73236775 3 Well Control Exercises

WELL CONTROLEXERCISE # 1 1. What mud weight is required to balance a formation pressure of 2930 psi at 5420 ft TVD? ___________ppg 2. If the fluid level dropped 550 ft in a 9600 deep hole containing 10.6 ppg mud, what would the hydrostatic at bottom be? ___________psi 3. Bottom hole pressure is reduced the most by gas cut drilling mud when: a. b. c. d. The gas is near the surface The gas is at or near the bottom The gas is about halfway up the well bore All are about the same 4. After a round trip at 8960 ft with 10.9 ppg mud, we kick the pump in and start to circulate. An increase in flow was noticed and the well was shut in with 0 psi on the drill pipe and 300 psi on the casing. What kill mud is required? (no float in the drill string) ___________ppg 5. What was most probable in causing the influx or well kick in the last question? a. b. c. d. Abnormal pressure was encountered The mud weight was not high enough to contain formation pressure It was swabbed in or the hole was not properly filled while pulling out It is impossible to tell 6. Which of the following circumstances would increase the chance of swabbing in a kick? a. b. c. d. High pulling speed Mud properties with high viscosity and high gels Tight annulus BHA/hole clearance Mud density in use is close to formation pressure 7. In which of the following cases would you be most likely to swab in a kick? a. When the bit is pulled up into the casing b. When the first few stands are being pulled off bottom c. About half way up the well WELL CONTROL 8. When drilling with 10.3 ppg mud at 11600 ft TVD the annular loss is estimated at 195 psi. What is the BHCP? _________psi 9. You are pulling out of hole. Two x 93 ft stands of 8" drill collars have been stood back in the derrick. The displacement is 0.0538 bbls. / ft. According to your Assistant Driller, 10 bbls should be pumped into the well. It only takes 10 bbls to fill the hole. (Answer yes or no to each question) a) Are the calculations correct? b) Have you taken a 5 bbls influx? c) All Ok, keep going 10. You have taken a kick and shut the well in. The active tank while drilling contained 250 bbls. And the mud return line to the pits contains 25 bbls. The tank now contains 300 bbls. How many barrels of mud have been displaced from the well? a) 0 bbls b) 25 bbls c) 50 bbls d) 275 bbls 11. The Fracture Gradient of an open hole formation at 3680 ft. is 0.618 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 this formation breaks down? a) 350 psi b) 2275 psi c) 630 psi d) 400 psi 12. A gas kick is being circulated out. At the time the gas reaches the casing shoe (4250 ft. TVD), the pressure at the top of the bubble is 3000 psi. If the original mud weight is 12 ppg, what is the casing pressure at the surface? (Hole TVD 7000ft) a) 348 psi b) 442 psi c) 1368 psi d) 2625 psi WELL CONTROL Questions 13-14 are based on the following information: 13 3/8” surface casing is set and cemented at 4250 ft. (TVD). The cement is drilled out together with 15 ft. of new hole, using a 11 ppg mud. A leak off test pressure of 800 psi is determined. (Hole TVD 7000ft) 13. What is the formation fracture gradient? a) 0.188 psi / ft b) 0.686 psi / ft c) 0.760 psi / ft d) 0.384 psi / ft 14. What is the maximum allowable annular surface pressure for 12.3 ppg mud in use at 7350ft. TVD : a) 373 psi b) 511 psi c) 884 psi d) 1982 psi 15. How often should the MAASP be recalculated? a) After every bit change b) After a change in mud weight c) After every 500 ft. drilled 16. Calculate the equivalent circulating density in the following circumstances: Circulating pressure = 3100 psi Pressure losses: Surface equipment = 20 psi Drill string = 930 psi Nozzles = 1800 psi Annulus = 350 psi Drilled depth: 12,300 ft. (11,500 ft. TVD) Mud weight: 11.4 ppg ECD is: a) 10.8 ppg b) 12.0 ppg c) 11.4 ppg d) 12.3 ppg Drill pipe capacity = 0. Calculate the slow circulating rate pressure loss. c.WELL CONTROL 17. Overburden pressure is: a. b. the pressure exerted at any given depth by the weight of the fluid in the pore space of the rocks. the pressure exerted at any given depth by the weight of the rocks and sediments. D. which one acts only on the borehole? A. B. You have got a kick in the well of 220 psi shut in drill pipe pressure. The pressure loss in the drill stem. The pressure loss in the annulus . the pressure exerted at any given depth by the weight of the sediments. Of all the pressure losses in the circulating system. a) 700 psi b) 770 psi c) 800 psi d) 840 psi 19. 20. The pressure loss across the nozzles. The pressure loss in the surface lines. or rocks and the weight of the fluids that fill the pore spaces in the rock. the pressure exerted at any given depth by the weight of the rocks.0082 bbls/ft Average stand length = 93 ft Calculate : a) Mud required to fill the hole per stand when pulled „dry‟ (bbls per stand) b) Mud required to fill the hole per stand when pulled „wet‟ (bbls per stand) 18. d.0178 bbls/ft Drill pipe metal displacement = 0. C. You are determining your kill rate pressure and bringing your pump rate up to a predetermined 30 SPM by holding the shut in casing pressure constant. At 30 SPM your drill pipe circulating pressure is 1060 psi. At the start of a trip out of the hole for a bit change. Capacity Casing Capacity Mud Weight A. Capacity Casing Capacity Mud Weight A. At the start of a trip out of the hole for a bit change. C.0758 bbls/ft = 10 ppg 22. B. D. B.00764 bbls/ft = .00764 bbls/ft = . B. 650 psi 6 psi 65 psi 130 psi = .01776 bbls/ft = .01776 bbls/ft = . D. drilling mud weight and kill mud weight shut in drill pipe pressure. drilling pump pressure and mud weight shut in drill pipe pressure and mud weight slow circulating rate pressure and final circulating pressure slow circulating rate pressure and shut in drill pipe pressure 24. 48 psi 483 psi 600 psi 683 psi = . C.0758 bbls/ft = 12 ppg 23. the first 20 x 93 ft stands of pipe are pulled from the hole wet with no fill up. Metal Displacement DP. D. Using the following data calculate the reduction in bottom hole pressure? DP. the first 10 x 93 ft stands of pipe are pulled from the hole dry with no fill up. Using the following data calculate the reduction in bottom hole pressure? DP. Select the two things that are needed to accurately determine an Initial Circulating Pressure? A. drilling mud weight and final circulating pressure . drilling mud and kill mud weight slow circulating rate pressure. C.WELL CONTROL 21. drilling pump pressure. drilling mud weight and kill mud weight slow circulating rate pressure. B. Select the three things that are needed to accurately determine a Final Circulating Pressure? A. D. Metal Displacement DP. C. B. one circulation two circulations three circulations four circulations 26. 9 gallons. C. C. keep SIDP constant at the original shut-in value by opening the choke and bringing the pump up to kill-rate speed. C. 5 gallons. 3 gallons . The Drillers Method of Well Control will normally result in: A. 7 gallons. a higher surface pressure than the wait and weight method a lower surface pressure than the wait and weight method. keep SICP constant at the original shut-in value by opening the choke and bringing the pump up to kill-rate speed. 27.WELL CONTROL 25. D. During a well-killing operation. B. The Drillers Method of Well Control normally requires how many circulations to kill a well? A. D. 28.000 psi system with 1. C. ensure that casing pressure and standpipe pressure rise consistently together. B. B. a lower bottom hole pressure than the wait and weight method.000 psi precharge is approximately: A. a common way to bring the pump up to kill rate without changing bottom hole pressure is to: A. keep SIDP constant at the original shut-in value by opening the choke. a higher bottom hole pressure than the wait and weight method. The usable accumulator fluid for a 10 gallon accumulator bottle on a 3. D. Use the following well data to calculate the different influx heights: Drill collar length: 700 ft DC .5 14 TVD (ft) 9500 12000 11200 13000 Answer 32.OH Capacity .5 14 Answer .5 10.6 10. 10 20 30 40 Height (ft) ________ ________ ________ ________ 30. b. d.WELL CONTROL 29. Using the following well data calculate Kill mud weights: SICP (psi) 600 850 780 700 SIDPP (psi) 450 690 570 300 Mud Wt (ppg) 10 11 10.0459 bbl/ft Kick size (bbls) a. c.OH Capacity . Using the following well data calculate the Annular Pressure Losses: BHCP (psi) 6000 2600 5700 Mud Wt (ppg) 11.2 Height of Influx 400 840 350 Answer 31. calculate the influx gradients: SICP 800 950 680 SIDPP 720 600 550 Mud Wt 11.6 9. Using the following data. calculate the new pump pressure: Old pump pressure 2500 1700 Old Mud weight 16 10 New mud Weight 17.0292 bbl/ft DP .8 10 Depth TVD (ft) 9450 5000 10000 Answer 33. Using the following data. WELL CONTROL 34.5 10. Change the ECD to BHCD: ECD (ppg) 12.0459 bbl/ft ? Answer: ft/min . Convert the following pressure gradient to mud weight: Answer Gradient (psi/ft) . Using the following data. What would be the annular velocity around the drill collars: DC – OH capacity (bbl/ft) 0.56 .4 Depth TVD (ft) 8000 11400 12500 BHCD (psi) 37.81 Mud Wt (ppg) 36.3 Pump output (bbl/min) 6 Annular Velocity (ft/min) 38. calculate the new pressure: Old SPM Old pressure New SPM 40 200 80 20 400 55 35.2 9. What would be the annular velocity around the drill pipe if the pump output is 6 bbl/min and the DP – OH capacity is . calculate the reduction in bottom hole pressure. Using the following data answer the questions below: DC metal displacement: DC capacity: Casing capacity: Mud weight: .0758 bbl/ft . the first 20 x 93 ft stands of drill pipe are pulled from the hole dry. At the start of a trip out of the hole for a bit change. At the start of a trip out of the hole for a bit change. calculate the reduction in bottom hole pressure.01776 bbl/ft . the first 10 x 93 ft stands of drill pipe are pulled from the hole wet.054 bbl/ft . Using the following data.0758 bbl/ft 12 ppg a. What is the maximum level drop in the annulus? Answer: ft b. While tripping out of the hole.WELL CONTROL 39. Mud weight: Casing capacity: DP capacity: DP metal displacement: Answer: psi 12 ppg . the trip tank is turned off and a flow check is made when the drill collars are at the rotary table. Using the following data.00764 bbl/ft 41. The last 400 feet of drill collar are pulled from the hole dry with no fill up.0758 bbl/ft . What is the reduction in bottom hole pressure? Answer: psi .01776 bbl/ft .00768 bbl/ft . Mud weight: Casing capacity: DP capacity: DP metal displacement: Answer: psi 12 ppg .00764 bbl/ft 40. the SICP will be: a. When a kick is taken in oil based mud and the well pressure have stabilized. b.067 bbl/ft . how far from the surface would it be when it started to break out and become free gas if the mud weight in use is 12 ppg. Gas that is in solution will migrate in the annulus in a vertical well at the same rate as free gas. calculate the loss in hydrostatic pressure if the casing was not kept full and the float failed while running casing in the hole.0754 bbl/ft . Higher than the same kick in water – based mud b. 800 ft 1282 ft 9600 ft 2182 ft . c. Casing capacity .0754 bbl/ft Annular capacity . Lower than the same kick in water – based mud c. An influx in oil based mud is not possible to detect when it is first occurring because gas going into solution will cause no associated pit increase at the surface. TRUE or FALSE 44. TRUE or FALSE 46. Using the following data. If the critical bubble pressure was about 800 psi.WELL CONTROL 42. d.067 bbl/ft Differential height 1000 ft 800 ft Mud Wt 10 12 Anwser (psi) Formula : Mud gradient x Differencial Height x Casing capacity (Casing capacity + Annular capacity) 43. a gas condensate influx enters the well bore undetected. When drilling a deep high pressure high temperature well using oil base mud. a. The casing pressure would read the same in oil or water – based mud 45. f.85 ppg 12. g. c. b. c. d. b.4 ppg mud in the hole? (use data from Q-2) a.21 ppg 5. drill pipe gauge on driller‟s panel casing gauge on driller‟s panel drill pipe gauge at the choke panel casing gauge at the choke panel 2.2 ppg mud to 670 psi surface pressure. 11. d.69 ppg 11. 0. high pressure pump The same known mud weight in and out Cement recipe An accurate surface pressure gauge A long open hole section . e. b. a list of mud additives a known mud yield point accurate TVD for the casing shoe Small volume. d. h. Which gauge must be used to read drill pipe pressure while taking SCR‟s? a. c. c.841 psi/ft 3. b. increase decrease stay the same impossible to say 6. c. What is the formation fracture gradient calculated from the test? a. d.74 psi/ft 0.WELL CONTROL EXERCISE # 2 1. c. drilled out and tested with 10. b.564 psi/ft 0. What do you consider as essential for an accurate formation test? (4 answers) a. A 13 3/8 casing is set at 3126 ft TVD. What would be the MAASP with 11. What happen to MAASP as MW increases? a. d. 400 psi 461 psi 500 psi 560 psi 4. b.56 ppg 12. What mud weight would have a MAASP of 250 psi? (use data from Q-2) a.678 psi/ft 0. d. What is the mud weight that we would expect to use to balance normal formation pressure? a.2 ppg 8. 364 psi 244 psi 448 psi 732 psi 12.5 ppg mud fell by 560 ft in a 6543 ft TVD well. b. d.00 ppg 8.WELL CONTROL 7. b.56 ppg 8. true b.5 ppg of plan Pump out of hole while tripping Drill a pilot hole Pump a slug before tripping Control ROP Minimise losses to 15 bbl/hr 11. d.5 ppg is spotted around 4 ¾ drill collars (total length 460 ft) in a 6 1/8 hole containing OBM of 11. false 10. ROP will be maximised MW must be with . c. Swabbing will cause the loss of primary well control? a. c.94 ppg 10. What is the reduction in bottom hole pressure if a 5 bbl lightweight pill of 7. which of the following are considered to be good drilling practices? (3 answers) a. 50 psi 120 psi 95 psi 79 psi . b. c. g. If the level of 12. f. d. d. 7. b. d. What is primary well control? a. the use of drilling fluid to balance formation the use of BOP to secure the well the use of annular preventer to close the well the use of cement plug 9. c. what would be the reduction in BHP? a.9 ppg? a. e. b. c. When drilling top hole. true b.5 ppg MD: 7500 ft TVD:7000 ft a. false 15. Calculate the rate of gas migration if SIDDP has increased by 50 psi in 15 minutes? MW: 10. b.03 ppg 12. d. c. d. b. the choke is left closed while drilling a.6 ppg? a. c.4 ppg 12. W&W method gives lower shoe pressure in all cases a. c. Every kick should be handled as a gas kick? a. false 19. b. What is the KMW if OMW is 11. true b.6 ppg mud reaches the casing shoe at 3126 ft TVD? a. 12. d. 569 psi 314 psi 456 psi 297 psi 17.4 ppg 11. What is the casing pressure when a 5 bbl gas bubble at 2200 psi in 11.WELL CONTROL 13. For a Soft shut-in. false . false 14. true b.6 ppg 18. A 9000 ft well is shut in with 200 psi SICP and 0 PSI SIDPP. true c. 366 ft/hr 455 ft/hr 244 ft/hr 575 ft/hr 16. W&W method results in a lower shoe pressure if drill string volume is less than the open hole volume minus the influx volume? a. Casing pressure must be kept constant during the second circulation a. Surface pressures are always lower if the W&W method is used compared to the Driller‟s method? a.WELL CONTROL 20. Surface annulus pressure is lower than with the driller‟s method a. false Answer true or false for these statements on the W&W method: 21. false 28. false 26. true b. The W&W method is preferred if rapid gas migration is expected a. true b. true b. The pumps are brought up to speed keeping the drill pipe pressure constant a. false 22. false 27. true b. Bottom hole pressure is maintained constant a. false 23. true b. true b. true b. false . The W&W is preferred as MAASP is critical and open capacity is greater than the drill string capacity a. The well is dead when you have reached FCP a. SIDPP should be zero once you have reached FCP a. false 24. false 25. true b. true b. Which two of the given dimensions determine the operating limit of the pressure build up in the separator? a b c d e f g Body height. Height of the U-tube. a. TVD: 12500ft and APL: 400 psi? a. What happen to BHP? a.WELL CONTROL 29. e. A larger pit gain will give a higher SIDPP. b.500 lbs 67.000 lbs 167. c. 31. The choke operator maintain drill pipe pressure constant while circulating KMW from surface to bit. You are using a cup type tester. d. Vent pipe inside diameter. Vent pipe height.500 lbs 33. 32. stay the same 30.615". Calculate the tension force created on the drill pipe above the cup tester when a 3000 psi test pressure is applied. Inlet line inside diameter. decrease c. b. True Maybe Sometimes False Always . c. What is the BHCP if the MW is 10 ppg. a b c 267. The mandrel outside diameter is 6 3/4" and the casing inside diameter is 12. Inside diameter of the U-tube. 6200 psi 6900 psi 7300 psi 7700 psi The poorboy degasser (mud/gas separator) is identified by its design dimensions. resulting in a higher kill mud weight. Body inside diameter. increase b. d. c. 38. A larger pit gain will result in higher SIDPP and SICP. d. b. What is the value of the Maximum Allowable Annular Surface Pressure usually determined by? a. e. The slow circulating rate. The maximum bottom hole pressure that can be sustained. what will happen to the mud pit volume the moment the gas is passing through the choke? a. The annular pressure loss. is the SICP and SIDPP about the same? a. d. d. Only if the influx is a fluid. 37.WELL CONTROL 34. e. a. c. d. but theSIDPP will remain the same if the kick is big or small. True Maybe Sometimes False Always 35. b. The pit volume will rise and fall erratically. d. b. . c. After circulating out a kick using the driller's method. c. The temperature of the influx fluid. e. b. The pit volume will stay the same from now on. True Maybe Sometimes False Always 36. b. a. When killing a well using the wait and weight method. The pit volume should not be monitored when killing. c. The formation strength at the casing shoe. e. A larger pit gain will result in a higher SICP. The pit volume starts increasing. The pit volume starts to drop. e. Never Yes No Only if the influx was gas. Increase initially and decreases in the end. fill the hole with water. Start diverting. what would you do? a. Spot a hivis pill acroos the shoe. d. Set a barite plug. 43. b. b. shut the well in. b. c. The pit volume stays the same. Increase only due to added weight material. b. d. On a surface stack. Stop drilling. It doesn't matter at all if SIDPP is constant. d. b. If total losses occurred while drilling with water based mud. c. e. d. The pit volume decreases. e. e. What action would you take if while circulating out a kick the choke line parted? a. Fix the pump as soon as possible. . Stop pump and close the HCR. Start bullheading. When killing a well using the driller's method. c. Continue drilling blind. c. BHP would possibly exceed formation fracture gradient. BHP would cause more influx to enter the well bore. Continue to kill if the influx is past the shoe. what would happen if when bringing the pump up to kill speed the casing pressure was allowed to increase above the shut in casing pressure? a. 40. c. Change over to the other pump. 41. Stop the pump and close the shear rams. It is OK if SIDPP also rises the same amount. e. Whilst circulating out a kick the mud pump fails. 42. e. Start killing with the volumetric method. Only while using wait and weight method does it matter. Stop pump and close the choke. Shut the well in. what would happen to the mud pit volume during the second circulation? a. What is the first thing to do? a.WELL CONTROL 39. Decreases at first and increases in the end. Stop drilling. d. Pitgain 50 bbl. a.0292 bbl/ft. e.1520 psi/ft . Hydrauliccally operated choke and kill line valves. and the toolpusher keeps 850 psi on the drillpipe by adjusting the choke. SIDPP increases with the size of the kick. e. Rams and hydraulic operated choke and kill line valves.1025 psi/ft . e. c. The annulus capacity is . 642 psi 945 psi 573 psi 580 psi 752 46. c. cap. DP/OH cap= . Ram preventers only. Which of the following functions is activated by the manifold pressure of the accumulator unit? a. Mud weight is 12. d.WELL CONTROL 44. What is the gradient of the influx? a. b. c. e. The influx volume is 12 bbl. d. Annular preventers All stack functions. Ann. False 47. with 450' of DC= . Decrease by 307 psi Increase by 253 psi Stay constant at 850 psi Increase by 140 psi Decrease by 405 psi 48. MW in the hole=13. If this driller speeds the pump up to 35 SPM. TD=12000'. A driller is circulating a kick out and has reached hisfinal circulating pressure of 850 psi with 30 SPM.0521 psi/ft 45.1215 bbl/ft. SIDPP=600 psi. . d.1502 psi/ft . True b.1205 psi/ft . b. SICP=1025 psi. d. . Influx gradient = .5 ppg.0778 bbl/ft. SIDPP=800 psi. b. b.1 psi/ft What is the SICP? a. the bottom hole pressure will: a.5 ppg. c. recorded information is as follows : Fracture mud weight Capacity of 19. 9 5/8”.5 lbs.4 ppg mud is in use when the well kicks and is closed in.4 ppg b) 13. TVD). = 14. The final circulating pressure (using kill mud weight with a 100 psi Safety Margin is) : a) 850 psi b) 970 psi c) 920 psi d) 1050 psi . The kill mud weight required to balance the formation pressure is: a) 13. 11. (TVD 10429 ft).4 ppg = 0. = 0.WELL CONTROL A deviated hole has a measured depth of 12.8 ppg d) 12. Shut in Drill Pipe Pressure : Shut in Casing Pressure: Kick volume: Pre.2 ppg 51.8 ppg 52.1 ppg b) 12.0 ppg c) 12. Drill pipe Capacity of 9 5/8” J55 casing Slow Circulating Rate Pressure 750 psi 1050 psi 15 bbls.4 ppg d) 11.6 ppg c) 12.320 ft. The initial circulating pressure is: a) 1400 psi b) 1600 psi c) 1900 psi 53. = 850 psi 49.01776 bbl/ft. 47 lb/ft. The kill mud weight with a Safety Margin of 100 psi is: a) 13. casing in set at a measured depth of 9750 ft. The maximum allowable annular surface pressure is rounded off to : a) 1370 psi b) 1480 psi c) 1435 psi d) 1415 psi 50.0732 bbl/ft. (9200 ft. WELL CONTROL 54. The drilling mud currently in use is 9.000 psi BOP Equipment d) 10.000 psi BOP Equipment c) 5. In the area where local legislation requires that BOP equipment must be rated so that maximum anticipated formation pressures do not exceed 75% of BOP equipment pressure ratings.000 psi BOP Equipment b) 3. what is the Minimum Acceptable rating for equipment to be used in drilling Normally Pressured Formation to 16.000 psi BOP Equipment e) 15.8 ppg. The Fracture Gradient of an open hole formation at 3680 ft. is 0.000 psi BOP Equipment .618 psi/ft.000 ft. Approximately how much Surface Casing Pressure can be applied to the well before this formation breaks down? a) 350 psi b) 2275 psi c) 630 psi d) 400 psi 55. TVD? a) 2. 119 bbls/stk PUMP PRESSURE While Drilling Slow Pump Rate Up Riser Slow Pump Rate Up CL 2600 psi at 90 spm (APL = 310 psi) 270 psi at 30 spm (APL = 75 psi) 360 psi at 30 spm ANNULAR VOLUMES Drill pipe .0505 bbls/ft = 0.00768 bbls/ft 95/8”.0088 bbls/ft 61/2” x 213/16” x 750 ft Capacity = 0.WELL CONTROL EXERCISE # 3 Use the Well Data to answer the questions.Open hole Drill pipe – riser Active surface volume = 0.01776 bbls/ft 5” OD.336 bbls/ft = 320 bbls Mud weight in use Pump output WELL CONTROL DATA SIDPP SIDPP SICP GAIN FRACTURE GRADIENT AT SHOE = 500 psi = 720 psi = 10 bbls = .500 ft TVD 15 ppg. 19. 0. 47 lb/ft.0459 bbls/ft = 0.681” ID 100% Internal yield = 10. 50 lbs/ft x 850 ft Capacity = .5 lbs/ft Capacity = 0.91psi/ft .Casing Drill pipe .Casing Drill pipe . Each question has only one correct answer.5” 5” OD. P110 8.0292 bbls/ft = 0.000 ft TVD 10.000 ft MD 800 ft 820 ft capacity = 0.0087 bbls/ft 8.Open hole Drill collars .900 psi Set at 7. WELL DATA Well Depth Marine riser Choke line Bit size Drill Pipe HWDP Drill Collars Casing 10. 5 bbls 627. B.5 minutes 46. 17 minutes 25 minutes 32 minutes 39 minutes 4. C. What kill mud is required to balance formation pressure? A.4 ppg 13. B. B. C. D. 13. C.0 ppg 6.WELL CONTROL 1.6 bbls 3.0 ppg 12. C. 58. The ICP (initial circulating pressure) at 30 spm will be approximately? A. What is the surface to bit time with the pump running at 80 spm? A. Calculate the total annular capacity with the pipe on bottom while controling the well? A. 482. D. What is the total capacity of the drill string? A. C. B. B.5 bbls 547.2 bbls 446.8 minutes 60. 150 bbls 162 bbls 197 bbls 180 bbls 2. D. C. B. 270 psi 770 psi 990 psi 1200 psi . D.5 minutes 5. D.3 minutes 51.4 ppg 16. D. Calculate bit to surface time (bottoms up) at 80 spm? A. What is the hydrostatic pressure at the bottom of the hole before the kick? A. B. The FCP (final circulating pressure) at 30 spm will be approximately? A. 15. After reaching FCP it is decided to increase the pump speed to 40 spm. 17. C. What is the ECD on bottom while drilling? A. What would happen to BHP if the drill pipe pressure is held constant at the original FCP value? A. D. B.0 ppg 15.5 ppg 18. C.5 ppg 16. D. B.0 ppg 16. C. C. B. 412 ft/min 210 ft/min 506 ft/min 321 ft/min 12.0 ppg 19. 5800 psi 6800 psi 7800 psi 6240 psi 10. C.0 ppg .WELL CONTROL 7. At 80 spm what is the annular velocity around the drill collars? A. B. D. approximately 800 psi approximately 390 psi approximately 500 psi approximately 290 psi 8. C. D. D.5 ppg 11. D. B. What is the maximum allowable mud weight? A. increase by about 225 psi decrease by about 225 psi remain constant because drill pipe pressure was not changed increase by about 500 psi 9.5 ppg 16. 465 psi/ft . How many strokes to go from ICP to FCP? A. C. D. D. D. 1027 ft 850 ft 653 ft 342 ft 14. B. D.433 psi/ft 15. C. C. D. 1282 stks 1363 stks 1680 stks 1538 stks 16. How long will it take to go from bit to shoe at a pump speed of 30 spm? A. How many strokes will it require to go from bit to shoe? A. What is the approximate length of the influx? A. C. The gradient of the influx is about? A. about 214 minutes about 29 minutes about 157 minutes about 55 minutes 18. B.WELL CONTROL 13.320 psi/ft . D. . B. C. B. 5364 stks 4122 stks 1658 stks 858 stks 17. about 96 minutes about 34 minutes about 214 minutes about 76 minutes . B. At 30 spm what is shoe to surface travel time? A.137 psi/ft . B. C. 1250 psi 1500 psi 2000 psi 1950 psi 20.5 ppg 16. What would be the approximate pressure step down from ICP to FCP in psi/100 strokes. how much pressure is applied at the surface to give a fracture gradient of . B.2 ppg 23. D. 30 psi/100 stks 35 psi/100 stks 50 psi/100 stks 66 psi/100 stks . B. C. C. If a 100 psi safety margin is included in the kill mud weight. 157 mins 214 mins 45 mins 76 mins 22. 685 psi 1638 psi 700 psi 585 psi 21. what would the new kill weight be? A.WELL CONTROL 19. D.91 psi/ft? A.5 ppg mud in the hole. D. C.0 ppg 15. C. D.4 ppg 16. C. B. If the casing shoe is tested with 12. What would be the new MAASP once the well has been killed? A. At 30 spm how long will it take to pump kill mud to the bit? A. D. A. 15. B. B. This is what the choke control console shows. E. decrease the pump speed E. What should you do? A. D. increase the pump speed D.WELL CONTROL Answer the following gauge questions as the well is killed using the Drillers method. What should you do? A.5 bbl rise in the level. TO TA L S TR O K E S 90 0 1000 1 100 80 0 70 0 600 5 00 400 3 00 200 1 00 1900 1200 1300 50 700 6 00 5 00 4 00 300 1400 15 00 160 0 900 10 00 1100 800 1 200 13 00 PSI PSI 14 00 1 500 1600 1 700 1700 1 800 200 18 00 10 0 1 900 PUMP SPEED D R ILLP IP E P R E S S U R E 30 C A S IN G P R E S S U R E 770 O P EN C H O KE P O S IT IO N C LO S E 630 24. nothing everything looks alright . open the choke a little close the choke a little increase the pump speed decrease the pump speed nothing everything looks alright Possible plugged nozzle Possible choke wash out Possible choke plugging TO T A L S TR O K E S 900 100 0 1 100 800 70 0 60 0 5 00 40 0 300 2 00 1 00 1 900 120 0 130 0 580 70 0 60 0 5 00 40 0 300 140 0 1500 16 00 900 100 0 11 00 800 120 0 130 0 PSI PSI 1400 1 500 160 0 170 0 170 0 1800 2 00 1 800 100 1 900 PUMP SPEED D R ILLP IP E P R E S S U R E 30 C A S IN G P R E S S U R E 600 O PE N CH O KE P O S ITIO N C LO S E 600 25. close the choke a little C. Pit room calls up to confirm a . The kill operation has started. G. F. C. H. B. open the choke a little B. E. B. D. open the choke a little close the choke a little increase the pump speed decrease the pump speed nothing everything looks alright . This is what you see on the panel.WELL CONTROL TO TA L STR O KES 900 1000 1100 8 00 700 600 500 400 300 200 100 1900 1200 1 300 3250 700 600 500 400 300 1400 1500 1600 900 1000 1100 800 1200 1300 P SI PS I 1400 1500 1600 1700 1700 1800 200 1800 100 1900 PU M P SPEED D R ILLP IPE PR E SSU R E 30 CASIN G PR ESSU R E 770 O PEN CH OK E PO SITIO N C LOS E 1 0 20 26. The pit levels are still reported to be increasing slightly. C. A. Properly install and test BOP equipment b. c. Keep mud weight high enough c. Most kicks have been caused by the failure of drilling crews to: a. b. watch for flow.V. The mud weight required in the hole to balance normal formation pressure would have to be: a. Abnormally pressured formations People not reacting or handling situations properly BOP equipment failure Lost circulation 5.5 ppg 6. Know how to take SIDPP with a float in the string Shut the well in quickly and properly with the least amount of gain Circulate the kick out using constant circulating pressure and pump strokes Hold 200 psi extra back pressure with the hydraulic choke while circulating out the kick 4. Mud monitoring equipment such as P. d. Observe. d. d. spot a high viscosity pill. b. A large percentage of all kicks have been caused by: a. and if there is none.T. d. then pump out of hole Go back to bottom. b. trip tanks and trip records should be used: a. Make sure that hole takes the proper amount of fluid during a trip 2. d.WELL CONTROL EXERCISE # 4 1. b. c.3 ppg 8.3 ppg 10. c. Any time the well is open Any time fluid is circulated through the mud pit When abnormal formation is expected When drilling 12 ¼ hole . c. pull out of hole Stop.9 ppg 9. and pit alarm systems. What is the correct action if the hole does not take the proper amount of fluid while tripping out of the hole? a. The most important rule in well control is to: a. 8. b. c. circulate bottoms up and evaluate the problem Check for gas cut mud at the surface 3. d. a) Surge pressure is reduced. The first reliable indication that a kick is in progress is: a.   True False b) Reverse circulation is possible. False 8. c. b.   True False . True b.   True False d) Shut-in drillpipe pressure can be taken without starting the pumps. Final circulating pressure is reached when: a. b. No warning An increase in pump pressure An increase in mud flow. increase b. The influx is circulated out Kill mud has made a complete circulation Kill mud has made a bottom-up Kill mud reaches the bit 11. mud volume and a decrease in pump pressure Reduced drilling rate 9. c. Every kick should be handled as a gas kick a. the surface pit volume will: a. decrease c. Mark the statements below "true" or "false" when drilling with a float valve in the string.   True False c) Flow back through the drillstring often occurs after pumping a slug. When a gas kick is being circulated up a well. stay the same 10.WELL CONTROL 7. d. What is the primary function of the choke in the overall BOP system? a) To divert contaminant to burning pit. d) Do nothing. b) A primary seal is leaking. 13. secure the well and repair the seal. Why should the side outlet below a test plug be kept in the open position while testing a surface BOP stack? a) Because of potential damage to casing/open hole.837 psi/ft c) 0. c) To divert fluid to the mud tank. . c) Small influx.WELL CONTROL 12. using a 10. of new hole.619 psi/ft b) 0. e) Large influx. (TVD) The cement is drilled out together with 15 ft. While testing the BOP stack. Change the worn packer. f) Small difference between formation breakdown pressure and mud hydrostatic pressure. d) To prevent the loss of mud due to expansion of gas. 16. The seal requires a slight leak for lubrication purpose. What is the formation fracture gradient? a) 0.2 ppg. c) The rams packer is leaking due to wear. d) Short open hole section. Which one of the following best describes the proper action to be taken? a) Energize plastic seal and repair BOP at next scheduled maintenance. Which three of the following conditions in the well increase the risk of exceeding the MAASP during the well kill operation? a) Long open hole section. A Leak Off Pressure of 670 psi is determined. e) To close the well in softly. b) Large difference between formation breakdown pressure and mud hydrostatic pressure.745 psi/ft d) 0. b) To hold back pressure while circulating up kick. 14. Questions 16-18 are base on the following information: 13 3/8” surface casing is set and cemented at 3126 ft. b) Because the test will create extreme hook load. c) Otherwise reverse circulation will be needed to release the plug 15.530 psi/ft. it is noticed that hydraulic oil is leaking from the weep hole on the upper rams. mud. is 0. A gas kick is being circulated out. d) The use of Pit Volume and Flow Rate measuring devices to recognize the kick.WELL CONTROL 17. d) Formation fluid pressure that exceeds normal water hydrostatic pressure. Approximately how much Surface Casing Pressure can be applied to the well before this formation breaks down? a) 350 psi b) 2275 psi c) 630 psi d) 400 psi 21. The drilling mud currently in use is 9. . What is meant by Abnormal High Pressure with regard to fluid pressure in the formation? a) The excess pressure due to circulating mud at high rates.618 psi/ft. At the time the gas reaches the casing shoe (3126 ft TVD) the pressure at the top of the bubble is 2200 psi. If the original mud weight is 11.6 ppg. c) The use of Blow Out Preventers to close in a well that is flowing. b) The used of Mud hydrostatic to balance fluid pressures in the formation. a) 865 psi b) 474 psi c) 449 psi d) 563 psi 18. What is primary well control? a) The slow Circulating Rate Pressure used in the kill process. drilled 19. How often should the MAASP be recalculated? a) After every bit change b) After a change in mud weight c) After every 500 ft. What is the Maximum Allowable Annular Surface Pressure for 11.8 ppg. a) 314 psi b) 442 psi c) 542 psi d) 506 psi 20. The Fracture Gradient of an open hole formation at 3680 ft. 22. What is the casing pressure at surface.4 ppg mud used at 6500 ft TVD. b) The excess pressure that needs to be applied to cause „leak-off „ into a normally pressure formation. c) High density mud used to create a large overbalance. Which factors most influence the rate at which shut in pressures stabilize after the well is shut in? a) Gas migration b) Friction losses c) Permeability d) Type of influx 24. While running pipe back into the hole. d) The well has been swabbed. b) Monitoring the mud volume in the mud tanks. c) Choose a lower circulating rate. A pit loss of 2 bbl. c) Stop drilling. a) Maintain extra back pressure on the choke for safety. A kick has been taken and it is known that a potential lost circulation zone exists in the open hole. If total losses occurred while drilling with water based mud what would you do? a) Continue drilling blind. c) A kick has been taken. b) Total lost circulation has occurred. . Which of the following causes of well kicks is totally avoidable and is due to a lack of alertness by the driller? a) Lost circulation. Lost circulation during a well control operation is usually detected by: a) Monitoring the return flow with the flow show. d) Choose a higher circulating rate. the return flow meter is observed to reduce from 50% to 42%. 27. 26. from the top until stabilized. is noted. b) Gas cut mud. c) Not keeping hole full. b) Stop drilling and fill the annulus up with water. 25. 28. b) Use the wait and weight method. What is the most likely cause of these indications? a) Partial lost circulation has occurred. After reaching bottom and commencing circulation. Select two correct actions which can be taken to minimize pressure in the annulus during the kill operation. it is noticed that the normal displacement of mud into the trip tank is less than calculated. c) Monitoring the weight indicator. shut the well in and see what happens.WELL CONTROL 23. d) Abnormal Pressures. Why is a 20 barrel kick in a small annulus more significant than a 20 barrel kick in a large annulus? a) The kill weight mud cannot be calculated as easily. b) It result in higher annulus pressures. . 31. Which two practices are used to maintain primary well control as a precaution when connection gas is noticed? a) Pumping a low viscosity pill around bit to assist in reduction of balled bit or stabilizers. What should the driller do at a drilling break? a) Circulate bottoms up. Which two of the following cause swabbing? a) Pulling the pipe too fast. e) Minimizing the time during a connection when the pumps are off. d) Gas cut mud. b) Increase torque. d) Going into the hole too fast. due to the height of the kick. d) Increase pump speed. 30. c) Pit gain.WELL CONTROL 29. e) Failure to slug pipe prior to pulling out of hole. Which one of the following is not an indication when a kick may be occurring? a) Flow rate increase. 33. b) Control drilling rate so that only one slug of connection gas is in the hole at any one time. d) Raising Mud yield point. c) The kicks are usually gas d) The pipe usually get stuck. b) Flow check c) Reduce weight on bit. c) Pulling out of the hole to change the bit. b) Insufficient trip margin. c) Improper circulating density. 32. d) decrease drill string weight e) pit volume gain f) increased rate of penetration 35. a) 260 bbls b) 20 bbls c) 40 bbls d) 240 bbls. if negative displace a 100 ft. While drilling The active tank contained 200 bbls and the mud return line to the pits contains 20 bbls. which two signs would leave little room for doubt that the well is kicking? a) flow line temperature increase.08 bbls/ft. if negative continue to pull out of hole.0075 bbls/ft. The driller is tripping pipe out of a 12 ¼” diameter hole. b) increased rotary torque c) flow rate increase. d) Flow check. Which of the following statements best describes formation porosity. d) All of the above 36. There are 85 more stands to pull. c) Flow check. stand of 5” pipe have already been pulled. e) Pull remaining stands out of hole. . b) Shut the well in and circulate hole clean. The calculated metal displacement of the 9 ½” collars is 0. c) The presence of sufficient salt water volume to provide gas lift. a) The ratio of the open spaces to the total volume of rock. What action should be taken in this situation? a) Flow check. Of all the following warning signs. The trip tank volume has reduced from 27 barrels to 15 barrels. heavy slug into annulus and continue to pull out of hole. The capacity of the drill pipe is 0. 37. if negative run back to bottom and monitor returns. 25x92 ft.01776 bbls/ft and the metal displacement 0.WELL CONTROL 34. What is the size of the influx?. b) The ability of fluid and gas to move within the rock. After having a kick the tank contains 240 bbls. if negative displace a 100 ft. It only takes 5 bbls to fill the hole. the pipe is full of 10. c) Large. While pulling out of the hole it is noticed that mud required to fill the hole is less than calculated. e) All of above. Two 93 ft. e) Shut the well in and circulate the hole clean. The pipe capacity is 0. According to your Assistant driller .4 ppg.1 bbls should be pump into the well. mud. What is the drop in bottom hole pressure due to pumping the slug into position? a) 25 psi b) 0 psi. 41. heavy slug into annulus and continue to pull out of the hole. b) Flow check. splintery cuttings.0549 bbls/ft. 40. c) 117 psi d) 135 psi. if negative continue to pull out of the hole. 39. (Answer “Yes” or “No” to each question. A 25 bbls slug weighting 12. Which of the following possible indications suggest that mud hydrostatic pressure and formation pressure are almost equal? a) A drilling break. You are pulling out of hole. if negative run back to bottom circulate bottoms up and monitor returns.5. keeps going? Yes No . Prior to pulling out of the hole from 10485 ft. TVD. The displacement is 0. inside the drill pipe.01776 bbls/ft.) a) Are the calculations correct? Yes No b) Have you taken a 5 bbls influx? Yes No c) All OK. b) Connection gas. d) Trip gas. What action must be taken? a) Flow check.WELL CONTROL 38. d) Flow check.0 ppg is pumped into the drill pipe causing the level to drop some 216 ft. c) Pull remaining stands out of the hole. stands of 8” drill collars have been stood back in the derrick. can a wire line be run inside the drill string? Yes No 43. (Answer “Yes” or “No” to each question. close the valve. A non return type safety valve was made up on top of the kelly cock prior to stripping in. j) Not holding down master air valve on remote BOP control panel while functioning a preventer. c) Drilling 20 ft further after a drilling brake. If flow through the drillpipe occurs while tripping. e) Maintaining stab in valves. From the list of practices shown below. g) Excluding the drawworks from the SCR assignment. h) Keeping air pressure on choke control console at 10 psi. choose the six most likely to lead to an increase in the size of the influx. f) Testing stab in valves during BOP tests.WELL CONTROL 42. 44. c. Which list below (a. b. Close the annular preventer. what should the first action be? a. Stab a full opening safety valve.) a) Should the kelly cock be closed? Yes No b) If the kelly cock is left in the open position. i) Calling toolpusher to floor prior to shutting in the well. d. b. 45. While tripping out of the hole a kick was taken and a full bore kelly cock was stabbed and closed. Pick up and stab kelly. d) Running regular pit drills for drill crew. b) Regular briefing for the derrickman on his duties regarding the monitoring of pit levels. c or d) describes how the choke manifold will most likely be set up for Hard Shut-in while drilling? BOP Side Outlet open open closed closed HydraulicValve(HCR) closed open open closed Auto Choke closed closed open open A B C D . a) Switch off the flow meter alarms. before flow checking. Run back into bottom. Which one of the following would be the safest course of action. d) Slow down the drilling rate and the pump rate until the shakers clear up then go back to the original parameters. if there is not any then circulate bottoms up to reduce rate so shakers can handle cutting volume. . c) Slow down the mud pump until the shakers can handle the volume of cuttings in the returns as requested by derrickman. b) Pick up off bottom and check for flow. While drilling along at a steady rate the derrickman asks to slow the mud pumps down so that the shakers can handle the increase in cuttings coming back in the returns.WELL CONTROL 46. a) Continue at the same rate allowing the excess to bypass the shakers and get caught in sand traps which can be dumped later. flow check periodically during circulation. why is it important to get the well shut in as soon as possible a) A larger pit gain will result in a higher SIDPP resulting in a heavier kill mud weight True or False. A kick is being circulated out at 30 SPM. a) Increase b) Decrease c) Stay the same d) No way of knowing 4. While killing a well. b) A larger pit gain will result in higher SIDPP and SICP True or False. Which two pressure gauge readings might be used to determine formation pressure? a) BOP manifold pressure gauge b) Choke console drill pipe pressure gauge c) Driller‟s console drill pipe pressure gauge d) Choke console casing pressure gauge 3. How will this affect bottom hole pressure (exclude any Equivalent Circulating Density [ECD] effect)? Pick one answer. The principle involved in Constant Bottom Hole Pressure methods of well control is to maintain a bottom hole pressure that is : a) Equal to the slow circulating rate pressure b) At least equal to the formation pressure c) Equal to the shut in drill pipe pressure d) At least equal to the shut in casing pressure . 2. what should happen to casing pressure in order to keep bottom hole pressure steady? a) Casing pressure should be held steady during SPM change b) Casing pressure should be allowed to rise during SPM change c) Casing pressure should be allowed to fall during SPM change 5. The drill pipe pressure reads 550 psi. c) A larger pit gain will result in higher SICP but SIDPP will stay the same True or False. It is decided to slow the pumps to 20 SPM while maintaining 970 psi on the casing gauge. as pump speed is increased. and casing pressure 970 psi.WELL CONTROL EXERCISE # 5 1. A flowing well is closed in. When a kick occurs. a) True b) False Questions 10-18 are based upon the following information : A well is closed in having taken a 30 bbl gas kick. even though surface pressure on the annulus continues to rise. = 0. How is a choke wash-out recognized? a) Rapid rise in casing pressure with no change in drill pipe pressure b) Increase in drill pipe pressure with no change in casing pressure c) Continually having to open choke to maintain drill pipe and casing pressure d) Continually having to close choke to maintain drill pipe and casing pressure 9. =0. The choke has to be gradually closed due to a string washout. while drilling 8 ½” hole at 11.WELL CONTROL 6. (TVD) with 5” drill pipe and 750 ft.0292 bbls / ft . If Drill pipe Pressure is held constant while displacing the string with kill mud. the pressure on at the casing shoe will not increase after the influx passes. what will happen to Bottom Hole Pressure? a) Increases b) Remains the same c) Decreases 8. DC /8 ½" Hole. of 6 ½” drill collars Annular capacities 5" DP / 8 ½" Hole.000 ft. At what point while correctly circulating out a gas kick is it likely that the pressure at the casing shoe to be at its maximum? a) At initial shut in b) When kill mud reaches the bit c) When kill mud reaches the shoe d) When top of gas reaches the shoe 7. If Bottom Hole Pressure is held constant while circulating the influx out. What effect does the gradual closing of the choke have on the bottom hole pressure? a) Decreases b) Increases c) Stays the same 10.0459 bbls / ft. While preparing to circulate Kill Mud. If you decide to bleed enough mud to keep the Drill Pipe Pressure constant at 350 psi. What will happen to Bottom hole Pressure? a) Increase b) Decrease c) Remain approximately the same 14. what would the pressure in the bubble do as the gas rises? a) Increase b) Decrease c) Remain approximately the same 17. What would happen to Bottom Hole Pressure? a) Increase b) Decrease c) Remain approximately the same . what will be the approximate Shut in Casing Pressure: a) 835 psi b) 650 psi c) 975 psi d) 888 psi 12. Assuming the gas Pressure Gradient to be 0. What will happen to the pressure on the Casing Seat? a) Increase b) Decrease c) Remain approximately the same 16.3 ppg and the Shut in Drill Pipe Pressure is 350 psi.115 psi/ft. The mud weight is 12. what will happen to the pressure in the gas bubble as it rises: a) Increase b) Decrease c) Remain approximately the same 13. If no action is taken.WELL CONTROL 11. What will happen to Shut in Casing Pressure? a) Increase b) Decrease c) Remain approximately the same 15. the gas bubble begins to migrate. 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 23. What would happen to the Shut in Casing Pressure? a) Increase b) Decrease c) Remain approximately the same 19. slowly but regularly you have had to reduce choke size because the drill pipe and casing pressures keep dropping with constant pump strokes. A kick is being circulated from a well using the Driller‟s Method. The operator increases pump speed to 35 SPM. Pumping pressure having been established as 1000 psi at 30 SPM. What would happen to the Pressure on the Casing Seat when the bubble is above the Casing Shoe? a) Increase b) Decrease c) Remain approximately the same 21. pressure suddenly increases to 1350. During the well kill operation. while holding pump pressure constant. During the operation. What would happen to the Pressure on the Casing Seat while the bubble is below the Casing Shoe? a) Increase b) Decrease c) Remain approximately the same 20.WELL CONTROL 18. An influx is being circulated out using the Driller‟s Method and using 1100 psi at 30 SPM. What should you do? a) Reduce 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 bit plugged d) (a) and (b) are acceptable courses of action 22. You are reasonably sure that a Nozzle of the Bit is plugged. What happens to Bottom Hole Pressure? a) Increases b) Decreases c) Remains approximately the same . The pump strokes remain constant. . you have to pinch in the choke to maintain drill pipe and choke pressures while the pump strokes remain constant. you may have: a) a washed out bit nozzle b) a washed out choke c) a pump failure 27. You are killing a well using the Drillers Method. the drill pipe pressure remains unchanged but the casing pressure goes up. The drill pipe pressure begins to drift down. If regularly and rather slowly. d) The only difference is in the type of gauges used. maintaining constant Drill pipe pressure. b) The influx fluid is usually less dense than the existing mud weight. How can a washout at the adjustable choke be recognized? a) Drill pipe and casing pressures both falling b) Drill pipe and casing pressures both rising c) Rapid rise in casing pressure with no change to drill pipe pressure d) Increase in drill pipe pressure with no change to casing pressure 28. c) The casing pressure is not necessarily higher. it depends on whether it is an offshore or land operation. therefore creating a lighter hydrostatic in the annulus. Which of the following parameters can be affected by a drill string washout during a well kill operation? a) Bottom hole pressure b) Kick tolerance c) Formation fracture pressure d) Slow circulating rate pressure 25. but the casing pressure remains unchanged. You close up your choke slightly.WELL CONTROL 24. What is the probable cause for this? a) Choke is plugging off b) Bit is plugging off c) Hole in drill pipe d) Choke is washing out 26. The reason shut in casing pressure is usually higher than the shut in drill pipe pressure is: a) The cuttings in the annulus are lighter. After a round trip at 9854 ft with 10. This pumping pressure is the SIDPP. 33. The pressure shown when the pump is at kill rate is the SIDPP. When casing pressure starts to rise. There is no float in the drill string. we kick the pump in and start to circulate. A gas kick is being circulated up the well. the float has opened.3 ppg b) 11. To establish the SIDPP. What is the surface pit volume most likely to do? a) Increase b) Stay the same c) Decrease . what action should be taken? a) Shearing the pipe and reading the SIDPP directly off the casing gauge b) Pump at kill rate into the drill string with the well shut in. This is the SIDPP. After shutting in on a kick. The well kicks and is closed in with 0 psi on the SIDPP and 150 psi on the SICP. yes b. c) Pump very slowly into the drill pipe with the well shut in. Which one of the following is the probable cause? a) A further influx is occurring b) The influx is migrating up the well bore c) The gauges are faulty d) The BOP stack is leaking 30. d) Bring the pump up to the kill rate holding the casing pressure constant by opening the choke.3 ppg c) 10. are the SICP and SIDPP about the same? a.3 ppg mud.WELL CONTROL 29. no 34. What kill mud weight is required? a) 10. Shut in casing pressure is used to calculate a) Kill weight mud b) Influx gradient and type when influx volume and well geometry are known c) Maximum Allowable Annular Surface Pressure d) Initial circulating pressure 32. the SIDPP and SICP are observed to be stable for fifteen minutes. then.7 ppg d) No way of knowing 31. A kicking well has been shut in. Both. read the pump pressure. When the pumping pressure stabilizes. After circulating out a kick using the driller‟s method (no weight up). start rising slowly by the same amount. The drill pipe pressure is „0‟ because there is a nonreturn valve (float) in the string. note whether it relates to the Drillers Method or the Wait and Weight Method. at regular intervals d) Bleeding off the drill pipe closed end displacement at regular intervals 38. equal to the drill pipe closed end displacement at regular intervals b) Bleeding off the drill pipe steel displacement at regular intervals c) Pumping a volume of mud into the well. a) Minimize pressures generated in the annulus due to gas migration. Driller W&W b) Remove influx from well before pumping kill mud Driller W&W c) Pump kill mud while circulating influx up the annulus Driller W&W d) Maintain Drill Pipe pressure constant for 1 st circulation Driller W&W 37. On a surface stack. equal to the drill pipe steel displacement. Which of the following statements is true? a) There is no difference between using the Drillers method and the Wait and Weight method b) If the kill mud is being circulated up the annulus before the kick has reached the shoe then Wait and Weight method will reduce the risk of breaking down the formation compared to using the Drillers method c) The Wait and Weight method should always be used because the pressure against the open hole will always be lower when using the Drillers method . For each of the following statements. the casing pressure was allowed to fall below shut in casing pressure? a) Formation would most probably break down b) More influx would be let into the well bore c) It would have no effect on anything 36.WELL CONTROL 35. Which one of the following actions taken while stripping into the hole will help to maintain an acceptable bottom hole pressure? a) Pumping a volume of mud into the well. what would happen if when bringing the pumps up to kill speed. Should casing pressure be: a) Less than Shut in Drill Pipe Pressure b) Equal to Shut in Drill Pipe Pressure c) Greater than Shut in Drill Pipe Pressure 42. observed pump pressure is ICP d) Add 1000 psi to shut in drill pipe pressure and circulate out the kick 41. Mud weight increase required to kill a kick should be based upon : a) shut in drill pipe pressure b) shut in casing pressure c) original mud weight plus slow circulation rate pressure losses d) shut in casing pressure minus shut in drill pipe pressure 40. what would happen to the bottom hole pressure? a) Increase b) Decrease c) Stay the same 43. if the casing pressure was held constant until the kill mud reached Surface.WELL CONTROL 39. How is the Initial Circulating Pressure found on a land rig or a jack-up. the well is shut in. when the slow pump rate circulating pressure is not known but a kick has been taken? a) Circulate at desired strokes per minute to circulate out the kick. Having completed the first circulation of the Driller‟s Method. Using Wait and Weight method. On the second circulation of the Driller‟s method. what happens to the bottom hole pressure? a) Increases b) Decreases c) Stays the same . but hold 200 psi back pressure on drill pipe side with choke b) Add 400 psi to casing pressure and bring pump up to kill rate while using the choke to keep the casing pressure +400 constant c) Bring pump strokes up to kill rate while keeping casing pressure constant by manipulating the choke. if the drill pipe pressure drops below the line of the graph as the kill mud goes down. WELL CONTROL 44. You have taken a kick with a non-return valve (float) in the drill string. After shutting the well in properly, it is best to : a) Use the annulus pressure to calculate the kill weight mud b) Start raising the mud weight 1 ppg per circulation until the well is dead c) Use either the rig pump or cementing unit pump to increase pressure in 100 psi increments until a change is seen on casing gauge d) Pump slowly into the drill pipe. When the pump pressure stabilizes, the float is open. The pumping pressure is the SIDPP used to calculate kill mud 45. A well is being killed using the Driller‟s Method. Original shut-in drill pipe pressure = 500 psi Original shut-in casing pressure = 900 psi After the first circulation, the well is shut in and pressures allowed to stabilize. They then read : Shut-in drill pipe pressure = 500 psi Shut-in casing pressure = 650 psi It is decided not to spend any more time cleaning the hole Which one of the following actions should be taken a) Prepare to use the Wait and Weight method b) Bull-head the annulus until shut-in casing pressure is reduced to 500 psi c) Reverse circulate until shut-in casing pressure is reduced to 500 psi d) Continue with second circulation of Drillers Method (holding casing pressure constant until mud reaches the bit) 46. If the slow pump circulating pressure was not known, and a kick has been taken with the well closed in, how would you find the ICP? a) Bring pump up to the desired rate, while holding the casing pressure 150 psi above the original SICP b) Bring pump up to desired rate, but hold 200 psi back pressure on the drill pipe c) Bring pump up to the desired rate holding casing pressure constant by manipulating the hydraulic choke d) Circulate at desired kill rate but hold casing pressure 100 psi below MAASP 47. The correct gauge to use for calculating the kill weight mud is : a) the gauge on the choke and kill manifold b) the drill pipe pressure gauge on the drillers console c) the casing gauge on the drillers console d) the drill pipe gauge on the remote auto choke panel e) the casing gauge on the remote auto choke panel WELL CONTROL EXERCISE # 6 1. What is the primary function of the weep hole (drain hole, vent hole) on a ram type BOP? a) To show that ram body rubber is leaking. b) To show that the primary mud seal on the piston rod is leaking. c) To show that the Bonnet seals are leaking. d) To show that the closing chamber operating pressure is too high. 2. You only have one inside BOP with an NC 50 (4”1/2 IF) lower pin connection on your rig but the drill string consist of 5” HWDP, and 8” collars. Which one of the following crossovers would you have on the drill floor in case of kick while tripping? a) 6-5/8” reg. Box X 7-5/8” reg. Pin b) NC50 (4-1/2” IF) Pin X 6-5/8” reg. Pin c) NC50 (4-1/2” IF) Box X 7-5/8” reg. Pin d) NC50 (4-1/2” IF) Box X 6-5/8” reg. Pin 3. Two types of valves may be used in the drill string: Type 1 Non return, stab in safety valve or inside BOP Type 2 Fully opening stab in Kelly cock valve or fully opening safety valve Indicate in the table which statement describes the valves. Type 1 Requires the use of key to close Must not run in the hole in the close position Has to be pumped to read “shut-in drill pipe pressure” Will not allow wireline to be run inside the drill string Has potential to leak through the open/close key Easier to stab if strong flow is encountered up the string 4. A BOP stack is configured: Pipe ram / Blind-Shear ram / Pipe ram / Annular, kill and choke lines are connected under the blind-shear rams. Is it possible to kill a well using the Driller's method if; a) The upper pipe rams are closed? b) The blind shear rams are closed? c) The lower pipe rams are closed? 5. A BOP stack is configured: Pipe ram / pipe ram / Blind-Shear ram / Annular, kill and choke lines are connected under the blind-shear rams. a) Can you repair the side outlets with pipe in the hole? b) Can you repair the outlets with no pipe in the hole? c) Is it possible to shut in with drill pipe in the hole and circulate through the drill pipe? d) Can you change blind rams to pipe rams and kill the well? 6. A BOP stack is configured: Drilling spool / Pipe ram / Blind-Shear ram / Annular, kill and choke lines are connected to the drilling spool. a) With drill pipe in hole, can we repair the side outlets? b) With no drill pipe in the hole, can you shut in and repair the Drilling spool? c) With drill pipe in hole, can you circulate through the Drilling spool? Type 2 WELL CONTROL 7. The kill line should enter a stack so that a) The well can be circulated if the blind rams are in use. b) The well can be circulated if the pipe rams are being used. c) Both the above. 8. Which of the following statements are true concerning Ram Packing Elements? a) Reciprocating motion of the pipe increases the wear on seals. b) Closing pipe rams on 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 above. 9. What do the term “6BX” stamped on a flange represent? a) serial number b) pressure rating c) type d) size 10. What is meant by the closing ratio for a ram type BOP? a) Ratio between closing & opening volume. b) Ratio between closing & opening time. c) Ratio of the wellhead pressure to the pressure required to close the BOP. 11. Study the two tables below which contain markings stamped on API flanges and ring gaskets. Each flange (1,2,3 and 4) mates with one of the ring gaskets (A,B,C or D). Write the appropriate flange number in the blanks. Ring Gasket Marking Flange A -CI API BX154 S304-4 B -OES API R57 D-4 C- OES API RX66 S-4 D -CI API BX153 S316-4 Flange Marking 1. 2. 3. 4. OES API 16-3/4 3M RX66 6A 89 300F PSL3 05/91 CI API 3-1/16 15M BX154 CRA 6A 89 250F PSL2 PRL2 08/92 OES API 2-9/16 20M BX153 CRA 6A 89 350F PSL4 PRL4 01/94 OES API 13-5/8 2M R57 6A 89 250F PSL1 PRL1 11/93 Gasket A B C D Flange D. A BOP stack is configured Pipe Ram / Blind-Shear ram / Pipe Ram / Annular. open and close again all rams and the annular. In an area where local legislation requires that BOP equipment must be rated so that maximum anticipated formation pressures do not exceed 75% of BOP equipment pressure ratings. d) To act as a back up system if the annular preventer fails. b) To direct fluid a safe distance away from the rig floor. b) Flange O. Component Annular BOP Ram BOP Volume to Open 27 13 Volume to close 29 15 .D. (Pick four answers) a) Type RX b) Type BX c) Type AX d) Type R oval e) Type R octagonal f) Type CX 13. identify the ring gaskets that are pressure energized. 15. Which dimension from the list below is used to identify the “Nominal Flange Size” a) Throughbore I. From the list below. of ring groove. What is the main function of a diverter? a) To shut in a shallow kick.D. 14. c) Diameter of raised face. d) O. c) To create a back pressure sufficient to stop formation fluids entering the wellbore. e) Bolt circle diameter. Use the table below to calculate the required accumulator volume if company policy is to provide sufficient volume to close.WELL CONTROL 12. what is the minimum acceptable rating for equipment to be used in drilling normally pressure formation to 16000 ft TVD? a) 2000 psi BOP equipment b) 3000 psi BOP equipment c) 5000 psi BOP equipment d) 10000 psi BOP equipment e) 15000 psi BOP equipment 16. b) 60 sec. b) 2 times accumulator volume.WELL CONTROL 17. 19. What is the value of X? a) 30 sec. d) 45 sec. True or False d) The master control valve must be depressed for five seconds then released before operating a BOP function. The API RP53 states that closing time should not exceed X seconds for annular BOPs smaller than 18-3/4". which two gauges show a reduction in pressure? a) Manifold pressure b) Annular pressure c) Accumulator pressure d) Air pressure . Which is the correct definition of the HPU reservoir volume according to API RP53? a) 2 times usable accumulator volume. Decide if the statements are true or false. Which two pressure readings decrease during normal operation of the pipe rams? a) Manifold pressure b) Annular pressure c) Accumulator pressure c) Precharge pressure 21. a) If you operate a function without operating the master control valve that function will not work. True or False c) The master control valve must be held depressed while BOP functions are operated. b) 5 times total accumulator volume . When closing the annular preventer from the remote panel. The following statements relate to the driller‟s remote control BOP control panel located on the rig floor. c) 2 min. True or False b) The master control valve on an air operated panel allows air pressure to go to each function in preparation for you operating the function. True or False 18. 20. Precharge pressure is 1000 psi. identify the most likely problem from the gauge readings observed on the remote control panel. b) Malfunction pressure regulating valve. e) Air pressure to the panel was lost. c) Choke and kill lines can still be operated from the remote panel. What is the total usable fluid volume when the minimum BOP operating pressure is 1. Which of the problems below would not stop the BOP from closing? a) Master control valve was not held down. If the air pressure on the drillers panel reads 0 psi. Annular pressure = = = = psi psi psi psi 25. On a 3000 psi accumulator system. each with a capacity of 10 gallons.WELL CONTROL 22. which of the following statements is true? a) No stack function can be operated from the remote panel. d) The annular preventer can still be operated from the remote panel. In the case below. c) Malfunction hydro-electric switch d) Leaking in hydraulic circuit e) Precharge pressure is to low 23. the manifold setting is 1. f) A bulb has blown on the remote panel. c) Closing line in the BOP was blocked. what are the normal operating pressures seen on the following gauges on the drillers remote control panel?     Air pressure Accumulator pressure.500 psi. . Operating pressure is 3000 psi.200 psi? Answer: gal 24. A BOP operating unit has 8 accumulator bottles. The annular setting is 900 psi. b) All stack function can be operated from the remote panel. 27. On which two gauges on the remote panel would you expect to see reduction in pressure when the annular preventer is being closed? 26. b) Four-way valve did not shift position. a) Everything is OK. Manifold pressure. d) Leak in the hydraulic line to the BOP or in the BOP closing chamber. What is the normal precharge for the accumulator bottles on a 3000 psi accumulator unit? a) 1000 psi b) 3000 psi c) 1200 psi d) 200 psi .WELL CONTROL 28. When drilling. which may be the correct position of the 4-way valves on the BOP accumulator unit? a) open b) close c) neutral d) open or closed depending on BOP stack function 29. 0292 bbls/ft WELL CONTROL DATA SIDPP SICP GAIN = 750 psi = 900 psi = 22 bbls You are recommended to complete a kick sheet to answer the following questions: .WELL CONTROL EXERCISE # 7 Use the Well Data to answer the questions.900 psi Set at 6. WELL DATA Well Depth Kick Off Point End Of Build Bit size Drill Pipe Heviwate Drill Collars Casing 8.500 ft MD 4.5 lbs/ft Capacity = 0.0447 bbls/ft = 0.00874 bbls/ft 61/2” x 213/16” x 820 ft Capacity = 0.447 TVD / 5.01776 bbls/ft 5” OD x 3” ID x 720 ft Capacity = . 320 bbls National triplex 12-P-160 With 61/2” Liners Capacity = 0. 19.554 ft TVD 10.0478 bbls/ft = 0.667 MD 8.5” 5” OD. P110 8. 47 lb/ft.5 ppg.117 bbls/stk PUMP PRESSURE Formation strength test Mud weight in use Surface Volume Pumps Slow Pump Rate 520 psi at 40 spm ANNULAR VOLUMES Drill pipe/HW .000 MD 5.4 ppg 11.0077 bbls/ft 95/8”.Open hole Drill collars .800 MD 1.270 psi w/ 10.000 TVD / 4.Casing Drill pipe/HW .Open hole = 0.175 ft TVD / 6.681” ID 100% Internal yield = 10. What is the Final Circulating Pressure? 4. How many strokes to pump from surface to KOP? 5.WELL CONTROL 1. Calculate the pressure drop per 100 strokes of kill mud pumped inside the string from the EOB to the bit? . What is the Initial Circulating Pressure? 3. How many strokes to pump from surface to the EOB? 7. What is the circulating pressure when kill mud reaches the KOP? 6. How many strokes to pump from surface to bit: 2. What is the circulating pressure when kill mud reaches the EOB? 8. What is the approximate time needed to kill the well? .WELL CONTROL 9. Calculate MAASP after circulation of kill mud? 10. 200 ft MD RKB 12.Casing Drill pipe .Open hole Drill pipe – Riser = 0.5” 5” OD.336 bbls/ft Mud weight in use Pump output WELL CONTROL DATA SIDPP SICP GAIN = 700 psi = 1150 psi = 30 bbls LEAK OFF TEST DATA 3650 PSI with 11 ppg mud . P110 8.681” ID 100% Internal yield = 10.0292 bbls/ft = 0.500 ft MD 1700 ft capacity = 0.360 bbls/ft 1724 ft capacity = 0.01776 bbls/ft 61/2” x 213/16” x 540 ft Capacity = 0. 0.WELL CONTROL EXERCISE # 8 Use the Well Data to answer the questions.900 psi Set at 14.117 bbls/stk PUMP PRESSURE While Drilling Slow Pump Rate Up Riser CLFL with 11 ppg mud 3500 psi at 75 spm (APL = 270 psi) 980 psi at 40 spm (APL = 75 psi) 250 psi at 20 spm (APL = 20 psi) 125 psi at 20 spm 500 psi at 40 spm ANNULAR VOLUMES Drill pipe .0459 bbls/ft = 0. 47 lb/ft.0489 bbls/ft = 0.4 ppg.008 bbls/ft 95/8”.700 ft TVD 16. 19.000 ft TVD – 14.Open hole Drill collars .5 lbs/ft Capacity = 0.0087 bbls/ft 8. WELL DATA Well Depth Marine riser Choke line Bit size Drill Pipe Drill Collars Casing 15. Each question has only one correct answer. 0 ppg 12. Calculate bit to surface time (bottoms up) at 40 spm? a) b) c) d) 155 minutes 234 minutes 60.3 minutes 123 minutes 5.3 ppg 13. What is the total capacity of the drill string? a) b) c) d) 288 bbls 162 bbls 335 bbls 456 bbls 2. What kill mud is required to balance formation pressure? a) b) c) d) 13.4 ppg 16. The ICP (initial circulating pressure) at 40 spm will be approximately? a) b) c) d) 1680 psi 770 psi 2130 psi 1200 psi 7. What is the surface to bit time with the pump running at 40 spm? a) b) c) d) 61 minutes 25 minutes 87 minutes 54 minutes 4.WELL CONTROL 1. The FCP (final circulating pressure) at 40 spm will be approximately? a) b) c) d) approximately 1800 psi approximately 1050 psi approximately 1500 psi approximately 1290 psi .0 ppg 6. Calculate the total annular capacity with the pipe on bottom? a) b) c) d) 722 bbls 443 bbls 987 bbls 323 bbls 3. What is the maximum allowable mud weight? a) b) c) d) 17.5 ppg 16. At 75 spm what is the annular velocity around the drill collars? a) b) c) d) 412 ft/min 210 ft/min 506 ft/min 300 ft/min 13. What would be the circulating pressure while drilling if the pump was decreased to 60 spm? a) b) c) d) 2240 psi 2800 psi 2100 psi 1860 psi 12. What is formation pressure based on the shut in data? a) b) c) d) 10.73 ppg 15.52 ppg 11. What is the ECD on bottom while drilling? a) b) c) d) 12. After reaching FCP it is decided to increase the pump speed to 50 spm.823 psi 6800 psi 7800 psi 6240 psi 10.03 ppg 16.WELL CONTROL 8.0 ppg 19.54 ppg 16.0 ppg 18.0 ppg . What would happen to BHP if the drill pipe pressure is held constant at the original FCP value? a) b) c) d) increase by about 590 psi decrease by about 590 psi remain constant because drill pipe pressure was not changed increase by about 500 psi 9. How many strokes to go from ICP to FCP? a) b) c) d) 1282 stks 1363 stks 1680 stks 2461 stks 17. Not following the the correct pressure schedule.WELL CONTROL 14.433 psi/ft 16.115 psi/ft 0.320 psi/ft 0. How many strokes are required to displace the riser – annulus a) b) c) d) 7034 strokes 4882 strokes 3453 strokes 1234 strokes . Calculate the MAASP? a) b) c) d) 2620 psi 2524 psi 2368 psi 1356 psi 18. What is the approximate length of the influx? a) b) c) d) 1027 ft 850 ft 653 ft 342 ft 15. What is the capacity of the choke line: a) b) c) d) 15 bbls 12 bbls 23 bbls 28 bbls 20.465 psi/ft 0. The gradient of the influx is about? a) b) c) d) 0. the BHP could be high or low causing losses or another influx. a) True b) False 19. If the well had been shut in with 0 psi on the drill pipe pressure and no float in the string and a SICP of 300 psi.9 ppg 12.5 ppg Answer the following gauge questions as the well is killed using the Drillers method. what mud weight would have required to kill the well? a) b) c) d) 12. TO TA L STR O KES 90 0 1000 1 100 80 0 70 0 600 5 00 400 3 00 200 1 00 1900 1200 1300 1 20 700 6 00 5 00 4 00 300 1400 15 00 160 0 900 10 00 1100 800 1 200 13 00 PSI PSI 14 00 1 500 1600 1 700 1700 1 800 200 18 00 10 0 1 900 PU M P SPEED D R ILLPIPE PR E SSU R E 40 C AS IN G P R ESSU R E 1 6 80 O P EN C H O KE P O S IT IO N C LO S E 590 22.5 ppg 15.WELL CONTROL 21.4 ppg 14. What should you do? a) b) c) d) e) open the choke a little close the choke a little nothing everything looks alright Possible plugged nozzle Possible choke plugging TO T A L S TR O K E S 900 100 0 1 100 800 70 0 60 0 5 00 40 0 300 2 00 1 00 1 900 120 0 130 0 500 70 0 60 0 5 00 40 0 300 140 0 1500 16 00 900 100 0 11 00 800 120 0 130 0 PSI PSI 1400 1 500 160 0 170 0 170 0 1800 2 00 1 800 100 1 900 PUMP SPEED D R ILLP IP E P R E S S U R E 40 C A S IN G P R E S S U R E 1620 O PE N CH O KE P O S ITIO N C LO S E 700 . The kill operation has started. This is what the choke control console shows. The pit levels are still reported to be increasing slightly.WELL CONTROL 23. a) b) c) d) e) open the choke a little close the choke a little possible choke washout possible choke plugging nothing everything looks alright TOTAL STROK ES 90 0 1000 11 00 8 00 70 0 600 500 400 300 200 100 1 900 1200 1 300 5600 700 600 50 0 400 300 140 0 1500 1600 900 1000 1100 800 12 00 1300 PSI PSI 1400 15 00 1600 1700 1 70 0 1800 200 180 0 100 1900 P UM P SPE ED DR ILLPIPE PRE SSU RE 40 CASIN G PRESS UR E 1400 OP EN CHO KE PO SITION CL OSE 1720 . Pit room calls up to confirm a .5 bbl rise in the level. This is what you see on the panel. What should you do? a) b) c) d) e) open the choke a little close the choke a little increase the pump speed decrease the pump speed nothing everything looks alright TO TA L STR O KES 900 1000 1100 8 00 700 600 500 400 300 200 100 1900 1200 1 300 4550 700 600 500 400 300 1400 1500 1600 900 1000 1100 800 1200 1300 P SI PS I 1400 1500 1600 1700 1700 1800 200 1800 100 1900 PU M P SPEED D R ILLP IPE PR E SSU R E 40 CASIN G PR ESSU R E 1 6 80 O PEN CH OK E PO SITIO N C LOS E 1 4 80 24. Not hearing anymore gas.WELL CONTROL 25. Experienced a sudden increase in casing pressure over the last 100 strokes. What are you going to do now? a) b) c) d) e) open the choke a little close the choke a little possible nozzle plugging possible choke plugging nothing everything looks alright TO TAL STRO KES 900 1000 1100 800 700 600 500 400 300 200 100 1900 1200 1300 6220 700 600 500 400 300 1400 1500 1600 900 1000 1100 800 1200 1300 PSI PSI 1400 1500 1600 1700 1700 1800 200 1800 100 1900 PUMP SPEED D R IL L P IP E P R E S S U R E 40 C A S IN G P R E S S U R E 1680 OPEN CHOKE POSITION CLOSE 1 40 26. How are things going? a) b) c) d) e) open the choke a little close the choke a little casing pressure should be 0 possible choke wash out good everything looks alright TO TA L S TR O K E S 90 0 1000 1 100 80 0 70 0 600 500 400 3 00 200 1 00 1900 120 0 1300 6300 700 600 5 00 400 30 0 1400 1 500 160 0 900 10 00 110 0 80 0 1 200 13 00 PSI PSI 14 00 150 0 1600 1 700 1700 1 800 200 18 00 1 00 1 900 PUMP SPEED D R ILLP IP E P R E S S U R E 00 C A S IN G P R E S S U R E 700 O P EN C H O KE P O S IT IO N C LO S E 700 . Gas is venting and pit levels are reported to be falling. What should you do? a) b) c) d) e) open the choke a little close the choke a little increase the pump speed decrease the pump speed nothing everything looks alright TOTAL STROK ES 90 0 1000 11 00 8 00 70 0 600 500 400 300 200 100 1 900 1200 1 300 250 700 600 50 0 400 300 140 0 1500 1600 900 1000 1100 800 12 00 1300 PSI PSI 1400 15 00 1600 1700 1 70 0 1800 200 180 0 100 1900 P UM P SPE ED DR ILLPIPE PRE SSU RE 40 CASIN G PRESS UR E 1620 OP EN CHO KE PO SITION CL OSE 140 . What should you do? a) b) c) d) e) Check MW = 13.WELL CONTROL 27. Got the pump to kill speed and have just reset the stroke counters having pumped the surface line. Shut back in.3 ppg Check MW = 16 ppg Reset stroke counter Bleed off pressure to 0 nothing everything looks alright TO TA L S TR O K ES 900 1000 1100 800 70 0 600 500 400 300 200 100 1900 1 200 1300 0000 700 600 500 400 300 1400 1500 16 00 900 1000 1100 800 120 0 1 300 PSI P SI 1400 1500 1600 170 0 1700 1800 200 1800 100 1900 PU M P SPEED D R ILLP IPE PRES SU R E 40 C AS IN G PR ESSU R E 1 7 80 O P EN CH O K E PO SITIO N C LOS E 236 28. How are things going? a) b) c) d) e) open the choke a little close the choke a little increase the pump speed possible choke wash out good everything looks alright T O TA L S TR O K E S 90 0 1000 1 100 80 0 70 0 600 5 00 400 3 00 200 1 00 1900 1200 1300 1720 700 6 00 5 00 4 00 300 1400 15 00 160 0 900 10 00 1100 800 1 200 13 00 PSI PSI 14 00 1 500 1600 1 700 1700 1 800 200 18 00 10 0 1 900 PUMP SPEED D R ILLP IP E P R E S S U R E 00 C A S IN G P R E S S U R E 220 O P EN C H O KE P O S IT IO N C LO S E 700 . Drill pipe pressure is falling but casing pressure stay constant.WELL CONTROL 29. Pump room is on the phone saying pit levels are OK. What are you going to do now? a) b) c) d) e) open the choke a little close the choke a little possible nozzle plugged possible choke plugged nothing everything looks alright TO TAL STRO KES 900 1000 1100 800 700 600 500 400 300 200 100 1900 1200 1300 980 700 600 500 400 300 1400 1500 1600 900 1000 1100 800 1200 1300 PSI PSI 1400 1500 1600 1700 1700 1800 200 1800 100 1900 PUMP SPEED D R IL L P IP E P R E S S U R E 40 C A S IN G P R E S S U R E 1430 OPEN CHOKE POSITION CLOSE 1 40 30. WELL CONTROL 31. Company man wants to know how things are going. What do you tell him? a) b) c) d) e) open the choke a little close the choke a little possible choke plugging possible nozzle plugging nothing everything looks alright . Had to shut in because of a pump. What do you thing? a) b) c) d) e) Drill pipe pressure is too low Casing pressure is too high Drill pipe pressure is too high Casing pressure is too low Everything looks alright TO TA L S TR O K ES 900 1000 1100 800 70 0 600 500 400 300 200 100 1900 1 200 1300 2480 700 600 500 400 300 1400 1500 16 00 900 1000 1100 800 120 0 1 300 PSI P SI 1400 1500 1600 170 0 1700 1800 200 1800 100 1900 PU M P SPEED D R ILLP IPE PRES SU R E 40 C AS IN G PR ESSU R E 1 0 50 O P EN CH O K E PO SITIO N C LOS E 130 32. Back up to kill speed. c) Stop drilling and put all function in block one at a time until the flow stops. 4. which of the following is true? a) SPM valve will operate in both pods.WELL CONTROL EXERCISE # 9 1. . but all gauges and the flow meter remain static. an alarm goes off indicating low accumulator pressure and the flow meter Indicates a rapid loss of fluid. b) Call and wait for the subsea engineer. 3. From which position in the hydraulic circuit is readback pressure taken? a) Upstream of the regulator in the pod? b) The regulator itself? c) Down stream of the regulator in the pod? 6. b) SPM valve will operate only on the active pod. The best course of action is: a) Stop drilling and shut the well in. What is the principal reason for fitting ram locking devices such as wedgelocks or Poslocks to a subsea stack? a) To give additional force when closing in. 2. c) To lock the BOP stack to the well head and lock the lower Marine Riser Package to the BOP stack. He Pushes the “Annular Close” button and the pilot light changes. b) Stop drilling and call subsea engineer. d) Close the lower annular preventer. thus reducing delay times. A driller needs to close in a flowing well with drill pipe in a subsea BOP stack. What is his best option? a) Change pod and try again. d) None of the above. b) To lock the ram in the closed position and maintain the shear rams locked during disconnect. While drilling. c) Send assistant driller to manually operate the 4-ways valve on the Hydraulic Control Manifold to close the annular. How much time is allowed for subsea ram type preventer to close in API RP53? a) b) c) d) 30 seconds 45 seconds 60 seconds 50 seconds 5. When a function is operated. c) The SPM valve will operate after the function is complete. Which two statements are true with respect to shuttle valves on a subsea stack? a) The shuttle valves automatically seal any hydraulic leaks in the selected pod. Which two statements are true with respect to the Pilot System? a) The fluid in the Pilot System flows continuously while a function on the BOP takes place. pressure will be vented from the line previously pressurised. c) The shuttle valves are pilots operated. Name 3 potential causes of riser collapse: . b) If the valve is shifted to the center or “block” position. d) Memory Function reminds the driller to engage Wedge Locks before hanging off. Which of the following statements is true regarding to the use of “manipulator” type 4 Ways valve used in subsea hydraulic BOP control systems. pressure will be trapped in the line previously pressurised. d) The shuttle valves allow the retrieval of a malfunctioning pod without losing hydraulic BOP control. d) The Pilot system is a closed dead-end system. b) The shuttle valves prevent communication between the selected system and the redundant system. 8. What is the purpose of the "Memory Function" on electric control panels? a) Memory Function indicates a malfunction by giving permanent light on the alarm panel after an alarm has been acknowledged and the audible alarm has stopped. c) The Pilot System controls the position of all shuttle valves on the BOP stack directly. e) Pilot fluid consists of potable water. a) If the valve is shifted to the center or “block” position. The subsea hydraulic BOP control system is divided into a Control System and a Pilot System. water-soluble concentrate and glycol. 11. c) Memory Function indicates the previous position before “Block position” of three position functions. 10. b) The Pilot System dumps fluid to the sea at every operation of BOP functions. b) Memory Function reminds the driller to add anti-freeze fluid when the temperature drops below a set level.WELL CONTROL 7. 9. a) true b) false 19.WELL CONTROL 12. a) true b) false 18. What is the purpose of sub-sea stack mounted bottles? a) b) c) d) to minimize the time to operate any BOP function to maximize the time to operate any BOP function to minimize the time to operate annular type preventer to optimize the time to operate ram type preventer The drillers BOP panel has gauges for pilot and readback pressure for the manifold and annular pressure. Read back pressure is mesured at the output from the sub sea regulator a) true b) false 15. Pilot pressure and readback pressure should normally be the same. Answer true or false to the following statements: 13. a stand pipe pressure of 65 psi was recorded. a) true b) false 14. You can pump down the choke line taking return up the riser. You can pump down the drill string taking returns through the riser and then close the annular and take returns through the choke line. Pilot pressure is measured at the out put of the surface regulator a) true b) false Answer true or false in each case to measure Choke Line Friction Loss (CLFL): 16. While pumping down the choke line at 150 gpm taking returns through the riser with 9 ppg mud in 750 feet water with 60 feet air gap. You need to know the length of the choke line. Estimate CLFL: a) b) c) d) 30 psi 65 psi 351 psi 143 psi . a) true b) false 17. APL is 10 psi a) b) c) d) 8. What would be the new CLFL if the mud weight is increased to 13. circulating pressure was now 600 psi. Casing shoe is 600 ft RKB. Air gap is 80 ft. What are the CLFL? a) b) c) d) 375 psi 975 psi 600 psi 225 psi 22. While pumping down the drill string and up the riser.7 ppg 11.5 psi 132 psi 234 psi 21.445 psi/ft) drilling without a riser. What is the BHP during connections? a) b) c) d) 450 psi 474 psi 550 psi 574 psi . Water depth is 220 ft. a circulating pressure of 375 psi was recorded. Calculate the Maximum Allowable Mud Weight with the following data: Hole size 17 ½”. Air gap is 60 ft and TD / TVD is 1350 ft RKB. Sea water is . The annular was closed and returns taken through a wide open choke.WELL CONTROL 20.45 ppg 10.65 psi/‟ft. A semi is in 650 ft of water (.455 psi/ft.5 ppg (use data from Q-19) a) b) c) d) 65 psi 97.7 ppg Water depth Air gap Well depth 23. Overburden is .77 ppg 9. 23 ppg 2. water depth is 1523 ft. sea water is . hat increase in mud weight is required to offset this? a) b) c) d) 1. TVD / TD is 2250 ft RKB and MW is 9. What would be the reduction in BHP if the riser were lost or removed? a) b) c) d) 30 psi 65 psi 95 psi no reduction 26.465 psi/ft.67 ppg 2.34 ppg 1.9 ppg mud? a) b) c) d) 45 bbls 93 bbls 157 bbls 173 bbls Air gap Water depth Well depth 25.WELL CONTROL 24. What surface volume would 2 bbl of gas trapped in a sub sea BOP at 1900 ft water depth have if released and allowed to migrate through the riser filled with 12.78 ppg . Air gap is 70 ft. A semi is drilling top hole with a riser and diverter installed connected to 30” casing.7 ppg. How many (.9 ppg water depth=1342 ft a) b) c) d) 0 psi 35 psi 65 psi 90 psi 30. The recommended response time for sub sea BOP is: Rams to close in less than: Annular should not exceed: Time to unlatch LMRP should not exceed: seconds seconds seconds 28. How can gas trapped in a subsea BOP be safely circulated out? 29.115bbl/st) strokes will it take to displace a 16” x 5” riser/drillpipe annulus (200 ft long)? a) b) c) d) 290 strokes 390 strokes 490 strokes 190 strokes .4 ppg KMW=10.WELL CONTROL 27. By how much would BHP change if a well was inadvertently opened before displacing riser to kill mud? MW=10. Place the number next to the component in the list provided.WELL CONTROL 31. The following drawing shows components of a subsea hydraulic control system. . Each component has a number. WELL CONTROL Using the schematic diagram of a hydraulic valve. manual function only remote function only air operated only manual or remote function 35. 2 3 4 8 33. a. answer the following question: 32. True b. b. In the center or block position. Manipulator 36. 8 34. d. the valve vents fluid lines to tank. Terminator b. 4 d. b. How many positions can the valve be placed in: a. How many active ports does the valve have? a. 2 b. d. c. Selector c. c. What is the name of this valve? a. 3 c. Can the valve be operated by: a. false . d. If the riser had a collapse pressure of 500 psi. b. If the choke line is filled with sea water and the fail safe valves are opened.WELL CONTROL WELL DATA: Well depth: 10. c. c.4 ppg 5. b. What mud weight increase is required to balance the well if the riser is to be removed? a.1 ppg 1.3 ppg Water depth Well depth 37. 2. d. how far could the mud level fall before seawater collapses the riser? a. if the riser is lost in bad weather. c.445 psi/ft 13. d. d. c. b.3 ppg 13.3 ppg 38. 1083 ft 1183 ft 1283 ft 1383 ft . what would be the the casing pressure read? a. b. 545 psi 945 psi 60 psi 245 psi 39. what would be the bottom hole pressure reduce by? a. 350 psi 500 psi 480 psi 571 psi 40.000 ft MD Air gap Air gap: Water depth: Sea water gradient: Mud weight: 60 ft 2150 ft . A BOP drill was conducted and the well shut in on the upper annular preventer.657 ft TVD RKB 12. c. If the riser has a collapse pressure of 450 psi. d. 113 bbls 123 bbls 133 bbls 143 bbls 1500 ft 1480 ft 12. a. you must add the choke line friction to the slow circulating rate: a. To find ICP.445 psi/ft of sea water? a. If a function is made to close the hang off rams and your fluid counter continues to register fluid movement after the correct closing volume has gone passed. The rig has an air gap of 80 ft. d. continue 42.2 ppg 14.5 ppg 11.7 psi . The hydraulic fluid system used to operate the subsea BOP‟s consist of potable water and additives. Call the subsea engineer and let him sort it out Close another set of rams Put the operating unit into block position Everything is OK. calculate the expanded gas volume that would be at surface if 2 barrels of gas had remained trapped under the rams and was released into the riser when the well was opened back up after a successful operation? Well data: Choke line length: Riser length: Kill mud weight: Drilling mud: Atmospheric pressure: a. b. what would you consider doing? (1 answer) a.WELL CONTROL 41. True b. True b. c. False 43. Using the following data. b. 1091 psi 1191 psi 1291 psi 1391 psi 45. c. how far would the mud level fall before it collapse if you are working in 1600 ft of . b. False 44. d. 73 gals 47. c.WELL CONTROL 46. Decrease c. what effect would this have on the usable fluid? a. 5. If accumulator bottles were taken to the seabed with the same precharge as surface bottles. Increase b. Calculate the usable fluid in a 10 gallons bottle if the maximum pressure is 3000 psi.00 gals 3. Same volume as surface volume .34 gals 6.63 gals 1. b. the mimimum is 1500 psi and the pre charge is 1000 psi? a. d. The wait and weight method will always result in lower casing shoe pressures. a) True b) False 4. The Driller‟s method of well control will result in higher casing shoe pressures if the open hole volume is less than the drill pipe capacity. a) True b) False . a) True b) False 2. but to adjust the Drill Pipe pressure you have to change the pump rate. The wait and weight will result in lower casing shoe pressure if the open hole volume is less than the drill pipe capacity. a) True b) False 6. a) True b) False 7. The Casing (Annulus) gauge is always slower to react to any choke adjustment then the Drill Pipe Pressure. The choke is used to adjust Casing (Annulus) pressure. When using the choke to adjust pressure it is the Casing (Annulus) gauge that reacts to the adjustment before the Drill Pipe Gauge. a) True b) False 3.WELL CONTROL EXERCISE # 10 1. The Driller‟s method of well control will result in the same pressure on the casing shoe if the open hole volume is less than the drill pipe capacity. a) True b) False 5. g) Line up suction to kill mud. a) Bring pump up to kill speed holding casing pressure constant. f) Bring pump up to kill speed holding casing pressure constant. Place the following statements in the correct order if you are using the Driller‟s Method. Place your answers in order below : 1st __________ 3rd __________ 5th __________ 7th __________ 2nd ____________ 4th ____________ 6th ____________ 8th ____________ . j) Bring pump up to kill speed holding drill pipe pressure constant. d) Maintain drill pipe pressure constant until kill mud reaches surface.WELL CONTROL 8. NOTE : There are 3 INCORRECT statements in the list. h) Maintain casing pressure constant until kill mud is pumped to surface. e) Shut-in the well and check both SICP and SIDPP are approximately equal. b) Maintain casing pressure constant until kill mud is at the bit. i) Maintain casing pressure constant for complete circulation. c) Maintain pumping pressure constant until influx is out. k) Shut in well and check for zero shut in pressure. The well is already shut in. The well is already shut in. NOTE : There are 3 INCORRECT statements in the list. a) True b) False . annulus pressures are kept lower than with the Driller‟s method. 1rst ________ 2nd _________ 3rd _________ 4th _________ 10. In the Wait and Weight method . a) True b) False b. a) Bring pump up to speed holding drill pipe pressure constant. a) True b) False c.WELL CONTROL 9. e) Allow drill pipe pressure to fall gradually from ICP TO FCP as kill mud is pumped from suction pit to shaker. In the Wait and Weight method there are less calculations compared to the Driller‟s method. c) Bring pump up to speed holding casing pressure constant d) Maintain drill pipe pressure constant as kill mud pumped from bit to surface. In the Wait and Weight method the casing pressure should be kept constant during 2 nd circulation. b) Allow drill pipe pressure to fall from ICP to FCP as kill mud is pumped to bit. Which of the following statements are True or False concerning the Wait and Weight method? a. f) Shut down and check the well is dead. Place the following statements in the correct order if you are using the Wait and Weight to kill a well. In the Wait and Weight method the well is dead when you reach FCP. a) True b) False i. a) True b) False f. a) True b) False . In the Wait and Weight method the drill pipe pressure is held constant throughout. after surface to bit strokes have been pumped if you shut in the well. The wait and weight method must be used if insufficient barite is on board. The Wait and Weight method does not require you draw a graph or step down chart. In the Wait and Weight method the drill pipe pressure should read zero. The Wait and Weight is the preferred method if MAASP is critical and the open hole capacity is greater the drill string capacity. a) True b) False j. Only the Wait and Weight method the drill pipe pressure is held constant throughout. a) True b) False e. a) True b) False g.WELL CONTROL d. a) True b) False h. Concurrent Method C. Which method would you choose? DRILLERS OR WAIT AND WEIGHT 13. Will the Wait and Weight method give lower shoe pressures than the Driller‟s method? TVD Shoe Depth Surface to Bit Strokes Bit to Shoe strokes Bit to surface SIDPP SICP Present Mud Wt. Wait and Weight method .304 stks 6. MAASP Pit Gain = = = = = = = = = = = 10. Kill Mud Wt. A.WELL CONTROL 11.3 11.629 1.300 30 bbls ft stks ppg ppg psi Answer – Yes or No b. Link the following by matching up the correct number to the correct letter. Based on the following information : a.830 ft 1. 3.3 1. 1. Most calculations moderate annulus pressures. Company policy states “when killing a well you will always attempt to kill the well using a method that minimizes the pressure on the stack and upper casing”. Based upon same information above : Will the Wait and Weight Method give lower surface pressures than the Driller‟s Method? Answer – Yes or No 12. Less calculations highest annulus pressures. 2. One circulation lower annulus pressures. Driller Method B.480 stks 500 psi 800 psi 10.000 8. WELL CONTROL 14. place 3 of them correctly in the blanks provided : A B C D E F Drillers Bring pump up to speed holding drill pipe pressure constant Constant bottom hole pressure Concurrent Bring the pump up to speed holding the casing pressure constant Drill pipe pressure constant The main principle of well killing methods is to maintain _____________________ The most common methods are the Wait and Weight and ____________________ method In both methods you must ______________________ when starting up. Maintain the drill pipe pressure constant when starting up the pump to kill speed. So long as the correct kill procedures are followed that part of the wellbore which is below a gas influx will have an increasing pressure. b. Which of the following statements are true ? a. b. (Drillers Method) a. So long as the correct kill procedures are followed that part of the wellbore which is below a gas influx will have a constant pressure. So long as the correct kill procedures are followed that part of the wellbore which is above a gas influx will have a constant pressure. Select one of the following statements that is TRUE concerning wellbore pressures when circulating a gas influx to surface. 16. c. . Pump must be brought up to speed holding casing pressure constant c. Surface line volume will affect the point at which kill mud will increase mud hydrostatic on bottom. From the statements A to F below. TRUE STATEMENTS ARE____________________and ___________________________ 15. Surface line volume does not need to be considered when starting to kill a well d. Pressure at any point above a gas influx is rising.WELL CONTROL 17. EFFECT IN PRESSURE LOCATIONS Increase Decrease Stays the same Increase at first Then remains constant Gas Bubble Surface Casing Gauge Casing shoe Bottom Hole At any point below gas bubble At any point above Gas bubble . Pressure at any point above a gas influx is decreasing. A gas is being circulated up the hole during a kill operation what effect will this have on the pressures at the various locations listed. Pressure at any point below a gas influx is decreasing. c. b. d. Pressure at any point above a gas influx is constant. 18. e. Which one of the following statements is true concerning wellbore pressure during the 1 st circulation of the Driller‟s method? a. Pressure within a gas bubble remains constant. 000 psi.200 psi on drill pipe. Increase b. Casing pressure is 1. By using the spm versus pump pressure equation the spm for 1. Decrease c. Decrease c.500 psi would be 34 spm.200 psi at 30 spm. c. Increase b. Once pump is up to speed note the drill pipe pressure and hold that constant for rest of 1st circulation. You decide to open the choke to bring the drill pipe pressure back to 1. During the first circulation of the Driller‟s method you decided to hold casing pressure constant. You think that the nozzles may be blocking. Very quickly the drill pressure increases to 1. Pump rate still holds at 30. Increase b. Stay in the same. 21. the drill pipe pressure is 1. Decrease c. 20. In the previous example you decided to stop the pump and close the choke before making a decision. What would happen to bottom hole pressure ? a.200 psi with 30 spm. What would you do? a. What has happened to bottom hole pressure ? a.WELL CONTROL 19. What would happen to bottom hole pressure ? a.500 psi drill pipe pressure. Therefore you bring pump up to 34 spm and adjust choke to obtain 1. Stay the same . Stay the same 23. Start pump up to 30 spm and manipulate choke to get 1. d. Stay the same 22. Increase mud weight by an amount equal to 300 psi. Increase b. Decrease c. During the second circulation of the Driller‟s method you decide to hold casing pressure constant until kill mud is at the bit.500 psi but no change in casing pressures. What would happen to bottom hole pressure ? a. b. Start pump up to 30 spm holding the choke pressure constant. While killing the well on the 1st Circulation of the Driller‟s method. During the second circulation of the Driller‟s method you hold drill pipe pressure constant until kill mud is at the bit. P. gauges rising d. matches _____________________________ b. Match the cause to the problem. Bit plugging 3. matches _____________________________ d. gauge falling CAUSE 1. Bottom hole pressure Casing shoe pressure Shut in casing pressure Gas bubble pressure . d. Both gauges falling b. Both gauges rising c. Nozzle / pipe washout a. matches _____________________________ 25. D. PROBLEM a.WELL CONTROL 24. Which of the following pressures do not increase with gas migration ? a. D. Below is a list of problems.P. Choke plugging 2. c. b. matches _____________________________ c. Choke washout 4. b. d. The following graphical diagrams show the approximate changes in pressure at certain points in the well during the Wait and Weight method. Surface casing pressure Casing shoe pressure Bottom hole pressure Drill pipe pressure NOTE / Pressure reading are not drawn to scale.WELL CONTROL 25. c. Answer: Answer: Answer: . a. WELL CONTROL Answer. . 000 ft 0.006 bbl/ft 0.000 ft 1.WELL CONTROL EXERCISE # 11 Well Data: Measured depth: TVD: Hole size: Air gap: Water depth: Drill collars 6 ½: Capacities: Drill pipe capacity: Drill pipe metal displacement: Drill pipe closed end displacement: HWDP (1000 ft) Drill collar capacity: Choke line (1100 ft): Marine riser: Annular capacities: Open hole / drill collar: Open hole / drill pipe: Casing / drill pipe: Pre-recorded data: Current mud weight: Casing 9 5/8 – 47 ppf set at (MD/TVD): Fracture gradient at shoe: SCR @ 40 SPM ( riser) SCR @ 40 SPM ( choke line) Pump output: Surface lines: Kick data: SIDPP: SICP: Pit gain: 100 psi 350 psi 10 bbls 16.91 psi/ft 500 psi 750 psi 0.000 ft 8½“ 70 ft 1.00650 bbl/ft 0.0505 bbl/ft 0.39 bbl/ft 15.0088 bbl/ft 0.0459 bbl/ft 0.01776 bbl/ft 0.500 ft 15.000 ft .02426 bbl/ft 0.0 ppg 9.0292 bbl/ft 0.119 bbl/stk 17 bbls 0.00768 bbl/ft 0. c. What kill mud weight is required? a. How many strokes does it take to complete one circulation through the choke line? a. 4382 strokes 6523 strokes 1363 strokes 3. b. 16. 16. How many strokes are required to displace the riser? a. c. c. 1954 strokes 2054 strokes 2154 strokes 2254 strokes 4.13 ppg 19. d. b. What is the MAASP? a. c. d.5 ppg 18. d.13 ppg 17. c. What is the MAMW? a. c. b. 2367 strokes 1384 strokes 2732 strokes 1199 strokes 5.5 ppg 19. d. 402 psi 502 psi 602 psi 702 psi 2. b.13 ppg . b.506strokes 7.5 ppg 17. 7940 strokes 5234 strokes 9876 strokes 3576 strokes 6. c. d. d.5 ppg 3. How many strokes does it take to pump from surface to bit? a. d.WELL CONTROL 1. b. How many strokes does it take to pump from bit to shoe? a.13 ppg 18. b. 504 psi 604 psi 306 psi 806 psi 10. 50 psi 100 psi 150 psi 200 psi 12. What is the FCP? a. What is the ICP? a. The capacity of the drill string The TVD of the casing shoe The presence of a float in the string The pore pressure of the formation being tested The mud density The TVD of the well The Annular pressure losses The MD of the casing The accurate hole capacity . What informations are essential to calculate the fracture pressure of a leak off test? a. b. d. d. b. g. b. What is the MAASP after killing the well? a. d. c.WELL CONTROL 8. i. d. What is the initial dynamic pressure? a. f. c. 400 psi 500 psi 600 psi 700 psi 9. d. b. c. h. c. c. 456 psi 756 psi 641 psi 985 psi 11. b. e. 500 ft TVD 12.800 psi w/ 11.Casing Drill pipe/HW .0459 bbls/ft = 0.01776 bbls/ft 5” OD x 3” ID x 1500 ft Capacity = .500 MD 1.5 ppg 12.000 ft MD 4.5 lbs/ft Capacity = 0.000 MD 5.088 bbls/stk PUMP PRESSURE Slow Pump Rate Riser CLFL 700 psi at 40 spm 250 psi at 40 spm Choke Line Riser Formation strength test Mud weight in use Surface Volume Pumps ANNULAR VOLUMES Drill pipe/HW . WELL DATA Well Depth Kick Off Point End Of Build Bit size Drill Pipe Heviwate Drill Collars Casing 7.008 bbls/ft 95/8”. 47 lb/ft.WELL CONTROL EXERCISE # 14 Use the Well Data to answer the questions. 1.900 psi Set at 5.000 TVD / 4.050 ft TVD / 5.000 ft – Riser / DP: .000 ft – Capacity: .5” 5” OD.500 TVD / 7. P110 8.009 bbls/ft 61/2” x 213/16” x 700 ft Capacity = 0.000 MD 8.681” ID 100% Internal yield = 10.5 ppg.0505 bbls/ft = 0.335 bbls/ft 1.000 bbls National triplex 12-P-160 With 51/2” Liners Capacity = 0.Open hole Drill collars . 19.03 bbls/ft WELL CONTROL DATA SIDPP SICP GAIN = 800 psi = 900 psi = 20 bbls You are recommended to complete a kick sheet to answer the following questions: .008 bbls/ft 1.Open hole = 0. What is the Final Circulating Pressure? 3. How many strokes are required to pump kill mud from KOP to EOB? .WELL CONTROL 1. What is the MAASP with the current mud weight? 6. How many strokes are required to pump kill mud from surface to KOP? 7. What Kill Mud weight is required? 4. What is the Maximum allowable fluid density? 5. What is the Initial Circulating Pressure at 40 spm? 2. What is the pressure reduction per 100 strokes surface to KOP? 8. What is the pressure reduction per 100 strokes KOP to EOB? 10. what is the circulating pressure? 14. what would be the SIDPP? 15. When kill mud reaches the KOP. What is the pressure reduction per 100 strokes EOB to bit? 12. How many strokes are required to pump kill mud from EOB to bit? 11. what is the circulating pressure? 13. What is the total strokes to pump kill kud to the bit? . What is the drill string volume? 16. When kill mud reaches the EOB.WELL CONTROL 9. If the well had to be shut in when kill mud reaches the KOP. WELL CONTROL 17. What is the marine riser – DP capacity? 18. Approximately, how many strokes are required to fill the choke line? 19. What should be the approximate pressure on the casing gauges when the pump reaches 40 SPM? 20. What is the MAASP with the current mud weight (dynamic conditions)? WELL CONTROL EXERCISE # 15 Use the Well Data to answer the questions. WELL DATA Well Depth Kick Off Point End Of Build Bit size Drill Pipe Drill Collars Casing 10,000 ft TVD 14 ,000 ft MD 3,500 TVD / 3,500 MD 4,000 TVD / 4,500 MD 8.5” 5” OD. 19.5 lbs/ft Capacity = 0.01776 bbls/ft 61/2” x 213/16” x 500 ft Capacity = 0.007 bbls/ft 95/8”, 47 lb/ft. P110 8.681” ID 100% Internal yield = 10,900 psi Set at 6,000 ft TVD / 7,000 MD 580 ft – Capacity: .008 bbls/ft 580 ft – Riser / DP: .335 bbls/ft 1,500 psi w/ 9.8 ppg 10 ppg. 274 bbls National triplex 12-P-160 With 6” Liners Capacity = 0.099 bbls/stk PUMP PRESSURE Choke Line Riser Formation strength test Mud weight in use Surface Volume Pumps Slow Pump Rate Riser CLFL 520 psi at 40 spm 100 psi at 40 spm ANNULAR VOLUMES Drill pipe/HW - Casing Drill pipe/HW - Open hole Drill collars - Open hole = 0.0489 bbls/ft = 0.0459 bbls/ft = 0.03 bbls/ft WELL CONTROL DATA SIDPP SICP GAIN = 500 psi = 650 psi = 11 bbls You are recommended to complete a kick sheet to answer the following questions: WELL CONTROL 1. What is the Initial Circulating Pressure at 40 spm? 2. What is the Final Circulating Pressure? 3. What Kill Mud weight is required? 4. What is the Maximum allowable fluid density? 5. What is the MAASP with the current mud weight? 6. How many strokes are required to pump kill mud from surface to KOP? 7. What is the pressure reduction per 100 strokes surface to KOP? 8. How many strokes are required to pump kill mud from KOP to EOB? What is the drill string volume? 16.WELL CONTROL 9. If the well had to be shut in when kill mud reaches the KOP. What is the pressure reduction per 100 strokes KOP to EOB? 10. What is the marine riser – DP capacity? . What is the pressure reduction per 100 strokes EOB to bit? 12. When kill mud reaches the KOP. what would be the SIDPP? 15. When kill mud reaches the EOB. How many strokes are required to pump kill mud from EOB to bit? 11. what is the circulating pressure? 14. What is the total strokes to pump kill kud to the bit? 17. what is the circulating pressure? 13. WELL CONTROL 18. Approximately. What should be the approximate pressure on the casing gauges when the pump reaches 40 SPM? 20. What is the MAASP with the current mud weight (dynamic conditions)? . how many strokes are required to fill the choke line? 19.