control drill D. Regularly pump a fresh water pill to clean cuttings from the hole E. Maintain a high rate of penetration to ensure mud viscosity level is as high as possible 22. During top hole drilling from a jack-up rig the well suddenly starts to flow due to a shallow gas kick. What would be the safest actions to take for the rig and personnel? (TWO ANSWERS) A. Activate the blind/shear rams to shut in the well B. Activate the diverter system and remove all non-essential personnel from the rig floor and hazardous areas C. Shut in the well and prepare for conventional kill operations immediately D. Start pumping fluid into the well at the highest possible rate E. First line up the flow to the mud/gas separator, activate the diverter system, and then remove personnel from the rig floor 23. The main purpose of the diverter system is to: A. Shut in the well B. Divert shallow gas away from the rig C. To prevent gas from entering the wellbore 24. Kicks taken while drilling shallow formations should be: A. Closed in with the annular preventer B. Closed in with the rams C. Ignored because the pressure is minimal D. Diverted 25. The pressure build up due to the rising of gas which cannot expand could be called the second build up. The first build up occurs in 5 to 10 minutes after the well is closed in and sometimes takes 30 minutes. What causes the first build up? A. Gas migration B. Friction losses C. Permeability D. Type of influx Intertek Consulting & Training Unpublished work. All rights reserved. Page 39

26. While drilling ahead a well kicks and is shut in. Drill pipe and casing pressures start to rise before stabilization and then both drop quite rapidly. What has probably happened? A. The drill pipe has parted B. The BHA has packed off C. A formation has broken down D. The pressure gauges need to be changed 27. While drilling, a gas kick is taken and the well shut in. The driller reported a 17 bbl pit gain. SIDPP = 525 psi; SICP = 0 psi The choke was opened and there was no flow from the annulus and the drill pipe pressure remained constant. What is the probable cause? A. The casing gauge is malfunctioning B. The drill string has twisted off C. The well is swabbed in D. The hole has packed off around the BHA E. The formation at the casing shoe has fractured 28. The reason the casing pressure is usually higher than the SIDPP is: A. The cuttings in the annulus are lighter therefore creating a lighter hydrostatic in the annulus B. The influx fluid is usually less dense than the existing mud weight C. The casing pressure is not necessarily higher, it depends on whether it is an offshore or land operation D. The only difference is the type of gauges used to measure pressures 29. Which of the following parameters primarily affect the value of the SICP when a well is shut in on a kick. (THREE ANSWERS) A. Pore pressure B. Bottom hole temperature C. Hole or annulus capacity D. Drill string capacity E. Kick volume F. Length of the choke line Intertek Consulting & Training Unpublished work. All rights reserved. Page 40

30. Fast drilling in large diameter holes may cause errors in shut in pressures. If a well is shut in on a kick, just after a period of fast drilling, would you expect the SICP to be: A. Higher than if drilling had been slow B. Lower than if drilling had been slow C. The same whether the annulus was clean or loaded with cuttings 31. When tripping out of a vertical well with a surface BOP stack, the well is shut in after a gas kick has been taken. The bit is 950 feet off bottom and the influx is estimated to fill the bottom 300 feet of the hole. The SICP is 450 psi. What will the most likely SIDPP be? A. The same as SICP B. Higher than SICP C. Lower than SICP because of the ECD D. Impossible to say if the exact location of the kick is not known Intertek Consulting & Training Unpublished work. All rights reserved. Page 41

32. Mud weight increase required to kill a kick should be based upon: A. SIDPP B. SICP C. OMW plus slow circulating rate pressure D. SICP minus the SIDPP 33. The correct gauge to use to calculate KWM is: A. The gauge on the choke and kill manifold B. The drill pipe pressure gauge on the driller s console C. The casing gauge on the driller s console D. The drill pipe pressure gauge on the remote choke panel E. The casing gauge on the remote choke panel 34. A flowing well is closed in. Which pressure gauge is used to determine formation pressure? A. BOP manifold gauge B. Choke console drill pipe pressure gauge C. Driller s console drill pipe pressure gauge D. Choke console casing pressure gauge 35. A kick has been taken in a horizontal well. Use the following data to calculate the mud weight required to kill this well: MW Length of horizontal section TVD at time of kick TVD at start of horizontal MD at start of horizontal SIDPP 230 psi SICP 240 psi 12.8 ppg 5990 feet 5820 feet 5790 feet 13,680 feet KWM = ppg Intertek Consulting & Training Unpublished work. All rights reserved. Page 42

36. A gas kick has been taken in a well with a large open hole section. After a short time the drill pipe becomes plugged by debris blocking the bit. Drill pipe pressure can not be read and pumping is impossible down the drill pipe. There is evidence of gas migration taking place. Which one of the following control procedures can be applied? A. Driller's Method B. Lubricate and Bleed C. Wait and Weight Method D. Volumetric method 37. A vertical well is shut in on a gas kick. The kill operation is delayed and the influx starts migrating. Both the drill pipe and casing pressures have increased by 100 psi as a result of migration. WELL DATA Well Depth Casing shoe depth MW DP/OH capacity DP/Csg capacity 10,000 feet 6000 feet 11.7 ppg.06 bbl/ft.065 bbl/ft KICK DATA SIDPP = 800 psi; SICP = 1000 psi; Kick Volume = 30 bbls Assume only drill pipe is in the well. How many bbls of mud should be bled from the well in order to arrive at the original BHP prior to gas migration? bbl Intertek Consulting & Training Unpublished work. All rights reserved. Page 43

38. Which of the following best describes the Volumetric Method of well control? A. Maintains a constant pressure in the influx as the influx migrates up the well B. Maintains a constant BHP as the influx migrates up the well C. Maintains a constant casing pressure as the influx migrates up the well D. Maintains a constant pressure at the casing shoe as the influx migrates up the well 39. A vertical well is shut in on a gas kick. The kill operation is delayed and the influx starts migrating. Both the drill pipe and casing pressures have increased by 100 psi as a result of migration. WELL DATA Well Depth Casing shoe depth MW DP/OH capacity DP/Csg capacity 12,000 feet 9000 feet 12.2 ppg.065 bbl/ft.070 bbl/ft KICK DATA SIDPP = 850 psi; SICP = 1100 psi; Kick Volume = 50 bbls Assume only drill pipe is in the well. How many bbls of mud should be bled from the well in order to arrive at the original BHP prior to gas migration? bbl 40. The well has been shut in on a swabbed in kick. The SIDPP and SICP both read 350 psi. The bit is 30 stands off bottom. Which of the following would be the safest course of action to take in order to bring the well back under primary well control? A. Calculate KWM using 350 psi and circulate the well out from that depth using the Wait and Weight Method B. Bring the well on choke while holding the casing pressure constant as the pump is brought up to the kill rate. Then circulate the influx out using the Driller's Method C. Strip back to bottom using proper stripping techniques then circulate the influx out using the Driller's Method Intertek Consulting & Training Unpublished work. All rights reserved. Page 44

41. Which one of the following actions taken while stripping into the hole will help maintain an acceptable bottom hole pressure? A. Pumping a volume into the well equal to the drill pipe closed end displacement at regular intervals B. Bleeding off the drill pipe displacement at regular intervals C. Pumping a volume of mud into the well equal to the drill pipe displacement at regular intervals D. Bleeding off the drill pipe closed end displacement of the pipe stripped in at regular intervals 42. When stripping pipe into the hole which valves should be installed? A. Full opening safety valve in closed position B. Full opening safety valve in open position C. Inside BOP with Full opening safety valve in open position D. Inside BOP with Full opening safety valve in closed position Intertek Consulting & Training Unpublished work. All rights reserved. Page 45

43. A well is closed in on a 30 bbl gas kick while drilling 8 ½ hole at 11,000 feet TVD with 5, 19.5lb/ft drill pipe and 750 feet of 6 ½ drill collars. Annular Capacities: 5 DP in 8 ½ Hole.0459 bbl/ft 6 ½ DC in 8 ½ hole.0292 bbl/ft The mud weight is 12.3 ppg and the SIDPP is 350 psi. Assuming a gas gradient of.115 psi/ft. what will the casing gauge read? A. 480 psi B. 650 psi C. 975 psi D. 837 psi Questions 44 through 48 are based on the following information: A deviated hole has a MD of 12320 feet and a TVD of 10,492 feet. 9 5/8 casing is set at a measured depth of 9750 feet and 9200 feet TVD. 11.4 ppg mud is in use when the well kicks and is closed in. SIDPP SICP Pit Gain Fracture Mud Weight DP Capacity Casing Capacity Slow Circulating Rate Pressure 750 psi 1150 psi 15 bbl 14.4 ppg.01776 bbl/ft.0732 bbl/ft 850 psi 44. The maximum allowable annular surface pressure is rounded off to: A. 1370 psi B. 1480 psi C. 1435 psi D. 1415 psi 45. The kill weight mud required to balance the formation pressure is: A. 13.1 ppg B. 12.6 ppg C. 12.8 ppg D. 12.2 ppg Intertek Consulting & Training Unpublished work. All rights reserved. Page 46

46. What drilling mud weight would give a safety margin of 100 psi after the well was killed? A. 13.4 ppg B. 13.0 ppg C. 12.4 ppg D. 11.8 ppg 47. The Initial Circulating Pressure is: A. 1400 psi B. 1600 psi C. 1900 psi 48. The Final Circulating Pressure is: A. 850 psi B. 955 psi C. 920 psi D. 1050 psi 49. On a surface stack, what would happen when bringing the pumps up to the kill speed if the casing pressure was allowed to fall below the SICP? A. Formation would probably break down B. More influx would be let into the wellbore C. It would have no affect on anything 50. A kicking well has been shut in. SIDPP = 0 psi and there is a float in the drill string. To establish the SIDPP what action should be taken? A. Pump very slowly into the drill pipe with the well shut in. When the drill pipe pressure gauge fluctuates, the float has opened. This pressure is the SIDPP. B. Bring the pump up to the kill rate holding the casing pressure constant by opening the choke. The pressure shown when the pump is at the kill rate is the SIDPP. C. Pump at the kill rate into the drill string with the well shut in. When casing pressure starts to rise, read the pump pressure. This is the SIDPP. D. Shearing the pipe and reading the SIDPP directly off of the casing pressure gauge. Intertek Consulting & Training Unpublished work. All rights reserved. Page 47

51. Calculate the slow circulating rate pressure. The initial circulating pressure (ICP) is determined by bringing the pump rate to a pre-determined 30 spm by holding the SICP constant. The shut in drill pipe pressure SIDPP is 220psi. At 30 spm the ICP is 1060 psi.. A. 700 psi B. 770 psi C. 800 psi D. 840 psi 52. To find the initial circulating pressure on a surface BOP stack when the slow pump rate circulating pressure is not known and a kick has been taken: A. Circulate at the desired SPM to circulate out the kick, but hold 200 psi back pressure on the drill pipe side with the choke. B. Add 400 psi to the casing pressure and bring the pump up to the selected kill rate while using the choke to maintain an additional 400 psi on the casing. C. Bring the pump up to the kill rate while holding the casing pressure constant at the SICP by choke manipulation. After the hydraulic delay, the pressure shown on the drill pipe gauge is the initial circulating pressure. D. Add 1000 psi to the SIDPP and circulate out the kick. 53. While killing the well, as the pump speed is increased, what should happen to the casing pressure in order to keep BHP constant? A. Casing pressure should be held steady during a SPM change B. Casing pressure should be allowed to rise during a SPM change C. Casing pressure should be allowed to fall during a SPM change 54. A saltwater kick is circulated out using the Driller's Method. The drill string consists of drill collars plus drill pipe and a surface BOP stack is in use. When will the surface casing pressure be at its maximum value? A. When KWM enters the drill pipe B. When the kick has been circulated to the surface C. Only when the kick reaches the casing shoe D. Just after KWM reaches the bit E. Immediately after the well has been shut in and stabililzed Intertek Consulting & Training Unpublished work. All rights reserved. Page 48

55. The following slow circulating rate pressures (SCRP) were recorded. Which one does not seem to be correct? A. 30 spm @ 100 psi B. 40 spm @ 180 psi C. 50 spm @ 400 psi 56. A hydraulic delay exists between the time the choke is adjusted to the time the drill pipe pressure reacts. This hydraulic delay is: A. Equal to the speed of sound B. About 1 second per 300 meters (1000 feet) of distance traveled. C. About equal to 20 seconds D. This is a myth no hydraulic delay exists 57. WELL DATA Hole Size = 12 ¼ ; DP = 5 OD; DC = 8 X 3 (215 feet); DC/OH capacity =.0836 bbl/ft; DP/OH capacity =.1215 bbl/ft While drilling at 12,000 feet a gas kick is taken and the well shut in. The influx volume is measured as 35 bbl. Calculate the length of the influx assuming it is on bottom and does not migrate. feet Intertek Consulting & Training Unpublished work. All rights reserved. Page 49

58. While tripping out of the hole from 12,000 feet TVD the hole does not take the proper amount of fill. With the bit at 9000 feet TVD the well flows and is shut in with 215 psi SICP. A float is in the drill string. Drill collar length is 1200 feet and the average length of each stand is 93 feet. Assume the gas is on bottom and does not migrate. Drill pipe capacity Drill pipe displacement Open hole capacity DC/Open hole capacity DP/Open hole capacity Pit gain Gas gradient MW.01776 bbl/ft.0076 bbl/ft.0702 bbl/ft.0291 bbl/ft.046 bbl/ft 30 bbl.12 psi/ft 12.0 ppg 58a. How much volume is required to fill the drill pipe after stripping one stand into the hole? bbl 58b. Calculate the height of the influx feet 58c. Calculate the volume displaced per stand of drill pipe stripped into the hole bbl 58d. After stripping to bottom, what is the height of the influx across the BHA feet 58e. Calculate the SICP once the bit is back on bottom psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 50

59. WELL DATA FOR QUESTION Well Depth 12,000 feet DC length 1100 feet 9 5/8 Csg Shoe 8000 feet DC capacity.00768 bbl/ft 8 ½ OH capacity.0702 bbl/ft DC displacement.033 bbl/ft MW 12 ppg (.624 psi/ft) DP capacity.01776 bbl/ft DP displacement.0076 bbl/ft DC/OH capacity.0291 bbl/ft DP/OH capacity.0459 bbl/ft DP/Csg capacity.0515 bbl/ft After pulling 33 stands the driller checks the hole fill. The well has not taken the correct amount of mud. A flow check is made and the well is flowing. Bit depth SICP Influx volume Influx gradient (Gi) 9000 feet 200 psi 30 bbl.156 psi/ft Assume that the influx occurred from the bottom of the hole and that no gas migration occurs. 59a. Calculate the volume to bleed off per 98 feet of drill pipe stripped back into the hole. bbl 59b. What will be the effect on bottom hole pressure of bleeding off too much mud? Increase Decrease Stay the same 59c. How would casing pressure most likely react as the drill string is stripped into the influx? Increase Decrease Stay the same Intertek Consulting & Training Unpublished work. All rights reserved. Page 51

60. Problems that occur during a killing operation may affect the parameters you are monitoring at the surface (drill pipe pressure and casing pressure). For each of the following problems state the immediate effect on each of the parameters listed. For an increase use this symbol For a decrease use this symbol For no change use this symbol Problem Drill Pipe Pressure Casing Pressure Bottom Hole Pressure A. Choke washout B. Hole in string C. Nozzle blowout D. Choke plugging E. Nozzle plugging Intertek Consulting & Training Unpublished work. All rights reserved. Page 52

61. During the well kill operation, slowly but regularly you have to reduce the choke size because the drill pipe and casing pressures keep dropping with constant pump strokes. What is the likely cause of this? A. A bit nozzle is washing out B. The choke is washing out C. You have a washed out pump swab 62. Which of the following parameters can be affected by a string washout during a well killing operation (TWO ANSWERS). A. Bottom hole pressure B. Kick tolerance C. Formation fracture pressure D. Slow circulating pressure 63. The choke has to be closed gradually due to a string washout. What effect does the gradual closing of the choke have on bottom hole pressure? A. Decrease B. Increase C. Stay the same 64. How is a choke washout recognized? A. Rapid rise in casing pressure with no change in the drill pipe pressure B. Increase in drill pipe pressure with no change in casing pressure C. Continually having to open the choke to maintain drill pipe and casing pressures D. Continually having to close the choke to maintain drill pipe pressure 65. A kick is being circulated from the well using the Driller's Method. Pumping pressure has been established as 1000 psi @ 30 SPM. During the operation pressure suddenly increases to 1350 psi. You are reasonably certain that a nozzle has plugged. What should you do? A. Reduce the pump pressure to 1000 psi by adjusting the choke B. Shut the well in and re-establish the pumping pressure C. Hold casing pressure constant at the value recorded just before the nozzle plugged D. A & B are acceptable courses of action Intertek Consulting & Training Unpublished work. All rights reserved. Page 53

66. A well is being killed using the Driller's Method. During the first circulation the drill pipe pressure is kept constant at 670 psi and the pump speed @ 30 SPM. Halfway through the first circulation the operator on the choke observes a sudden increase in drill pipe pressure. There is no significant change in choke pressure and the pump speed is still 30 SPM. What could have happened? (THREE ANSWERS) A The bit nozzles have partially plugged B. The choke has partially plugged C. The kick is about to enter the choke D. A partial blockage in the kelly hose E. Pressure has built up in the mud/gas separator F. A partial blockage in the drill string has occurred 67. During a well killing operation using the Driller's Method, the choke pressure suddenly increases by 150 psi. Shortly thereafter the operator observes the same pressure increase on the drill pipe pressure gauge. What is the most likely cause of this pressure increase? A. A second influx has entered the well B. A restriction in the kelly hose C. A plugged nozzle in the bit D. The choke is partially plugged E. A washout in the drill string 68. What would be the correct action to take for the problem in question #67 A. Reduce the pump rate to reduce the pressure by 150 psi B. Open the choke a little until the drill pipe pressure returns to the calculated value C. No action required as this pressure increase has no effect on bottom hole pressure D. Stop the kill operation, remove the restriction in the kelly hose or change over to a spare kelly hose 69. While displacing the drill pipe with Kill Weight Mud a sudden loss in drill pipe pressure occurs, no change in the choke pressure is seen. The driller continued to pump at the same rate while the supervisor adjusted the choke to follow the drill pipe pressure graph as originally planned. What happens to BHP as a result of this? A. BHP increases then decreases B. BHP remains unchanged C. BHP decreases D. BHP decrease then increases E. BHP increases with the choke adjustment Intertek Consulting & Training Unpublished work. All rights reserved. Page 54

70. Which of the following would be applicable, if the pressures did not respond to opening the choke and the pumps were shut down and the well secured? A. Bit nozzle plugged B. Bit nozzle washout C. Drill string washout D. Pump failure E. Plugged choke F. Choke washed out 71. During a kill operation the choke operator notices the drill pipe pressure rises sharply though the casing pressure remains steady. He reacts by opening up the choke to maintain correct pumping pressure. This situation continues with increasing regularity. The choke operator notices that during this operation the choke has been adjusted from ½ to ¾ open. What is the most likely cause of this? A. Choke plugging B. Choke washing out C. Pipe washed out D. Bit nozzle plugging 72. In the above question, what effect has the gradual opening of the choke have on bottom hole pressure? A. BHP has decreased B. BHP has increased C. BHP has remain unchanged 73. Lost circulation during a well control operation is usually detected by: A. Monitoring the return flow with a flowshow B. Monitoring the mud volume in the pits C. Monitoring the pump speed D. Monitoring the weight indicator Intertek Consulting & Training Unpublished work. All rights reserved. Page 55

74. While circulating out a kick the choke operator has been continually closing the choke in order to maintain the correct circulating drill pipe pressure. The mud logger has reported that both drill pipe and casing pressures have been increasing. NOTE: The choke operator s gauges operate from different sensor than the mud logger. A check of the gauges on the standpipe and choke manifold confirm the mud logger s report. What is the most likely explanation? A. The choke is washing out B. The choke operator s gauges are malfunctioning C. The choke is plugging D. The mud logger s gauges are malfunctioning 75. A kick has been taken and it is known that a potential lost circulation zone exists in the open hole. Select TWO CORRECT ACTIONS which can be taken to minimize pressure in the annulus during the kill operation. A. Maintain extra back pressure on the choke for safety B. Use the Wait and Weight Method C. Choose a lower circulating rate D. Choose a higher circulating rate 76. Does a kick always occur in the event of total loss of circulation? A. Yes, losses always occur above any potential kick zone B. No, it depends on the drill string weight reduction noted on the weight indicator C. No, it depends on the mud level in the annulus and the formation pressure 77. If total losses occur while drilling with water based mud what would you do? A. Continue drilling blind B. Stop drilling and fill the annulus with water C. Stop drilling, shut in the well and see what happens 78. While circulating out a kick the mud pump fails. What is the first thing to do? A. Shut the well in B. Fix the pump as soon as possible C. Change over to Pump #2 D. Divert the well Intertek Consulting & Training Unpublished work. All rights reserved. Page 56

79. If the drill string washed out during a kill operation, providing no action was taken, which of the following would remain constant? (TWO ANSWERS) A. Bottom hole pressure B. Casing pressure C. Slow circulating pressure D. Drill pipe pressure 80. Which THREE of the following are proper practices for drilling an anticipated H 2 S environment? A. Use S-135 drill pipe B. Use X-95 drill pipe C. Use H 2 S scavenger D. Use a high ph mud to neutralize the hydrogen sulfide E. Use a low ph mud to neutralize the hydrogen sulfide F. Always reverse out prior to round trips 81. How would you determine the Initial Circulating Pressure if no slow pump rate pressure were available? Assume the rig is on land, a kick has been taken and the well is shut in. A. Add 300 psi to the casing pressure and bring the pump up to the kill speed while using the choke to keep casing pressure at (SICP + 300 psi) B. Bring the pump up to the kill rate while keeping casing pressure constant by choke manipulation C. Circulate at the kill rate holding 200 psi back pressure on the drill pipe side with the choke 82. During a kill operation a pump swab starts leaking. The choke operator knows nothing about the leak and is maintaining the standpipe pressure in accordance with the pressure schedule on the kill sheet. What will be the affect on BHP? A. BHP stays constant B. BHP decreases C. BHP increases Intertek Consulting & Training Unpublished work. All rights reserved. Page 57

KILL SHEET EXERCISES Complete a SURFACE IWCF KILL SHEET using the data given below and answer the questions on the page following the data. Well Data Hole ID 12 ¼ MD 10,975 feet TVD 10,550 feet Csg Set @ 6250 feet; 12.515 ID Internal Capacities DP.0174 bbl/ft HW.0088 bbl/ft (465 feet in length) DC.0087 bbl/ft (900 feet in length) Volume from mud pumps to rig floor: 7.2 bbl Annular Capacities DC in Open Hole DP & HW in open hole DP & HW in cased hole.0836 bbl/ft.1215 bbl/ft.1279 bbl/ft Mud Pumps Output:.11 bbl/stk Slow Circulating Pump Data Pump #1 30 SPM @ 620 psi 40 SPM @ 1100 psi Pump #2 30 SPM @ 610 psi 40 SPM @ 1080 psi Active Surface Volume 525 bbl Formation Strength Test Data Fracture Gradient @ Casing Shoe (6250 feet) Kick Data SIDPP 525 psi SICP 750 psi Pit Gain 18 bbl MW at the time of the kick 11.5 ppg.75 psi/ft NOTE: The well will be killed with pump #2 at 40 SPM using the Wait and Weight Method Intertek Consulting & Training Unpublished work. All rights reserved. Page 58

1. Calculate the MAASP using the mud weight of 11.5 ppg psi 2. What mud weight is required to balance formation pressure (round off to 1 decimal)? ppg 3. Calculate the Initial Circulating Pressure (ICP). psi 4. Calculate the Final Circulating Pressure (FCP). psi 5. Calculate the pump strokes from surface to bit. strokes 6. Calculate the pump strokes from the mud pump to the bit. strokes 7. Calculate the time in minutes from surface to the bit. minutes 8. Calculate in minutes to pump from the mud pump to the bit. minutes 9. Calculate the strokes required to pump from the bit to the shoe. strokes 10. How many minutes are required to circulate the total well system volume at 40 SPM? minutes 11. Calculate the MAASP with KWM in the system. psi 12. What is the pressure loss per 100 strokes as the KWM is pumped from surface to the bit? psi/100 stks Intertek Consulting & Training Unpublished work. All rights reserved. Page 59

1309 11.5 14.97 12.5 0.10 931 9 5/8 7250 7250 8 1/2 12950 30 620 620 12575 40 1080 1080 11585 465.0177.0088 205.05 4.09 900.0087 7.83 216.97 2170 72.3 900 4800.0291.0459 26.19 220.32 246.51 2465 82.1 7250.0489 354.52 601.03 3545 6010 118.1 200.3 818 8180 525 5250 1343 13430 272.6 Intertek Consulting & Training Unpublished work. All rights reserved. Page 60

650 850 22 12.5 650 12575 13.5 620 650 1270 13.5 620 12.5 1270 670 600 600 2170 27.6 670 1270 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2170 1270 1243 1215 1188 1160 1132 1105 1077 1050 1022 994 967 939 912 884 856 829 801 774 746 718 691 670 1200 1100 1000 900 800 700 600 500 400 300 200 100 0 500 1000 1500 2000 2170 Intertek Consulting & Training Unpublished work. All rights reserved. Page 61

Using the kill sheet on the previous pages answer the following questions. The well be killed using the Wait and Weight Method with a pump rate of 30 spm. 1. What mud weight is required to balance the formation pressure? ppg (round off to 1 decimal) 2. How many strokes will be required to pump from surface to bit? stks 3. How many strokes are required to pump from the bit to the casing shoe? stks 4. What is the MAASP at the time the well is shut in. psi 5. What is the total annular volume? bbl 6. What is the MAASP once kill mud has been circulated around the well? psi 7. What is the calculated Final Circulating Pressure? psi 8. What is the calculated Initial Circulating Pressure? psi 9. Approximately how much time will it take to completely displace the well with KWM? minutes Intertek Consulting & Training Unpublished work. All rights reserved. Page 62

GAUGE EXERCISES Using the completed kill sheet, circle the first action that you would take based on the situations presented. Take note of all parameters before making your decision. Pump strokes Pump rate Drill pipe pressure Casing pressure 650 850 Intertek Consulting & Training Unpublished work. All rights reserved. Page 63

1. After 2 minutes this is the situation. What should you do? A. Keep opening the choke slowly B. Keep closing the choke slowly C. Increase the pump rate D. Decrease the pump rate E. Continue, everything is OK Intertek Consulting & Training Unpublished work. All rights reserved. Page 64

2. Everything is OK.or is it? Should you..? A. Continue, everything is OK B. Open the choke a little C. Close the choke a little D. Adjust the pump rate E. Stop pumping and close the choke Intertek Consulting & Training Unpublished work. All rights reserved. Page 65

3. After about 17 minutes this is what you observe. What action should you take? A. Open the choke a little B. Close the choke a little C. Increase the pump rate D. Decrease the pump rate E. Continue, everything is OK Intertek Consulting & Training Unpublished work. All rights reserved. Page 66

4. After 850 strokes this is the situation. What should you do? A. Increase the pump speed B. Decrease the pump speed C. Close the choke slowly D. Open the choke slowly E. Continue, everything is OK Intertek Consulting & Training Unpublished work. All rights reserved. Page 67

5. Everything seems to be going smoothly until you notice a sudden rise in both pressures. What has caused this problem? A. The choke is plugging B. The choke is washing out C. There is a washout in the string D. A bit nozzle has plugged E. A bit nozzle has washed out The problem in the case above has been corrected Intertek Consulting & Training Unpublished work. All rights reserved. Page 68

6. Based on what you see at right, what action should be taken? A. Increase the pump speed B. Decrease the pump speed C. Close the choke slowly D. Open the choke slowly E. Continue, everything is OK Intertek Consulting & Training Unpublished work. All rights reserved. Page 69

7. This is the situation after 3000 strokes. What should you do? A. Increase the pump speed B. Decrease the pump speed C. Close the choke slowly D. Open the choke slowly E. Continue, everything is OK Intertek Consulting & Training Unpublished work. All rights reserved. Page 70

8. The pit volume is increasing and casing pressure is rising. Should you.. A. Increase the pump speed B. Decrease the pump speed C. Close the choke slowly D. Open the choke slowly E. Continue, everything is OK Intertek Consulting & Training Unpublished work. All rights reserved. Page 71

9. This is the situation after 8000 strokes. The pit level is now dropping. You could have loss of circulation. What are you going to do? A. Increase the pump speed B. Decrease the pump speed C. Close the choke slowly D. Open the choke slowly E. Continue, everything is OK Intertek Consulting & Training Unpublished work. All rights reserved. Page 72

10. The choke is now fully open but it is difficult to determine whether there is any pressure on the casing. What should you do? A. Increase the pump speed B. Decrease the pump speed C. Close the choke a little D. Stop pumping and close in the well E. Continue pumping at 30 spm 670 Intertek Consulting & Training Unpublished work. All rights reserved. Page 73

DAY 3 1. Company policy states that an accumulator must provide sufficient volume to close, open and close again, all rams and the annular. Using the information below, calculate the required volume. ITEM OPENING VOL. CLOSING VOL> Annular 27 gal 29 gal Rams 13 gal. ea. 15 gal. ea. PIPE Required Volume = gal BLIND PIPE 2. According to API RP-53 what is the maximum allowable closing time for annular preventers 18 ¾ and above? A. 30 seconds B. 60 seconds C. 2 minutes D. 45 seconds Intertek Consulting & Training Unpublished work. All rights reserved. Page 74

3. Indicate the activities that may take place with the BOP illustrated below. A. Can the spool be repaired? with no drill pipe in the holes: and the well shut in under pressure? Yes / No B. Can the pipe rams be changed to blind ram? With Drill pipe in the hole: and the well shut in under pressure? Yes / No C. Can the well be killed with the Wait and Weight method? The well is shut in with drill pipe in the hole. Yes / No D. Can the side outlets on the spool be repaired? Drill pipe in the hole and the well shut in under pressure. Yes / No Annular Blind Ram Choke Line Kill Line Pipe Ram Intertek Consulting & Training Unpublished work. All rights reserved. Page 75

4. Indicate the activities that may be carried out with the BOP stack illustrated below. A. Can the spool be repaired with no drill pipe in the hole: and the well shut in under pressure? Yes / No B. Can the pipe rams be changed to blind rams with drill pipe in the hole: and the well is under pressure? Yes / No C. Can this well be killed with the Wait and Weight Method? The well is shut in with drill pipe in the hole. Yes / No D. Can the side outlets on the spool be repaired? With drill pipe in the hole and the well shut In under pressure? Yes / No Annular Blind Ram Pipe Ram Kill Line Choke Line Intertek Consulting & Training Unpublished work. All rights reserved. Page 76

5. According to API RP-53, what is the recommended reservoir capacity for a BOP closing unit. A. 2 times the useable accumulator volume B. 2 times the accumulator volume C. 5 times the total accumulator volume 6. Identify the components that are controlled by manifold pressure. (THREE ANSWERS) A. Pipe rams B. Blind rams C. Annular D. HCR valves 7. Which TWO pressure readings would decrease if you operated the pipe rams? A. Manifold pressure B. Annular pressure C. Accumulator pressure D. Precharge pressure 8. Which of the two tools below would you use if you wanted to test the BOP stack and the upper casing seals? A. Plug type tester B. Cup type tester 9. Identify which type of valve should be used for the operations listed. 1. A full opening safety valve (TIW) 2. A stab-in non-return valve (Gray Valve ) Place a 1 or 2 in the blanks provided A. Stabbing onto a strong flow up the drill string B. Is closed manually with a tool C. May develop a leak around the key D. May be pumped open E. May not be run in the hole in the closed position F. Wireline may be run through it Intertek Consulting & Training Unpublished work. All rights reserved. Page 77

10. Identify the situation in which a BOP pressure test is recommended as per API RP-53. (TWO ANSWERS) A. After circulating out a gas kick B. When two months have elapsed since the last test C. After changing out BOP components D. After setting a casing string 11. According to API RP-53, how often does API recommend BOP pressure tests? A. Every 7 days B. Every 14 days C. Every 21 days D. Every 28 days 12. You have only one full opening drill string safety valve with an NC-50 lower connection on your rig but the drill string consists of 5 HWDP and 8 collars. Which of the following cross-overs would you have to have on the floor in case of a kick while tripping? A. 6 5/8 Reg Box X 7 5/8 Reg Pin B. NC-50 Pin X 6 5/8 Reg Pin C. NC-50 Box X 7 5/8 Reg Pin D. NC-50 Box X 6 5/8 Reg Pin 13. Mark the following with advantage or a disadvantage when a drill string float is used. A. Surge pressure B. Reverse circulation C. Flowback through the drill pipe D. Reading SIDPP Intertek Consulting & Training Unpublished work. All rights reserved. Page 78

14. Identify from the sketch below, which valves should be opened to circulate down the drill string with the mud pump through the remote adjustable choke and the mud/gas separator. The well is closed in with the annular. Circle the correct answers.. A. 2,4,5,6,7,8,9,11,12,16 B. 1,3,7,8,9,11,12,15 C. 2,3,7,8,9,11,12,16 3 4 Non-return Valve Ann Remote Choke 11 12 Mud Pump Cmt Pump 2 1 B/S 5 6 PR PR 8 7 9 10 13 14 Man Choke 15 16 17 To mud pits To separator To ventline Intertek Consulting & Training Unpublished work. All rights reserved. Page 79

In each of the following problems (15 through 17) below write the letter from the list below that best describes the reason for the pressure gauge readings. 15. 2900 psi increasing 1500 psi steady 900 psi steady Accumulator Pressure Manifold Pressure Annular Pressure Problem NOTE: A function test has just been performed and the pump is still running Normal Readings: Annular Manifold Accum. 900 psi 1500 psi 3000 psi A. Everything is OK B. Malfunctioning pressure regulator ( valve) C. Malfunctioning hydro-electric pressure switch D. Leak in hydraulic circuit E. Precharge pressure is too low Intertek Consulting & Training Unpublished work. All rights reserved. Page 80

16. 2700 psi decreasing 1800 psi increasing 900 psi steady Accumulator Pressure Manifold Pressure Annular Pressure Problem NOTE: The pump has just kicked in. Normal Readings: Annular Manifold Accum. 900 psi 1500 psi 3000 psi A. Everything is OK B. Malfunctioning pressure regulator ( valve) C. Malfunctioning hydro-electric pressure switch D. Leak in hydraulic circuit E. Precharge pressure is too low Intertek Consulting & Training Unpublished work. All rights reserved. Page 81

17. 2400 psi decreasing 1300 psi decreasing 900 psi steady Accumulator Pressure Manifold Pressure Annular Pressure Problem NOTE: No function test has been performed. The pump is running. Normal Readings: Annular Manifold Accum. 900 psi 1500 psi 3000 psi A. Everything is OK B. Malfunctioning pressure regulator ( valve) C. Malfunctioning hydro-electric pressure switch D. Leak in hydraulic circuit E. Precharge pressure is too low Intertek Consulting & Training Unpublished work. All rights reserved. Page 82

18. 3200 psi increasing 1500 psi steady 900 psi steady Accumulator Pressure Manifold Pressure Annular Pressure Problem NOTE: The pump is running. Normal Readings: Annular Manifold Accum. 900 psi 1500 psi 3000 psi A. Everything is OK B. Malfunctioning pressure regulator ( valve) C. Malfunctioning hydro-electric pressure switch D. Leak in hydraulic circuit E. Precharge pressure is too low Intertek Consulting & Training Unpublished work. All rights reserved. Page 83

19. The following statements relate to the driller s remote control BOP control panel located on the rig floor. Indicate if the statements are TRUE or FALSE. A. If you operate a function without operating the master control valve that function will not work. TRUE FALSE B. The master control valve on an air operated panel allows air pressure to go to each function in preparation for operating the function. TRUE FALSE C. The master control valve must be held depressed while BOP functions are operated. TRUE FALSE D. The master control valve must be depressed for five seconds then released before operating a BOP function. TRUE FALSE 20. A BOP operating unit has 8 bottles, each with a capacity of 10 gallons. Maximum pressure is 3000 psi and the precharge pressure is 1000 psi. A. What is the total useable fluid volume when the minimum BOP operating pressure is 1200 psi? gallons B. What is the total useable fluid volume when the minimum BOP operating pressure is1500 psi? gallons 21. Which of the following statements is TRUE concerning ram packing elements? A. Motion reversal of pipe increases the wear on the seals B. Closing pipe rams on the open hole may damage the elements C. The ram packer should normally be checked and if worn, changed whenever the bonnet is opened D. All of the above 22. The kill line should enter a stack so that. A. The well can be circulated if the blind rams are closed B. The well can be circulated if the pipe rams are being used C. Both of the above Intertek Consulting & Training Unpublished work. All rights reserved. Page 84

Use the diagrams below to answer the following questions: 1 2 3 4 Air Accumulator. Manifold Annular 23. On a 3000 psi accumulator system what are the normal operating pressures seen on the following gauges. Use the list below and right to fill in the blanks. A. Gauge #1 psi 120 psi B. Gauge #2 psi 900 psi C. Gauge #3 psi 1500 psi D. Gauge #4 psi 3000 psi 24. On which TWO gauges on the remote panel would you expect to see reduction in pressure when the annular preventer is closed? A. Gauge #1 B. Gauge #2 C. Gauge #3 D. Gauge #4 25. If Gauge #1 reads 0 psi, which of the following statements is TRUE? A. No stack function can be operated from the remote panel B. All stack functions can be operated from the remote panel C. Choke and kill line valves can still be operated from the remote panel D. The annular preventer can still be operated from the remote panel Intertek Consulting & Training Unpublished work. All rights reserved. Page 85

26. Mark an X in the box where the problem relates to the cause. Causes Problems 4-way valve on accumulator failed to shift Closing line to BOP blocked Leak in hydraulic lines to BOP or BOP itself Air pressure lost to panel Bulb has blown 1. Close light does not illuminate but pressure drops and later increases. 2. Light does not illuminate and pressure gauge does not drop. 3. Pressure gauge drops but does not rise back up. 4. Light illuminates but pressure gauge does not drop. Intertek Consulting & Training Unpublished work. All rights reserved. Page 86

27. Which one of the previous problems (1, 2, 3, or 4) did not stop the BOP from closing? A. 1 B. 2 C. 3 D. 4 28. Indicate the letters in the following blanks which correspond to the items in the illustration below: A. Closing chamber B. Opening chamber C. Wear plate D. Piston travel indicator E. Piston F. Packing element F E A B C Hydril GK Annular D Intertek Consulting & Training Unpublished work. All rights reserved. Page 87

29. Indicate the letters in the following blanks which correspond to the items in the illustration below: A. Closing chamber B. Opening chamber C. Packing unit D. Adapter ring E. Piston A B C D E Shaffer Spherical Annular Intertek Consulting & Training Unpublished work. All rights reserved. Page 88

30. Indicate the letters in the following blanks that correspond to the items in the illustration: A. Packing element B. Donut C. Operating piston D. Opening chamber E. Closing chamber F. Pusher plate G. Packer insert H. Vent/Weephole H J B I A D C G K E K F Cameron Model D Annular Intertek Consulting & Training Unpublished work. All rights reserved. Page 89

31. Indicate the letters in the following blanks which correspond to the items listed in the illustration below? A. Packing element B. Opening chamber C. Opening chamber head D. Closing chamber E. Piston F. Secondary chamber I F H G A B C D E Hydril GL Annular Intertek Consulting & Training Unpublished work. All rights reserved. Page 90

32. Identify the ram preventer components. 12 2 1 1 2 8 7 9 11 6 10 4 3 5 11 9 Body Operating Cylinder Bonnet Operating Piston Lock Screw Ram Assembly Lock Screw Housing Intermediate Flange Ram Change Cylinder Bonnet Door Seal Intertek Consulting & Training Unpublished work. All rights reserved. Page 91

33. When using the Driller's Method of well control with pipe in the hole can you circulate if. A. The upper pipe rams are closed? YES NO B. The annular preventer is closed YES NO C. The lower pipe rams are closed YES NO Annular PIPE BLIND/SHEAR KILL LINE CHOKE LINE PIPE 34. From the diagram with the well shut in. A. Can you repair the side outlets with pipe in the hole YES NO B. Can you repair the outlets with no pipe in the hole? YES NO C. Is it possible to shut in on drill pipe in the hole and circulate through the drill pipe? YES NO Annular BLIND/SHEAR KILL LINE CHOKE LINE PIPE PIPE Intertek Consulting & Training Unpublished work. All rights reserved. Page 92

35. From the diagram with the well shut in.. A. With drill pipe in the hole can we repair the side outlets? YES NO B. With no drill pipe in the hole, can you shut in and repair the drilling spool? YES NO C. With drill pipe in the hole, can you circulate across the drilling spool? YES NO Annular BLIND/SHEAR PIPE KILL LINE CHOKE LINE Intertek Consulting & Training Unpublished work. All rights reserved. Page 93

36. Match the numbers to the following parts in the picture below. 6 2 4 5 3 1 7 Lower Ram Assembly Blade Packer Top Seal Upper Body Side Packers Upper Ram Assembly Intertek Consulting & Training Unpublished work. All rights reserved. Page 94

37. Using the remote panel we close the annular preventer. Which TWO gauges on the panel reduce in pressure? A. Air B. Annular C. Manifold D. Accumulator E. By-pass 38. When drilling, the 4-way valves on the BOP accumulator unit should be in which position? A. Open B. Closed C. Neutral D. Open or closed depending on the BOP stack function 39. While testing the BOP stack, it is noticed that well bore fluid is leaking past the weep hole. Which of the following best describes the proper action to be taken? A. Energize the plastic seal and repair the BOP at the next scheduled maintenance B. A primary seal is leaking. Immediately secure the well and renew the seal. C. The ram packer is leaking due to wear. Change the worn packer. D. Do nothing, the seal requires a slight leak for lubrication purposes. Intertek Consulting & Training Unpublished work. All rights reserved. Page 95

40. Using the diagram on the previous page, identify the following parts: Hydroelectric pressure switch Accumulator shut-off valve Accumulator pressure gauge Unit/remote switch Manifold by-pass valve (high / low) Triplex pump check valve 41. The characters 6 BX stamped on a flange represents the A. Serial number B. Pressure rating C. Type D. Size 42. What is meant by the closing ratio for a ram BOP? A. Ratio between closing and opening volume B. Ratio between closing and opening time C. Ratio of wellhead pressure to the pressure required to close the BOP 43. Accumulators are precharged with what type of gas? 44. The main function of the choke in the overall BOP system is A. To divert contaminant to the burning pit B. To hold back pressure while circulating out a kick C. To divert fluid to the mud pit D. To prevent the loss of mud resulting from gas expansion E. To perform a soft shut in Intertek Consulting & Training Unpublished work. All rights reserved. Page 97

45. Why should the side outlet below the test plug be kept in the open position while testing a surface BOP stack? A. To prevent potential damage to the casing and/or open hole B. To prevent extreme hook loading. C. To allow easy release of the plug 46. What is the normal precharge for the accumulator bottles on a 3000 psi accumulator? A. 1000 psi B. 3000 psi C. 1200 psi D. 200 psi D1 47. From the diagram, identify the dimensions that determine the build up of pressure in the mud/gas separator. (TWO ANSWERS) H3 A. Vent line height (H3) B. Separator height (H2) C. Mud seal height (H1) D. Inlet diameter (D2) E. Primary vent diameter (D1) D2 H2 H1 Intertek Consulting & Training Unpublished work. All rights reserved. Page 98

48. Calculate the pressure at which gas blow through would occur. The mud weight is 12.5 ppg. psi 15ft 6.5 ft Intertek Consulting & Training Unpublished work. All rights reserved. Page 99

49. Of the items shown at right, which one determines at what pressure the degasser will unload? A. D1 B. D2 C. H1 D. H3 E. H1 & H3 F. D2 & D1 & H3 D1 H3 D2 H2 H1 Intertek Consulting & Training Unpublished work. All rights reserved. Page 100

50. Based on the information given at right, what is the rated working pressure of the atmospheric degasser? psi 12 inches 188 feet D2 15 feet 12 feet Present MW is 11.8 ppg Intertek Consulting & Training Unpublished work. All rights reserved. Page 101

51. On a Cameron u type ram preventer, in which position does the 4-way valve have to be in to open the bonnet after backing off the bonnet bolts? A. Open B. Closed C. Neutral D. Either position will work 52. Which ram type preventer on a Cameron 13 5/8, 10,000 psi working pressure BOP stack is equipped with a thicker intermediate flange? A. Pipe rams B. Blind rams C. Shear rams D. Variable bore rams 53. What would be the effect of fitting a 7 1/16 X 5000 psi flange to a 10,000psi working pressure rated BOP stack? A. The stack rating would remain at 10,000 psi B. The stack rating would decrease to 5000 psi C. The stack rating would decrease to 7500 psi 54. What is the purpose of the master control valve on an air operated remote BOP panel? A. It activates the hydraulic fluid circuit at the panel B. It activates the air circuit at the panel C. It activates the electrical circuit for the open/close lights D. It adjusts the pipe ram closing pressure 55. Where are the proximity (activating) switches for the BOP remote panel lights situated? A. On the pressure gauge mounted on the remote control panel B. On the accumulator C. On the side of the BOP operating chambers D. On the remote control operating handles Intertek Consulting & Training Unpublished work. All rights reserved. Page 102

56. On which ram operation would you be most likely to use the manifold by-pass valve (high / low)? A. Using variable bore rams B. Using blind/shear rams C. When using 5 S-135 drill pipe D. When using 3 ½ G-105 drill pipe 57. According to API RP-53, what is the minimum pressure at which the charging pumps start up? A. When accumulator pressure has decreased to less than 50% of the operating pressure B. When accumulator pressure has decreased to less than 75% of the operating pressure C. When accumulator pressure has decreased to less than 90% of the operating pressure 58. Select THREE items of equipment that may warn of increasing formation pressure while drilling overbalanced. A. ROP recorder B. Pump stroke counter C. Gas detector D. Casing pressure gauge E. Mud temperature recorder F. Standpipe pressure gauge 59. Why are some choke manifolds equipped with a glycol or methanol injection system? A. To help prevent hydrate formation while circulating out a kick B. To help test fluid flow better C. To allow the use of all types of adjustable chokes D. To help prevent a hydraulic shock if gas suddenly arrives at the surface 60. A test cup for 9 5/8 43.5 lb/ft casing is used to test a BOP stack to a pressure of 10,000 psi using 5 drill pipe. The area of the test cup subject to pressure is 42.4 square inches. What is the minimum grade of drill pipe that could be used and will withstand the stress of testing? A. Grade E drill pipe having a tensile strength of 311,200 lbs B. Grade X-96 drill pipe having a tensile strength of 394,200 lbs C. Grade S drill pipe having a tensile strength of 560,100 lbs D. Grade G drill pipe having a tensile strength of 443,096 lbs Intertek Consulting & Training Unpublished work. All rights reserved. Page 103

61. What is meant by the useable fluid volume of an accumulator? A. The total volume of hydraulic fluid that can be stored in the accumulator tank B. The total volume of fluid that can be stored in the accumulator bottles C. The total volume of fluid that is recoverable from the bottles between the accumulator operating pressure and the minimum operating pressure D. The total volume of fluid that is recoverable from the bottles between the accumulator operating pressure and the precharge pressure E. The total volume of fluid that is recoverable from the bottles between the accumulator operating pressure and 750 psi above precharge pressure 62. What are the main components of a diverter system? (TWO ANSWERS) A. A low pressure annular preventer with a large internal diameter B. A vent line of sufficient length to allow gas to be safely vented from the separator C. A high pressure ram preventer with a large internal diameter D. A vent line with manually operated valves E. A vent line of sufficient diameter to permit safe venting and proper disposal of flow from the well 63. What should be considered for the BOP rated working pressure according to API RP-53? A. Maximum anticipated bottom hole pressure B. Maximum anticipated formation pressure C. Maximum anticipated surface pressure D. Maximum anticipated drilling mud hydrostatic pressure E. Maximum anticipated MAASP 64. What is the primary function of the weep hole (drain hole, vent hole) on a Ram BOP? (select ONE answer) A. To show that the ram body rubbers are working B. To show that the mud seal on the piston rod is leaking C. To show that the bonnet seals are leaking D. To show that the closing chamber pressure is excessive Intertek Consulting & Training Unpublished work. All rights reserved. Page 104

65. Identify the ONE ram locking device from the list below that does NOT allow for self-feeding of ram packers to allow for packer wear. A. Shaffer Ultralock B. Shaffer Poslock C. Hydril MPL Lock D. Cooper (Cameron) Wedgelock E. Koomey Autolock 66. From the list below, identify the ring gaskets that are pressure energized. (FOUR ANSWERS) A. Type RX B. Type BX C. Type AX D. Type R Oval E. Type R Octagonal F. Type CX 67. Which dimension from the list below is used to identify the Nominal Flange Size? A. Throughbore ID B. Flange OD C. Diameter of raised face D. OD of ring groove E. Bolt circle diameter Intertek Consulting & Training Unpublished work. All rights reserved. Page 105

68. Identify the following parts of this pipe ram block. Rubber Retaining Screw Block Holder Top Seal Retracting Screw C F D E B Shaffer Pipe Rams A Intertek Consulting & Training Unpublished work. All rights reserved. Page 106

69. Identify the following shear ram block components: Upper Holder Upper Ram Block Lower Holder Lower Ram Block Upper Rubber Lower Rubber Lower Shear Blade Retainer Screw Intertek Consulting & Training Unpublished work. All rights reserved. Page 107

70. The rig is now working for an operator who requires a different stack (13-5/8 x 15,000 psi). This operators policy is to provide sufficient usable hydraulic fluid to function all BOP components with a minimum pressure remaining to close against full rated BOP working pressure. The number of gallons to function all BOP components = 150 gallons for this stack. The BOP closing ratio is 10.6 to 1 Precharge pressure = 1,000 psi System pressure = 3,000 psi How many 10 gallon bottles (cylinders) are required to store those 150 gallons of hydraulic fluid? A. 30-10 gallon bottles B. 36-10 gallon bottles C. 41-10 gallon bottles D. 51-10 gallon bottles 71. All ram BOP s are designed to close (and hold closed) on full rated pressure with 1500 psi hydraulic operating pressure? A. True B. False 72. Ram type BOPs are designed to open in a situation where rated working pressure is contained below the rams and mud hydrostatic pressure to the flow line is above the rams; for instance in a stripping situation. A. True B. False Intertek Consulting & Training Unpublished work. All rights reserved. Page 108

73. Identify the following components from the illustration provided on the previous page: A Accumulator shut-off Valve (Bank Isolator valve) B Accumulator Bottles C Manifold Regulator (Pressure reducing and regulating valve) D Annular Regulator (Pressure reducing and regulating valve) E Air Filter F Air Lubricator G Electric Pressure Switch H Hydro-Pneumatic Pressure Switch I Three Position/Four-Way Control Valve J Manifold Regulator Override Valve (By-pass valve) K Electric Motor Starter L Check Valve for Air Operated Pump M Annular Preventer Pressure Gauge N Manifold Pressure Gauge O Accumulator Pressure Gauge P Check Valve for Triplex Pump Q Strainer for Air Operated Pump R Strainer for the Triplex Pump S Accumulator Pressure Relief Valve T Manifold Pressure Relief Valve U Unit /Remote switch V Pressure Transducers/Transmitters W Air Pumps Intertek Consulting & Training Unpublished work. All rights reserved. Page 110

74. The wait and weight method of well control is being used on a floating rig. After all the influx is out of the well, the drill pipe pressure increases to a level higher than the final circulating pressure even though the choke is wide open. What is the cause of the increase in pressure? A. An error was made in calculating the final circulating pressure B. If the casing pressure is not increasing then a bit nozzle is plugged C. Because of the U-tube effect, the choke line friction pressure is now showing up on the drill pipe pressure gauge D. Hydrates are forming in the drill string thus increasing drill pipe pressure 75. What can be done to reduce the problem in the previous question? (TWO ANSWERS) A. Reducing the pump rate will reduce choke line friction pressure which will reduce the amount of drill pipe pressure increase B. Open the kill line and allow the mud to return to the surface through both the choke and kill lines. This reduces choke line friction and will reduce the amount of drill pipe pressure increase C. Use the excess pressure as a safety factor which will further guarantee killing the well on the 1 st circulation D. The extra pressure is of no concern and will not hurt anything Use the following data to answer questions 76, 77 & 78. Assume the kill procedure to be conducted from a floating rig Vertical depth of the casing shoe MAASP leak-off value with 9.5 ppg mud Slow pump rate @ 30 spm through the riser Slow pump rate @ 30 spm through the choke line Drilling fluid density SIDPP SICP TVD at the time of the kick 6500 feet 1350 psi 800 psi 1050 psi 10.6 ppg 540 psi 850 psi 8900 feet 76. Calculate the required Initial Circulating Pressure A. 600 psi B. 790 psi C. 1340 psi D. 1590 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 111

77. Calculate the required Final Circulating Pressure when the density of the kill fluid is 11.8 ppg. A. 600 psi B. 891 psi C. 946 psi D. 1170 psi 78. Calculate the maximum allowable value on the annulus pressure gauge when establishing kill pump rate @ 30 spm at initiating kill operation. A. 696 psi to 728 psi B. 980 psi C. 1000 psi to 1066 psi A floating drilling rig is drilling below 30 inch conductor. Use the information to answer questions 79 & 80. Water depth TVD from flow line Air gap Sea water density Mud weight 1465 feet 2250 feet 80 feet 8.5 ppg 9.5 ppg 79. Calculate the reduction in BHP if the riser is disconnected at the wellhead housing on the seafloor. psi 80. Calculate the minimum drilling fluid density that will keep the well balanced with the riser disconnected. ppg Intertek Consulting & Training Unpublished work. All rights reserved. Page 112

A 17 ½ hole is being drilled below 30-inch conductor. Use the data below to answer questions 81 & 82. Water depth 650 feet Conductor set @ 1275 feet from rig floor Air gap 60 feet Sea water gradient.445 psi/ft 81. From a previous well drilled the formation fracture gradient beneath the sea bed is estimated to be.62 psi/ft. Calculate the theoretical maximum mud weight that can be used in a static (non-circulating) condition without exceeding the formation strength. ppg 82. Calculate the above in the dynamic (circulating) condition with an annular pressure loss of 10 psi. ppg 83. On a semi-submersible a kick is taken and the following data has been recorded after shut in pressures have stabilized. Well depth (RKB) Casing shoe (RKB) Formation fracture gradient Mud weight Water depth Water density Pressure loss through riser Pressure loss through choke line SIDPP SICP 17,327 feet MD/15,678TVD 15,245 feet MD/12,855 feet TVD.8 psi/ft 13.2 ppg 1080 feet 8.6 ppg 470 psi 670 psi 510 psi 800 psi Calculate the margin between the initial dynamic MAASP and the initial choke pressure if the instructions are to maintain a 100 psi overbalance over and above formation pressure at the start of the well killing operation. Assume a circulating rate of 30 spm. psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 113

84. On a semi-submersible a kick is taken while drilling and the following data has been collected. Well depth (RKB) Casing shoe (RKB) Formation fracture gradient Mud weight Water depth Water gradient Pressure loss through riser Pressure loss through choke line SIDPP SICP 16,557 feet MD/14,340 feet TVD 14,870 feet MD/12,855 feet TVD.845 psi/ft 14.9 ppg 930 feet.445 psi/ft 410 psi 655 psi 420 psi 575 psi Calculate the margin between the initial dynamic MAASP and the initial choke pressure at the start of the kill operation. Assume a circulating rate of 25 spm. psi 85. Use the following data to determine the shut in kill line pressure. MW in drill string, annulus and choke line = 10.8 ppg Choke line length = 1800 feet Well depth = 8000 feet TD/RKB Gradient of seawater in kill line =.445 psi/ft? 500 PSI 700 PSI A. 700 psi B. 500 psi C. 910 psi D. 950 psi KLFL 0 PSI (STATIC) K SUBSEA BOP C CLFL 0 PSI (STATIC) APL NEGLIGIBLE Ph = 4300 psi (In annulus) Ps = 5000 psi BHP = 5000 psi Intertek Consulting & Training Unpublished work. All rights reserved. Page 114

86. The driller needs to close in a flowing well with the drill pipe in a subsea BOP stack. He pushes the Annular Close button and the pilot light changes but all gauges and the flow meter remain static. What is his best option? A. Change pods and try again B. Call and wait for a subsea engineer C. Send the assistant driller to manually operate the 4-way valve on the hydraulic control manifold to close the annular 87. While drilling an alarm goes off indicating low accumulator pressures and the flow meter Indicates a rapid loss of fluid. The best course of action to take is.. A. Stop drilling and shut in the well B. Stop drilling and call the subsea engineer C. Stop drilling and put all functions in block 88. When a function is operated in a piloted hydraulic system which of the following is TRUE? A. SPM valves will operate in both pods B. SPM valves will only operate in the active pod 89. According to API specifications, closing units for subsea installations should be able to close ram preventers within seconds and the annular preventer closure time should not exceed seconds. 90. On a subsea pod, regulators are used to reduce the main hydraulic fluid supply from 3000 to a lower pressure for use. One of these regulates fluid pressure to the annular preventer. The other is the manifold regulator. Name two items on the stack that are supplied by fluid from the manifold regulator. 91. In order to verify the actual pressure supplied to control either an annular or ram preventer, a read back signal is sent to the surface. It is sent from. A. Upstream from the regulator in the pod B. The regulator itself C. Downstream of the regulator in the pod Intertek Consulting & Training Unpublished work. All rights reserved. Page 115

92. Ram locking devices such as wedgelocks or poslocks are fitted to a subsea stack: A. To provide addition force when closing a preventer thus reducing delay times B. To lock the ram in the closed position and maintain the shear rams locked during disconnect C. To lock the BOP stack to the wellhead and lock the Lower Marine Riser Package to the riser 93. A well is being shut in using an annular preventer with drill pipe in the stack. The flow meter continues to run. To preserve accumulator pressure and keep the well shut in the driller should.. A. Close the well in with the pipe rams and open the annular preventer B. Block the annular function, strip through the annular to space out the pipe for the ram, then shut in using pipe rams C. Go to Hydraulic Control Manifold to diagnose the problem D. Close another set of rams immediately and monitor the flow E. Put the annular function in block 94. When an operation of a BOP function is selected from the electric driller s panel a number of indications will confirm whether the operation is carried out or not. Which indications should be observed when a ram-type preventer is closed? (FOUR ANSWERS) A. Flow meter runs then stops B. Annular readback pressure decreases then increases C. Rig air pressure decreases and then increases D. Manifold readback pressure decreases then increases E. Manifold pilot pressure decreases then increases F. Accumulator pressure decreases then increases G. Annular pilot light pressure decreases and then increases H. Light changes from Green to Red 95. The hydraulic BOP control system is divided into a Control System and a Pilot System. Which options gives TRUE statements with respect to the pilot system? (TWO ANSWERS) A. The fluid in the pilot system flows continuously while a function on the BOP takes place B. The Pilot System dumps fluid to the sea at every operation of BOP functions C. The Pilot System controls the position of all shuttle valves on the BOP stack directly D. The Pilot System is a closed dead end system E. Pilot fluid is mainly potable water, water-soluble concentrate, glycol, bactericide, and corrosion inhibitor F. Pilot fluid is mixed with mainly potable water and a small amount of additives to limit pollution of the environment Intertek Consulting & Training Unpublished work. All rights reserved. Page 116

96. The drawing on the following page shows a diverter system for a floating rig. The wind is from Port to Starboard on the diagram. The well starts to flow. Which functions would you operate if the system was not automatically controlled? A.. Pressure A Close B Open C B.. Open F Close C Pressure A C Open F Unlock C Pressure A D Open B Close C Pressure A DIVERTER ELEMENT PRESSURE RELAX CLOSED OPEN Port Vent Returns to Shaker RI G AIR CLOSED ADJUST OPEN SLIP JOINT UPPER ELEMENT BLEED ADJUST SLIP JOINT LOWER ELEMNT PRESSURE RELAX RELAX Starboard LOCK UNLOCK CLOSED OPEN Vent Upper Working Packing Element DIVERTER INSERT Pressure Below Diverter Bag Lower Packing Element Closed When Diverter Is Operated Slip Joint Annulus Pressure Intertek Consulting & Training Unpublished work. All rights reserved. Page 117

97. The main components of a subsea control system are shown in the diagram on the following page. Some components have been identified by letter. Identify the following components: NOTE: A letter may be used more than once. Hydraulic hose bundle Subsea control pods Master electric panel Electric power pack Subsea hose reels Retrieving frame for pods Hydraulic control manifold Jumper hose bundle Subsea bottle rack Emergency back-up supply Electric driller s panel Intertek Consulting & Training Unpublished work. All rights reserved. Page 118

98. Which option gives the advantage of using the Kill Line with static fluid to monitor wellhead pressure during a well kill operation? A. Response on changes in wellhead pressure is quicker through the kill line B. Effect of choke line friction pressure is reduced by 25% when monitoring on the kill line gauge C. Effect of choke line friction pressure is reduced by 50% when monitoring on the kill line gauge D. Keep pressure on the kill line gauge constant while starting or stopping the pumps. This eliminates the effect of the choke line friction pressure. 99. In case of diverting a shallow gas blowout through a long marine riser a risk occurs that affects the riser. A. The riser may collapse B. The riser may burst due to extreme internal pressure C. Buoyancy forces acting on the riser may require tension forces in excess of a situation where the riser is full of fluid 100. What are the advantages of having a riser fill-up valve installed on a marine riser system? (TWO ANSWERS) A. Less tension is required for the riser B. It keeps the well full of mud while tripping out of the hole C. It reduces the risk of riser collapse D. It continuously supplies sea water to the well in case of total loss of returns E. It allows pumping heavy mud in the riser during kill operations 101. On a floating rig why does a driller need information about tides? (TWO ANSWERS) A. To adjust riser tensioners B. To know the position of tool joints in the stack relative to the rams C. To calculate riser tensioner ton-miles D. To correctly hang-off during well control operations E. To correctly set ram closing pressure Intertek Consulting & Training Unpublished work. All rights reserved. Page 119

DATA: The diagram illustrates the detail of hydraulic principle of redundancy utilized to control functions on the subsea BOP stack. Use this diagram to answer Question #102 YELLOW POD BLUE POD 102. Which statements are correct with respect to the shuttle valves? (TWO ANSWERS) A. The shuttle valves automatically seal any hydraulic leaks in the selected pod B. The shuttle valves isolate pressurized control fluid communication between the selected system and the redundant system C. The shuttle valves are pilot operated D. The shuttle valves allow retrieving a malfunctioning pod without losing hydraulic BOP control fluid 103. Master electric panels as well as electric mini panels for operation of functions on a subsea BOP are supplied with an electric Memory Function. Which statement is correct? A. Memory Function indicates a malfunction by giving permanent light on the alarm panel after an alarm has been acknowledged and the audible alarms has stopped B. Memory Function reminds the driller to add anti-freeze fluid when the temperature drops below a certain level C. Memory Function indicates the previous position before Blocked Position of three position functions D. Memory Function reminds the driller to engage the wedge locks before hanging off the drill pipe Intertek Consulting & Training Unpublished work. All rights reserved. Page 120

104. The two symbols below represent a 4-way, three position valve typically used in a subsea hydraulic control system. One is a manipulator type and one is a selector type. Write the names for each below their respective illustrations. C D 105. Write TRUE or FALSE next to each of the following questions regarding the use of manipulator-type 4-way valves used in subsea control systems. A. If the valve is shifted to the center or block position, the pressure will be vented from the line previously pressurized B. The center or block position can be used for troubleshooting hydraulic leaks C. The pod selector valve on the subsea hydraulic control system is of the manipulator type D. If the valve is shifted to the center or block position, pressure will be trapped in the line previously pressurized E. Manipulator type valves are the type typically installed inside the pod hose reels 106. Based on the diagram on the following page, place the appropriate part number (1 through 7) next to the matching item on the list below. Hydraulic pressure regulator Rams Open SPM valve Air solenoid valve Rams Closed SPM valve Shuttle valve 4-way manipulator valve Electric pressure switch Intertek Consulting & Training Unpublished work. All rights reserved. Page 121

1 Hydraulic Pilot Supply Open Air Supply 5 2 Block Close Vent Blue Yellow Quick Disconnect Junction Box To Yellow Hose Reel 3 Quick Disconnect Junction Box Blue Hose Reel 6 4 Control Fluid Supply 7 Blue Pod From Yellow Pod Open Close Ram Type BOP Intertek Consulting & Training Unpublished work. All rights reserved. Page 122

107. What THREE FACTORS on a floating rig may influence the accuracy of drilling fluid volume and flow readings when monitoring an open well? A. Water depth B. Vessel heave C. Number of generators on line D. Crane operations E. Rig pitch and roll F. Riser tension 108. After a gas kick has been killed using a subsea stack it is known that 8 bbl of gas remain trapped in the BOP stack between the annular preventer and the choke line side outlet. Based on the given information calculate the expanded volume of the gas when it reaches the rig floor if the annular were opened and the gas migrates to surface. Vertical distance between rig floor and BOP Kill mud density MW in riser Atmospheric pressure 1465 feet 13.5 ppg 12.5 ppg 14.6 psi A. 580 bbl B. 572 bbl C. 564 bbl D. 556 bbl 109. A gas kick is being circulated out on a floating rig. When the top of the kick has displaced the drilling fluid in the choke line the choke valve will require adjusting. In an attempt to maintain constant bottom hole pressure. What adjustment should be made to the choke? A. The valve must close more B. The valve must open more C. Keep the choke valve opening constant during this part of the kill operation 110. Why should CHOKE LINE FRICTION be recorded on a floating drilling rig? (ONE ANSWER) A. In order to be able to accurately calculate the density of the drilling fluid B. In order to know the amount SICP should increase when establishing the kill pump rate while keeping BHP constant C. In order to know what amount SICP should decrease when establishing kill pump rate and keeping BHP constant D. In order to know the Initial Circulating Drill Pipe Pressure at the kill rate if SCIP is lower than the choke line friction pressure Intertek Consulting & Training Unpublished work. All rights reserved. Page 123

KILL SHEET EXERCISES Complete an IWCF Subsea Kill Sheet using the data given and answer the questions on the page following the data. Well Data Hole ID 12 ¼ MD 8000 feet TVD 6930 feet Air gap 80 feet Water depth (MSL to sea floor) 850 feet Csg (13 3/8 ) set @ 5130 feet (RKB to shoe) Internal Capacities DP HWDP DC Choke Line ID 2.875 Riser Volume from mud pumps to rig floor.0177 bbl/ft.0088 bbl/ft (370 feet in length).0087 bbl/ft (745 feet in length).008 bbl/ft (930 feet in length).3789 bbl/ft (915 feet in length) 6.5 bbl Annular Capacities DC in Open Hole HW/DP in Open Hole DP in Cased Hole DP in Marine Riser Mud Pump Output:.0836 bbl/ft.1215 bbl/ft.1279 bbl/ft. 3546 bbl/ft.136 bbl/stk Slow Circulating Pump Data 40 SPM through the riser 800 psi 40 SPM through the choke line 1050 psi Active Surface Volume 500 bbl Sea water weight 8.6 ppg Formation Strength Test Data MW during test Leak off pressure Kick Data SIDPP SICP Pit Gain MW at the time of the kick 12.5 ppg 1330 psi 540 psi 750 psi 15 bbl 13.5 ppg NOTE: The well will be killed @ 40 SPM using the Wait and Weight Method Intertek Consulting & Training Unpublished work. All rights reserved. Page 124

1. Calculate the MAASP using the mud weight of 13.5 and calculate the MAASP using Kill Mud Weight. Using OMW psi Using KMW psi 2. What mud weight is required to balance the formation pressure? ppg (round off to 1 decimal) 3. Calculate the Initial Circulating Pressure. psi 4. Calculate the Final Circulating Pressure. psi 5. Calculate the pump strokes to pump from mud pump to the bit. stks 6. Calculate the time in minutes to pump from mud pump to bit. min 7. Calculate the strokes to pump from the bit to the shoe stks 8. How many minutes are required to circulate the total well system volume at 40 spm? min 9. What is the pressure safety margin at the shoe in the static condition? Assume the top of the kick to be below the casing shoe. psi 10. Calculate the initial dynamic casing pressure at the kill pump rate. psi 11. Calculate the strokes required to displace the riser to KWM before opening the BOP stack. stks Intertek Consulting & Training Unpublished work. All rights reserved. Page 125

12. Calculate the new MW when the riser margin is added ppg 13. Calculate the MAASP when the riser margin is included in the mud system psi Use the data from the filled out kill sheet to answer the questions following the kill sheet. You are only required to indicate the first action to be taken. The well is to be killed at 20 spm using the Driller's Method. Intertek Consulting & Training Unpublished work. All rights reserved. Page 126

1350 10.6 15.32 1206.13 20 380 450 70 11.1 810 830 2,550 2,550 5,490 4,570 9 5/8 12,230 5,500 8.5 16,920 7,000 2,550 2,940 11,100 210 120.0177.0177.0177.0087.0060 45.13 52.03 196.47 1.82.72 296.17 347 400 1511 14 6 2278 113.9 120 4570 11420 830.0291.0459.0502.0060 3.49 209.76 213.25 573.28 4.98 791.51 1087.68 580 1667.68 269.97.3333 810 1640 4410 38 6089 8367 4462 12,828 2077 82 220.4 1.9 304.4 418.3

394 586 980 38 0 470 380 5790 16920 410 930 13.7 11.1 4570 313 410 313 723 1310 980 330 330 95.1 347 980 723 257 257 64.2 400 723 470 253 253 1531 16.5