IWCF Well Control
Equipment
Equipment Contents
Section I BOP Stack configuration
Section II Diverters and Annular Preventers Section III Ram Preventers
Section IV API Flanges
Section V inside BOP and valves Section VI Choke Manifold
Section VII Mud Gas separator and Vacuum degasser Section VIII Volumes and Testing
Gulf Technical & Safety Training centre Page 2 of 137
Section I
BOP Stack Configuration
1. Using the BOP configuration shown below answer the following questions.
a. With drillpipe in the hole, is it possible to shut the well in under pressure and repair the side outlets on the drilling spool?
A. Yes B. No
b. With no drill pipe in the hole, is it possible to shut the well in under pressure and repair the drilling spool?
A. Yes B. No
c. Is it possible to shut the well in with drill pipe in the hole and circulate through the drill pipe?
A. Yes B. No
d. With drill pipe in the hole, and the well shut in under pressure with the annular preventer, is it possible to circulate through the kill line and choke line?
A. Yes B. No
RAM BLIND SHEAR RAM
SPOOL ANNULAR HCR HCR Choke Line Kill Line
e. With no drillpipe in the hole, is it possible to shut the well in under pressure using the annular preventer and change pipe rams to blind rams?
A. Yes B. No
f. While replacing the ring gasket on the drilling spool choke line flange the well starts to flow. There is no drill pipe in the hole. Can the well be shut in under pressure?
Gulf Technical & Safety Training centre Page 4 of 137 2. Using the BOP configuration shown below answer the following questions.
a. With no drill pipe in the hole, is it possible to shut the well in under pressure and repair the side outlets on the drilling spool?
A. Yes B. No
b. With no drill pipe in the hole, is it possible to shut the well in under pressure and repair the drilling spool?
A. Yes B. No
c. Is it possible to shut the well in with drill pipe in the hole and circulate through the drill pipe?
A. Yes B. No
d. While changing blind rams to pipe rams with drill pipe in the hole the well starts to flow. Can the well be shut in?
A. Yes B. No
RAM
BLIND SHEAR RAM
SPOOL ANNULAR HCR Choke Line HCR Kill Line
e. With no drill pipe in the hole, is it possible to shut the well in under pressure and change the pipe rams?
A. Yes B. No
f. With drill pipe in the hole, is it possible to shut the well in under pressure and change blind rams to pipe rams?
Gulf Technical & Safety Training centre Page 6 of 137 3. Using the BOP configuration shown below answer the following questions.
a. With the well shut in under pressure on 5” drillpipe in the hole, is it possible to repair the side outlets of the drilling spool?
A. Yes B. No
b. With no drillpipe in the hole, is it possible to shut the well in under pressure and change the 3-1/2” rams to 5” rams?
A. Yes B. No
c. With the well shut in on 3-1/2” rams (on 3-1/2” pipe) under pressure, and with a safety valve in the string, is it possible to change 5” rams to variable bore rams?
A. Yes B. No
ANNULAR
BLIND SHEAR RAM
5” PIPE RAM SPOOL HCR Kill Line 31/ 2” PIPE RAM HCR Choke Line
d. With the well shut in on 5” pipe rams under pressure, is it possible to change blind rams to 5” pipe rams?
A. Yes B. No
e. With the well shut in on 5” pipe rams under pressure, can the annular element be replaced?
A. Yes B. No
f. With the well shut in on 5” pipe rams under pressure, can the manual valve on the choke line be replaced?
Gulf Technical & Safety Training centre Page 8 of 137 4. Using the BOP configuration shown below answer the following questions.
a. With the drillstring in the hole and the well shut-in on Upper Pipe Ram, can the well be circulated whilst repairs are made on annular?
A. Yes B. No
b. Should the well be circulated and killed with the Lower Pipe Rams closed, when the drill string is in the hole? (I.e. circulate via the casing head valves).
A. Yes B. No
c. Can the casing head valves be repaired with the string in the hole and the well closed on the annular?
5. Using the BOP configuration shown below answer the following questions.
a. With the drillstring in the hole and the well shut-in on 5” pipe rams, can we repair the HCR valve?
A. Yes B. No
b. With no drillstring in the hole and the well shut-in on blind/shear rams, can we repair the HCR valve?
A. Yes B. No
c. With the drillstring in the hole and the well shut-in on 5” pipe rams, can the Blind/Shear rams be changed to pipe rams?
Gulf Technical & Safety Training centre Page 10 of 137
Valve Line Up
1. The well is shut in on the pipe ram. It is planned to circulate from the Mud Pump No. 1 through the kill line into the annulus and bleed off mud or gas through the Manual Choke to the Mud Gas Separator.
Which one of the following groups of valves must be open to kill the well safely and monitor the operation?
a. Valve Nos. 2, 4, 5, 7, 8, 10, 14, 16, 25 b. Valve Nos. 1, 4, 5, 6, 8, 9, 10, 11, 12, 19, 25 c. Valve Nos. 2, 4, 7, 9, 10, 12, 15, 18, 25 d. Valve Nos. 1, 3, 10, 11, 14, 19, 25 e. Valve Nos. 1, 4, 9, 10, 11, 12, 14 WELLHEAD 5” PIPE RAMS BLIND/SHEAR RAMS 5” PIPE RAMS ANNULAR PREVENTER (BAG) MUD PUMP MUD PUMP KILL LINE 1 2 4 7 5 6 8 9 10 11 12 14 13 15 20 19 18 17 16 MANUAL CHOKE REMOTE CHOKE MUD GAS SEPERATOR VENT LINE FLARE BOOM CEMENT PUMP 3 25
2. A leak-off test is to be performed using the high-pressure cement pump.
Which five (5) valves must be open in the Figure above, when pumping down the drillstring and reading the pressure from the choke manifold gauge? Valves to be Open: ………. WELLHEAD 5” PIPE RAMS BLIND/SHEAR RAMS 5” PIPE RAMS ANNULAR PREVENTER (BAG) MUD PUMP MUD PUMP KILL LINE 1 2 4 7 5 6 8 9 10 11 12 14 13 15 20 19 18 17 16 MANUAL CHOKE REMOTE CHOKE MUD GAS SEPERATOR VENT LINE FLARE BOOM CEMENT PUMP 3 25
Gulf Technical & Safety Training centre Page 12 of 137 3. The well is shut in on the Upper Pipe Rams. It is planned to circulate using mud
pump No.2, down the drillstring, through the Remote Choke and mud gas separator?
Which one of the following groups of valves must be open to kill the well safely and monitor the operation?
a. Valve Nos. 2, 7, 8, 9, 16, 25, 17, 18, 19 b. Valve Nos. 2, 3, 7, 8, 10, 11, 14, 19 c. Valve Nos. 2, 7, 9, 11, 12, 15, 18 d. Valve Nos. 1, 3, 7, 8, 10, 11, 13, 14, 19 e. Valve Nos. 2, 7, 8, 9, 10, 11, 12, 14, 20 f. Valve Nos. 2, 3, 7, 8, 10, 13, 16, 17, 25 WELLHEAD 5” PIPE RAMS BLIND/SHEAR RAMS 5” PIPE RAMS ANNULAR PREVENTER (BAG) MUD PUMP MUD PUMP KILL LINE 1 2 4 7 5 6 8 9 10 11 12 14 13 15 20 19 18 17 16 MANUAL CHOKE REMOTE CHOKE MUD GAS SEPERATOR VENT LINE FLARE BOOM CEMENT PUMP 3 25
4. The well is shut in on the Annular BOP. It is planned to circulate from the Cement Pump down the drill string and bleed off through the Manual Choke to the Mud Gas Separator.
Which one of the following groups of valves must be open to kill the well safely and monitor the operation?
a. Valve Nos. 2, 3, 5, 8, 9, 10, 11, 14, 19, b. Valve Nos. 1, 3, 4, 6, 7, 8, 10, 11, 13, 18, 25 c. Valve Nos. 3, 7, 8, 9, 10, 11, 12, 19, 25 d. Valve Nos. 2, 3, 5, 8, 9, 10, 11, 12, 15, 17, e. Valve Nos. 3, 5, 8, 9, 10, 11, 14, 16, 19, 25 f. Valve Nos. 2, 3, 4, 6, 7, 8, 9, 10, 11, 14, 16, WELLHEAD 5” PIPE RAMS BLIND/SHEAR RAMS 5” PIPE RAMS ANNULAR PREVENTER (BAG) MUD PUMP MUD PUMP KILL LINE 1 2 4 7 5 6 8 9 10 11 12 14 13 15 20 19 18 17 16 MANUAL CHOKE REMOTE CHOKE MUD GAS SEPERATOR VENT LINE FLARE BOOM CEMENT PUMP 3 25
Gulf Technical & Safety Training centre Page 14 of 137 5. Which valves would need to be open to circulate, using the mud pump, down
the drillstring, through the remote choke and mud gas separator?
Valve Numbers: ………..
6. Which valves would need to be open to circulate, down the kill line, using the cement pump, through the manual choke and mud gas separator?
7. Based on the following diagram what valves would be open when circulating a kick using the mud pump, down the drillstring and returning through the remote choke and mud gas separator?
Valve Numbers-... WELLHEAD 5” PIPE RAMS BLIND/SHEAR RAMS 5” PIPE RAMS ANNULAR PREVENTER (BAG) MUD PUMP MUD PUMP KILL LINE 1 2 4 7 5 6 8 9 10 11 12 14 13 15 20 19 18 17 16 MANUAL CHOKE REMOTE CHOKE MUD GAS SEPERATOR VENT LINE FLARE BOOM CEMENT PUMP 3 25
Gulf Technical & Safety Training centre Page 16 of 137 8. Based on the diagram below what would be the valve line up if we were going to
use the Cement pump to perform a leak off test down the drillstring and measure pressure at the cement pump.
Circle either open or closed for each valve below. Valve no: 1 □ Open □ Closed
Valve no: 2 □ Open □ Closed Valve no: 3 □ Open □ Closed Valve no: 4 □ Open □ Closed Valve no: 5 □ Open □ Closed Valve no: 6 □ Open □ Closed Valve no: 7 □ Open □ Closed Valve no: 8 □ Open □ Closed Valve no: 9 □ Open □ Closed
WELLHEAD 5” PIPE RAMS BLIND/SHEAR RAMS 5” PIPE RAMS ANNULAR PREVENTER (BAG) MUD PUMP MUD PUMP KILL LINE 1 2 4 7 5 6 8 9 10 11 12 14 13 15 20 19 18 17 16 MANUAL CHOKE REMOTE CHOKE MUD GAS SEPERATOR VENT LINE FLARE BOOM CEMENT PUMP 3
9. In which order should the valves for the choke line be installed on surface BOP with a 'rated working pressure' of 10,000 psi according to best practice? (Note; inside means -closed to the BOP)
a. Inside -a hydraulically operated valve, middle -a manual valve, outside hydraulically operated valve.
b. Inside -a hydraulically operated valve, outside -a manual valve. c. Inside -a manual valve, outside -a hydraulically operated valve.
d. Inside -a manual valve, middle -a check valve, outside -a hydraulically operated valve.
e. Inside -a check valve, middle -a hydraulically operated valve, outside -a hydraulically operated valve.
10. On a surface BOP stack, in which position must the valves on the kill line and choke line be placed during drilling?
a. Both types of valves closed on the kill line and opened on the choke line. b. Manual valves closed and hydraulic valves opened.
c. Hydraulic valves closed and manual valves opened. d. All valves must be closed.
Gulf Technical & Safety Training centre Page 18 of 137
Section II
Diverters and Annular Preventers
1. Figure below illustrates a diverter in place while drilling with a surface BOP.
Match the correct numbers to the descriptions below.
a. ... Actuating piston. b. ... Head.
c. ... Vent line.
d. ... Annular packing element. e. .. ... Diverter open port. f. .. ... Flow line.
g. .. ... Body.
h. ... Diverter closing port.
2. What are the main components of a diverter system? (TWO ANSWERS)
a. A vent line of sufficient diameter to permit safe venting using the mud-gas separator
b. A vent line of small diameter, sufficient to create a “back pressure” on bottom while circulating.
c. A high pressure ram type preventer with a large internal diameter. d. A low pressure annular preventer with a large internal diameter. e. A vent line of sufficient diameter to permit safe venting and proper
disposal of flow from the well.
3. Figure below illustrates an integral diverter system. Match the correct components to the descriptions below.
a. ... Insert packer.
b. ... ……Outer packer (outer active seal). c. ... .Diverter packer closing port. d. ... … Flow line seals.
e. ...Insert packer lockdown dogs. f. ...Diverter lockdown dogs.
Gulf Technical & Safety Training centre Page 20 of 137 4. Diverter systems are designed to totally seal in a well.
□ True □False
5. The main purpose of a diverter is to divert shallow gas.
□ True □False
6. Diverters vent lines must be small diameter lines.
□ True □False
7. The requirements of a diverter system are a low pressure annular preventer and an overboard vent line to the a mud gas separator.
□ True □False
8. Pick the correct procedure for the operation of a surface diverter system. Wind direction is starboard to port.
a. Open starboard vent, close shaker valve, close diverter. b. Close diverter, close shaker valve, open starboard vent. c. Close diverter, open port vent, close shaker valve. d. Open port vent, close shaker valve, close diverter.
9. What are the components of a 29-1/2 inch diverter system? (select two answers)
a. A low pressure annular preventer with a large internal diameter.
b. A vent line of sufficient diameter to permit safe venting using the mud-gas separator.
c. A high pressure rams type preventer with a large internal diameter. d. A vent line with a manually operated full opening valve.
e. A vent line of sufficient diameter to permit safe venting and proper disposal of flow from the well.
10. Which one of the following is 'good practice' in relation to diverter systems?
a. Open the diverter line before closing the diverter.
b. For safety, the diverter should only be operated some distance away from the rig floor.
c. As the equipment is not used for lengthy periods of time, the diverter system doesn't need to be included in the rig maintenance program. 11. What happens when a diverter is closed?
a. The vent valve opens and then the BOP closes. b. The BOP and vent valve close at the same time. c. The BOP closes and then the vent valve opens.
Gulf Technical & Safety Training centre Page 22 of 137 12. Which of the following factors limit the success of diverter operation when
shallow gas blowout occurs? (THREE ANSWERS)
a. Rig air pressure of Zero psi.
b. The formation strength at the conductor/casing shoe. c. Diverter lockdown doges unlocked.
d. Diverter lockdown doges locked. e. Rig air pressure of 125 psi.
Annular Preventers
1. Figure below illustrates a Hydril GK Annular Preventer commonly used for Surface BOP installations
Match the correct numbers to the component below a. Opening Chamber.
b. Closing Chamber Hydraulic Inlet. c. Preventer Body.
d. Operating Piston.
e. Screwed Head.
Gulf Technical & Safety Training centre Page 24 of 137 2. Figure below illustrates a Cameron „D‟ type Annular Preventer
„D‟ Type Annular BOP Match the correct numbers to the component below. a. Closing hydraulic port.
b. Opening hydraulic port. c. Packer inserts.
d. Operating Piston. e. Ring groove.
3. Figure below illustrates a Cameron “DL” type annular preventer “DL” Type Annular BOP
Match the correct numbers to the component below. a. ………. . ...Operating Piston. b. …………. Pusher Plate. c. …………. Packer Insert. d. …………. Vent. e. …………. Donut. f. …………. Packer.
g. …………. Opening Hydraulic Port. h. ……..…. ..Closing Hydraulic Port. 1 2 3 4 5 6 7 8 9 10 11 12 13
Gulf Technical & Safety Training centre Page 26 of 137 4. Figure below illustrates a Hydril GL Annular Preventer.
Match the correct numbers to the components below a. Opening Chamber.
b. Closing Chamber Hydraulic Inlet.
c. Piston.
d. Head Quick Release Screws. e. Packing Unit.
5. Figure below illustrates a Hydril GL Annular BOP. Which of the following statements are correct when this preventer is used in a Subsea operation? (TWO ANSWERS)
a. Lowest required hydraulic closing pressure when closing chamber and secondary chamber are connected.
b. Lowest required hydraulic closing pressure when opening chamber and secondary chamber are connected.
c. The secondary chamber allows balancing the open force on the piston created by drilling fluid hydrostatic pressure in the marine riser.
Gulf Technical & Safety Training centre Page 28 of 137 6. Figure below illustrates a section view of a 13-5/8” - 10,000 psi WP type GX
annular BOP.
Match the numbered components with the descriptions below. a. Latched head.
b. Operating piston. c. Packing unit d. Opening chamber
e. Wear plate
7. Identify the parts of the Hydril GK.
Opening chamber Packing unit Closing chamber Head (screw) Piston
Gulf Technical & Safety Training centre Page 30 of 137 8. Identify the parts of the Shaffer.
Opening chamber Closing chamber Packing unit Piston
9. Identify the parts of the Cameron „D‟ Type.
Opening chamber Closing chamber Packing unit (donut) Packing/Sealing insert Piston
Head (latched) Ring groove
Gulf Technical & Safety Training centre Page 32 of 137 10. Match the items listed below to the number indicated on the drawing.
Opening Chamber
Primary Closing Chamber
Balance or Secondary Closing Chamber Opening Chamber Head
Packer Element Piston
11. Why is it important to reduce the regulated hydraulic pressure for annular BOP before running a large sized casing?
a. To prepare for the Soft Shut in procedure. b. To reduce the closing time.
c. To avoid collapsing the casing, during closing.
d. To enable the packing unit to fit uniformly around the casing body without damaging the steel segments.
12. Annular preventer sealing elements are made primarily to seal around any size of pipe in the hole, but can also seal off the borehole with all pipe removed.
a. True. b. False.
13. Which three statements about Annular Preventers are true? (Select three answers)
a. Can be used as a means of secondary well control. b. Is designed to seal around any object in the well bore. c. Cannot seal on a square or hexagonal kelly.
d. Will not allow tool joints to pass through.
e. Will allow reciprocating or rotating the drill string while maintaining a seal against well bore pressure.
f. Can require a variable hydraulic closing pressure according to the task carried out.
Gulf Technical & Safety Training centre Page 34 of 137 14. When annular BOPs are hydraulically pressure tested, it often happens that the
test pressure cannot be kept steady during the first attempt. They have to be charged up two or more times before an acceptable test is obtained
Why is this?
a. Annular BOPs always leak until the packing element finds its new shape. This motion can take several minutes.
b. The compressibility of the hydraulic fluid from the hydraulic control unit below the closing piston causes the test pressure to drop.
c. The packing unit elastomer is flowing into a new shape because the rate of flow is influenced by the applied pressure.
15. What has to be checked before the installation of any annular packing element? (TWO ANSWERS)
a. Temperature rating of the element. b. Type of mud to be used.
c. Desired hydraulic closing pressure. d. Maximum pipe outside diameter.
Gulf Technical & Safety Training centre Page 36 of 137 16. A BOP stack is made up from the well head as follows: -
Three Ram BOPs, 13-5/8, 10,000 psi rated working pressure. One Annular BOP, 13-5/8, 5,000 psi rated working pressure.
After taking a kick while tripping the well is closed in on 5 inch pipe using the Annular Preventer. After stabilisation of shut in pressures the casing gauge reads 1,000 psi.
Using the diagram below what hydraulic pressure should the annular closing pressure be adjusted to for stripping?
a. 200 - 400 psi. b. 400-600 psi. c. 600 - 800 psi. d. 1000-1500 psi
17. Which type of rubber should be installed in an annular BOP while working in coldest temperature (-20/-30 Celsius -4/-22 Fahrenheit)? (TWO ANSWERS) a. Neoprene rubber.
b. Nitrile rubber. c. Natural rubber.
18. Which type of annular BOP was designed with a weep hole? a. Cameron Model D.
b. Hydril model GL.
c. Shaffer model Wedge cover. d. Hydril model MSP
19. Which one of the following statements defines 'Well Pressure Assistance"? a. The well pressure acting on the piston produces an increasing pressure in the
closing chamber.
b. The pressure exerted by the well on the exposed surface of the piston gives a result force that is added to the force produced by the pressure in the closing chamber.
c. The pressure exerted by the well on the exposed surface of the piston gives a result force that is subtract from the force produced by the pressure in the closing chamber.
20. In which one of the following annular BOP's "closure" not assisted by well pressure?
a. Hydril model GL. b. Hydril model GK. c. Cameron model D
Gulf Technical & Safety Training centre Page 38 of 137 21. What pressure must be kept in the annular BOP closing chamber during stripping
operation?
a. The minimum pressure of BOP closure that ensures proper sealing.
b. The minimum pressure that allows the tool joint to go through the packing. c. 500 psi.
Section III
Ram Preventers
1. Match the items listed below to the number indicated on the Cameron blind/shear ram.
a. ………. Side Packers. b. ………. Ram Face Seal. c. ………. Top Seal.
d. ………. Lower Ram Assembly. e. ………. Top Ram Block. f. ………. Top Ram Assembly.
Gulf Technical & Safety Training centre Page 40 of 137 2. Figure below illustrates a shear/blind ram.
Match the numbered parts to the correct components listed below. a. ………. Shear blade.
b. ……. …Upper rubber seal. c. ………. Upper ram block holder. d. ………. Upper ram block. e. ………. Lower ram block. f. ………. Lower rubber seal.
3. Figure below illustrates a pipe ram.
Match the numbered parts to the correct components listed below. a. ………. Top Seal.
b. ………. Ram Packer. c. ………. Ram Block. d. ………. Ram Assembly.
4. Most of the conventional front packer elements fitted on ram BOPs are enclosed between steel plates. What are the main reasons for this type of design.
(TWO ANSWERS)
a. To support the weight of the drillstring during hang-off.
b. To prevent the rubber extruding top and bottom when the rams are closed. c. To feed new rubber into sealing contact with the pipe when the sealing face
Gulf Technical & Safety Training centre Page 42 of 137 5. Match the items listed below to the numbers indicated on the drawing.
a. ………. Body
b. ………. Cylinder, Operator c. ………. Bonnet
d. ………. Ram Assembly e. ………. Bonnet seal
f. ... ……..Ram change piston g. ………. Bonnet Bolt
h. ………. .Locking Screw Housing i. ………. . Locking screw
j. ………. .Intermediate Flange k. .………. Piston, Operating l. …..…. ... Ram change cylinder
6. Identify the parts of the Cameron pipe ram.
a. ………. Ram Packer b. ………. Top Seal c. ………. Ram Block
Gulf Technical & Safety Training centre Page 44 of 137 7. Identify the parts of the Shaffer blind/shear ram.
a. ………. Upper Ram block. b. ………. Lower Ram block c. ………. Upper seal/rubber d. ………. Lower seal/rubber e. ………. Upper holder f. ………. Lower holder g. ………. Lower shear blade
8. Identify the parts of the Shaffer pipe ram.
a. ………. Holder. b. ………. Block c. ………. Seal / Rubber
9. The main functions of the “weep hole” on ram type B.O.P is to: (Two answers) a. Show the bonnet seal is leaking.
b. Show the primary mud seal on the piston rod is leaking. c. Release any overpressure that may occur during testing. d. Prevent damage to the opening chamber.
10. With regard to ram locking devices, are the following statements True or False? a. All rams have locking devices.
□ True □False
b. Locking devices increase the closing pressure on rams. □ True □False
Gulf Technical & Safety Training centre Page 46 of 137 d. All rams will allow the string to be hung off.
□ True □False
e. Rams are designed to hold pressure from both above and below. □ True □False
11. If a primary mud seal fails during a kill operation you have no back-up seal. □ True □False
12. When a ram type surface BOP is operated, the hydraulic fluid on the opposite side of the operating piston is being displaced.
Indicate what happens to the fluid.
a. The fluid leaves the operating cylinder and drains off in the borehole through a check valve.
b. The fluid leaves the operating cylinder and returns back to the opposite side of the piston to enforce the closing pressure.
c. The fluid leaves the operating cylinder and returns back to the fluid reservoir (as a function of the four-way valve for each preventer).
13. Which statements are correct with respect of fixed bore ram type BOP‟s? (select two answers)
a. Ram type BOP‟s are designed to contain and seal Rated Working Pressure from above the closed rams as well as from below.
b. Ram type BOP‟s should be equipped with a mechanical locking system. c. Fixed bore ram type BOP‟s can close and seal on various pipe sizes. d. Fixed bore ram type BOP‟s can be used to hang off the drill string
14. What are ram type preventers designed to do? a. Hold pressure only from above.
b. Hold pressure only from below.
c. Hold pressure from both above and below.
15. On a ram type BOP preventer, in which position will the 4-way valve be put to assist with the removal of the bonnet after backing off the bonnet bolts?
a. Open. b. Closed.
c. Neutral (Block).
d. In any position, it does not matter.
16. Which of the following statements about fixed bore ram type BOPS are correct (THREE ANSWERS)
a. Ram type BOPs are designed to contain and seal Rated Working Pressure from above the closed rams as well as from below.
b. Ram type BOPs should be equipped with a mechanical locking system. c. Fixed bore ram type BOPs can close and seal on various pipe sizes. d. Fixed bore ram type BOPs can be used to hang off the drill string.
e. Ram type BOPs are designed to contain and seal Rated Working Pressure only from below the closed rams.
17. When a ram type BOP on a surface stack is closed, what happens to the operating fluid displaced from the opening chamber?
a. The fluid drains into the well bore.
Gulf Technical & Safety Training centre Page 48 of 137 18. Which ram type preventer on a Cameron 13-5/8, 10,000 psi BOP stack is
equipped with thicker intermediate flanges? a. Pipe rams.
b. Blind rams. c. Shear rams. d. Variable rams.
19. What is the main purpose of Blind/Shear rams?
a. To shear tubulars like drill pipe while simultaneously sealing the hole. b. To shear tubulars like drill pipe without sealing the hole.
c. To effect a seal with drill collars in the hole.
20. What is the meaning of “Closing Ratio” for a ram type BOP - as defined by API RP53?
a. The ratio between opening and closing volume.
b. The ratio of the wellhead pressure to the BOP closing pressure. c. The ratio between opening and closing time.
d. The ratio between BOP rated working pressure and hydraulic control unit working pressure.
21. Can ALL ram type BOPs open in a situation where Rated Working Pressure is contained below the rams and hydrostatic pressure to the flowline is above the rams?
a. Yes b. No
22. Can ALL ram type BOPs close on Rated Working Pressure in the well bore when the hydraulic operating pressure is 1,500 psi?
a. Yes b. No
23. Bottom rams should always be used to circulate up a kick. TRUE FALSE
Gulf Technical & Safety Training centre Page 50 of 137 24. A Hydril 183/4", 10,000 psi, W.P Ram type BOP, has a closing ratio for pipe and
shear rams of 10:1.
What is the minimum closing pressure required for the BOP? Answer ………….. Psi
25. A Cameron 13 5/8”, 10,000 psi working pressure, ram BOP, has a closing ratio for pipe and shear rams of 7.0 - 1.
What is the minimum closing pressure required for the BOP? Answer ………….. Psi
26. For the following ram type BOP:
BOP R.W.P. 15000 psi
Closing ratio 6.8 : 1
Opening ratio 3 : 1
Accumulator operating pressure 3000 psi
What is the minimum pressure required to close the BOP at maximum wellbore Pressure?
27. What is the correct meaning of the term „primary seal and secondary seal‟ when used in connection with ram type BOPs?
a. Primary seal is shutting in the well using the annular BOP. Secondary seal is shutting in the well using the rams after the annular BOP has already been closed.
b. Primary seal is well control utilising only mud hydrostatic pressure. Secondary seal is well control utilising both mud hydrostatic pressure and the BOPs. c. Primary seal is the mechanical ram shaft packing. Secondary seal is injected
plastic packing intended to activate an extra seal on the ram shaft in an emergency -if the primary seal is leaking.
d. Primary seal is a seal between the ring gasket and the connection on the side or end outlets. Secondary seal is a seal established by a ring gasket wound with Teflon tape.
28. What are the correct reasons for including a weep hole on ram type BOPs? (TWO ANSWERS)
a. The weep hole indicates if the primary ram shaft packing is leaking well bore fluid.
b. The weep hole prevents leakage through the primary ram shaft packing from the well bore into the opening chamber.
c. The weep hole allows for visual inspection of the ram shaft and should be plugged with a bull plug between inspections.
d. To allow the installation of a grease nipple so that the ram shaft can be greased.
e. The weep hole is a grease release port that prevents over-greasing of the ram shaft packing.
Gulf Technical & Safety Training centre Page 52 of 137 29. What is the primary function of a weep hole (drain or vent hole) on a ram type
BOP?
a. To show that the ram body rubbers are leaking.
b. To show that the closing chamber operating pressure is too high. c. To show that the mud seal on the piston rod is leaking.
d. To show that the bonnet seals are leaking.
30. During a routine test it is noticed that the weep hole (drain hole/vent hole) on one of the blowout preventer bonnets is leaking fluid.
What action should be taken?
a. The weep hole only checks the closing chamber seals, leave it till the next maintenance schedule.
b. Energise emergency packing. If leak stops, leave it till the next maintenance schedule.
c. A leak is normal because the metal to metal sealing face in the bonnet needs some lubrication to minimise damage.
d. Ram packing elements on the ram body are worn out, replace immediately. e. Primary ram shaft seal is leaking, secure the well and replace immediately. 31. Before running 7 inch casing with a variable pipe rams (5-7 inch) already
installed, is it necessary to change over to 7 inch casing rams. □ Yes.
□ No.
32. Which one of the following rams will be replaced before running casing? a. Upper pipe rams.
b. Lower pipe rams.
33. In an emergency situation it is possible to activate a 'secondary Seal' on a ram type preventer Which one of the following pressures will it seal against? a. Wellbore pressure.
b. Closing chamber pressure. c. Opening chamber pressure.
Gulf Technical & Safety Training centre Page 54 of 137
Section IV
API Flanges
1. Figure below illustrates the profile of an API 6BX type flange.
API Type 6BX Flange
Which number indicates the Nominal flange dimension? a. Dimension No. 1.
b. Dimension No. 2. c. Dimension No. 3. d. Dimension No. 4.
2. Figure below illustrates the profiles of two API type flanges.
Which one of the flanges has a specified distance between “made-up flanges” that require occasional re-tightening of bolts/studs and nuts?
a. API type 6B. b. API type 6BX.
3. What is the meaning of “6BX” when referring to a flange? a. Type.
b. Serial Number. c. Dimension. d. Trademark.
4. Which of the following statements about ring gaskets are correct? (TWO ANSWERS)
a. Ring gaskets may be used several times
b. The same material specifications apply to ring gaskets as to ring grooves. c. Type RX and BX ring gaskets provide a pressure-energised seal.
Gulf Technical & Safety Training centre Page 56 of 137 5. Figure below shows an API Type 6BX Flange
The four figures below illustrate cross sectional profiles of four different API
ring gaskets commonly used on well head equipment.
Which one of these gaskets matches the 6BX type flange shown at top of page. a. Type R Octagonal.
b. Type BX.
6. Figure below illustrates the cross-sectional profiles of four different API ring gaskets commonly used on wellhead equipment.
Select the correct types that illustrate pressure energised ring gaskets.
Type R Octagonal Type R Oval Type RX. Type BX. (TWO ANSWERS)
a. Type R Octagonal. b. Type R Oval. c. Type RX. d. Type BX.
Gulf Technical & Safety Training centre Page 58 of 137 7. Figure below illustrates the cross-sectional profiles of four different API ring
gaskets commonly used on wellhead equipment.
Type R Octagonal Type R Oval Type RX. Type BX.
Select the pressure energised type of ring gasket that should be used for flanged BOP connection type 6B as stated in API RP 53.
a. Type R Octagonal. b. Type R Oval. c. Type RX. d. Type BX.
8. What is a 7-1/16”, 10,000 psi flange? a. It is designed for RX ring gasket type.
b. It has a 10,000 psi test pressure and 5000 psi working pressure. c. It has a 10,000 psi working pressure and 7-1/16” ID.
d. It has a 7-1/16” OD and a 10,000 psi working pressure.
9. What would be the effect of fitting a 7-1/16” x 5,000 psi flange to a working 10,000 psi rated BOP stack?
a. The rating would remain at 10,000 psi.. b. The rating would become 5,000 psi. c. The rating would become 7,500 psi.
10. What does 5/8 mean when the equipment in use is described as “15M, 13-5/8”?
a. The external diameter of the flange or hub. b. The external diameter of the BOPs.
c. The cylinder diameter of the hydraulic actuator for the ram BOPs. d. The through-bore (inside diameter) of the BOP.
11. Of the 4 types of gasket listed, indicate which flange (API 6B, API6BX) they would be used with.
Type R Octagonal …… Type R Oval ………… Type R RX ………….. Type BX ………..
b. Which two of the above gaskets are pressures energised? … …… & … ……
12. Are the following statements true or false regarding API ring gaskets? a. Pressure energised type gaskets should be re-used.
□ True □False
b. 6BX flanges with BX gaskets require more checking than 6B with RX gaskets.
□ True □False
c. The nominal size of a flange is the diameter of the required gasket. □ True □False
Gulf Technical & Safety Training centre Page 60 of 137 13. Which statements are correct with respect to ring gaskets used for flange to
flange make up? (TWO ANSWERS)
a. Type RX and BX ring gaskets provide a pressure energised seal.
b. The same material specifications apply for ring gaskets as for ring grooves. c. Ring gaskets may be used several times.
d. Type BX flanges, which are designed for face-to-face make up, make use of type BX ring gaskets only.
14. The figures illustrate the cross sectional profile of four different API ring gaskets commonly used on wellhead equipment.
Indicate the type of ring gasket that matches the type 6BX flange. a. Type R Octagonal
b. Type R Oval c. Type RX d. Type BX
15. Figures 1, 2 and 3 below show three different types of end outlet connections or side connections used on BOPs.
1 2 3
Identify the types of connection by matching the correct number to the description:
a. Clamp hub connection.: ……….. b. Flanged connection.: …….…….. c. Studded connection.: …….……
16. What is understood by the expression "Stand-Off between flanges" when installed and made up?
a. The external diameter of the flange. b. The internal diameter of the flange.
c. The distance between the two flanges when installed with the studs and the nuts tightened
Gulf Technical & Safety Training centre Page 62 of 137
Section V
Inside BOPs & Valves
1. Before cutting the drilling line. With the bit at casing shoe, which item of equipment must be installed to make the operation safe?
a. Circulating head.
b. Make up top drive/kelly. c. Full opening safety valve. d. Inside blowout preventer.
e. Full opening safety valve and an inside blowout preventer
2. There is only one inside BOP with an NC50 (4-1/2 inch IF) pin connection on the rig.
The drill string consists of: -
5-inch Heavy Weight drill pipe (NC50) 8-inch (6-5/8 Reg.) drill collars.
Which of the following crossovers must be on the rig floor while tripping? a. NC50 (4-1/2 inch IF) Box x 6-5/8 inch Reg. pin.
b. NC50 (4-1/2 inch IF) Box x 7-5/8 inch Reg. pin. c. NC50 (4-1/2 inch IF) Box x 6-5/8 inch Reg. box. d. 6-5/8 inch Reg. Box x 7-5/8 inch Reg. Pin.
3. There is only one inside BOP with an NC50 (4-1/2 inch IF) pin/box connection on the rig. The drill string consists of: -
5-inch drill pipe (NC50).
5-inch Heavy wall drill pipe (NC50). 8-inch drill collars (6-5/8 Reg.). 9-1/2 inch drill collars (7-5/8 Reg.).
Which of the following crossovers must be on the rig floor while tripping? (TWO ANSWERS)
a. NC50 (4-1/2 inch IF) box x 6-5/8 inch Reg. pin. b. NC50 (4-1/2 inch IF) box x 7-5/8 inch Reg. pin. c. NC50 (4-1/2 inch IF) pin x 6-5/8 inch Reg. box. d. 6-5/8 inch Reg. Pin x 7-5/8 inch Reg. Pin. e. NC50 (4-1/2 inch IF) pin x 7-5/8 inch Reg. box.
Gulf Technical & Safety Training centre Page 64 of 137 4. Figure below illustrates six components often used to test BOPs or control drill
pipe pressure.
Match the correct component numbers to each of the descriptions below. a. ………. Bit sub bored for float.
b. ………. Cup type tester c. ………. Dart sub.
d. ………. Pump down dart.
e. ………. Dart type drill pipe float f. ………. Flapper type drill pipe float.
5. Full opening safety valves (stab-in kelly cock type) should be placed on the rig floor at all times, ready for use, to fit the tubulars being used.
Which of the following actions can be performed with a full opening valve in the string? (THREE ANSWERS)
a. Easier to stab if strong flow is encountered up the drill string. b. Must not be run in the hole in the closed position.
c. Has to be pumped open to read „Shut In Drill Pipe Pressure. d. Will not allow wireline to be run inside the drill string. e. Is kept in its open position by a rod secured by a T-handle. f. Requires the use of a key to close.
6. Stab-in non-return safety valves (inside BOPs) should be placed on the rig floor at all times, ready for use, to fit the tubulars being used.
Which of the following actions can be performed with a non-return valve in the string?
(THREE ANSWERS)
a. Easier to stab if strong flow is encountered up the drill string. b. Must not be run in the hole in the closed position.
c. Has to be pumped open to read „Shut In Drill Pipe Pressure. d. Will not allow wireline to be run inside the drill string. e. Has potential to leak through the open/close key.
Gulf Technical & Safety Training centre Page 66 of 137 7. In which of the following situations is it an advantage to use a full closing float
valve in the drill string?
a. To avoid flowback while tripping or during a connection. b. To read the drill pipe pressure value following a well kick. c. To allow reverse circulation.
d. To reduce surge pressure.
8. A conventional flapper type float valve is installed in the bit sub in the closed position. What effect does the float valve have on the drill string when tripping into the well? (TWO answers)
a. It increases the risk of hydraulic collapse of the drill pipe - if not filled. b. It increases tripping time.
c. It increases flow-back through the drill string. d. It reduces surge pressure on the formation. e. It reduces flow-back in the flow line. f. It allows reverse circulation at any time.
9. Indicate whether the following operations can or cannot be performed with a float valve (non-return) type in the string.
Can the correct shut in drill pipe pressure be read on the gauge after the pumps are stopped
a. Yes. b. No.
10. Indicate whether the following operations can or cannot be performed with a float valve (non-return) type in the string.
Is it possible to get drill pipe back flow while tripping? a. Yes.
b. No.
11. Indicate whether the following operations can or cannot be performed with a float valve (non-return) type in the string.
Is surge pressure generated when tripping in? a. Yes.
b. No.
12. Indicate whether the following operations can or cannot be performed with a float valve (non-return) type in the string.
Is it possible to reverse circulating? a. Yes.
Gulf Technical & Safety Training centre Page 68 of 137 13. A well kicks with the bit off bottom and is shut in - the kellycock should now be
in place. The decision is made to strip back into the hole.
What equipment should be made up onto the string in order to perform the
stripping operation safely, assuming there is no float sub or dart sub in the string?
(Note: Drill pipe safety valve = Kellcock. Inside BOP = non-return valve.)
a. Only the drill pipe safety valve in the closed position. b. Only the inside BOP.
c. The drill pipe safety valve (open) with an inside BOP installed on top. d. The inside BOP with a drill pipe safety valve (closed) installed on top. 14. What is an Inside Blowout Preventer?
a. An element inserted into the annular preventer to reduce the inside diameter. b. A ball valve installed immediately above the bit.
c. A device that can be installed in the drillstring to act as a “back-pressure” valve.
15. Match the items listed below to the numbers indicated on the drawing.
a. ………. Valve spring b. ………. Release tool c. ………. Valve seat
d. ………. Valve release rod
e. ………. Release rod locking screw f. ………. Valve insert
Gulf Technical & Safety Training centre Page 70 of 137 16. Match the items listed to the numbers on the diagram.
a. ………. Ball
b. ………. Lower Seat c. ………. Upper Seat d. ………. Body e. ………. Crank
17. True or Fulse:
a. Full Opening safety valves are easier to stab than Non Return valves if back flow occurs.
TRUE FALSE
b. Non Return valves require the use of a key to close.
TRUE FALSE
c. Full Opening valves have to be pumped open to read SIDPP.
TRUE FALSE
d. Full Opening valves must not be run into the hole in the closed position.
TRUE FALSE
18. With regard to drillstring floats which of the following are true or false?
a. Floats allow reverse circulating. TRUE FALSE
b. Floats increase surge and swab pressures. TRUE FALSE
c. Floats prevent back flow up the drillstring. TRUE FALSE
d. Floats protect the bit from plugging. TRUE FALSE
Gulf Technical & Safety Training centre Page 72 of 137 f. Floats allow SIDPP to be read without further action.
TRUE FALSE
19. When RIH with a solid float, the drillstring must be filled from the top on a regular basis. What might be the result if this procedure is not carried out correctly? (Two answers)
a. Drillpipe collapse.
b. Drop in BHP due to air bubble. c. Riser collapse.
d. Mud losses. e. Stuck pipe.
20. The upper Kelly valve is installed to isolate the surface installation from well pressure.When should this valve be closed.
a. When connections are made, to save the spilling of drilling fluid.
b. In well control situations when the surface pressures may exceed the rated working pressure of the rotary kelly hose and the stand pipe manifold. c. Only when the swivel packing is being replaced.
21. While pulling out a kick is taken. The Hydril • drop in back-pressure valve' is dropped and pumped down and the well shut in. After a while it is observed that the pressure on the drill pipe gauge continues to increase. Which of the following are the causes of this pressure increase?
(TWO ANSWERS)
a. The bit nozzles are plugged.
b. The drop in check valve is not yet seated.
c. The indented surface inner seat is washed out by the mud flow. d. The stabilizers are balled up.
22. There is only one inside BOP with NC38 (3-1/2 inch IF) pin / box connection on the rig. The drill string consists of:
3-1/2 inch drill pipe (NC38). 2-7/8 inch drill pipe (NC31).
Which of the following crossovers must be on the rig floor while tripping?
a. NC40 (4 inch IF) box X NC26 (2 3/8 inch IF) pin. b. NC38 (3 1/2 inch IF) box X NC31 (2 7/8 inch IF) box. c. NC31 (2-7/8inch IF) pin X NC38 (3-1/2 inch IF) box. d. NC46 (4 inch IF) box X NC35 (3-1/2 inch IF) pin.
Gulf Technical & Safety Training centre Page 74 of 137
Section VI
Choke Manifold
1. What is the purpose of the choke manifold vent /bleed line that by-passes the chokes?
a. To connect to the mud/gas separator.
b. To by-pass the chokes and connect the choke manifold to the kill line. c. To by-pass the chokes and bleed off high volumes of fluid.
2. What is the recommended diameter for the choke manifold vent line/bleed line by-passing the chokes according to API RP53?
a. The same diameter as the other lines on the choke manifold. b. At least equal to the diameter of the choke line.
c. At least 5 inches.
3. What is the main function of the choke in the overall BOP system? a. To direct hydrocarbons to the flare.
b. To direct wellbore fluids to the mud/gas separator. c. To shut the well in softly.
d. To hold back pressure while circulating out a kick. 4. Why are two chokes fitted into most choke manifolds?
a. To direct returns to the separator. b. To direct returns to the pits. c. To direct returns to the flare.
d. To minimise back-pressure when circulating through the manifold. e. To provide backup if a problem occurs with the active choke.
5. Why are some choke manifolds equipped with a glycol or methanol injection system?
a. To minimize the effect of hot climates.
b. To help prevent hydrate formation while circulating a kick. c. To help fluids flow better during well testing.
d. To protect rubber goods in high temperature wells.
6. Which method is used to operate the remotely operated valves on the choke line? a. Hydraulic fluid.
b. Air. c. Nitrogen. d. Wires.
7. The reason for having at least two chokes in the manifold is: a. To reduce back pressure.
b. To allow separation of fluid and gas. c. To reduce load on the mud gas separator.
d. To provide a backup in case of washout/plugging. 8. The main function of the Choke in the overall B.O.P system is:
a. To divert fluid to the mud tank. b. To divert contaminant to burning pit. c. To close the well in softly.
Gulf Technical & Safety Training centre Page 76 of 137
Section VII
Mud Gas Separator (MGS)
1. Which of the following dimensions in the diagram below, limit the maximum working pressure of the mud/gas separator?
a. The height of the main body (H1). b. The height of the dip tube (H2). c. The total height of the vent line (H4). d. Diameter of the inlet pipe (D3).
GAS TO VENT FROM CHOKE MANIFOLD MUD/GAS SEPERATOR TO SHALE SHAKERS LIQUID SEAL D1 D3 D2 H1 H2 H4
2. In the figure below, which dimension determines the back-pressure generated within the seperator?
a. The length and the inside diameter (D3) of the inlet pipe from the buffer tank to the choke manifold.
b. The dip tube height (H2).
c. The body height (H1) and the body inside diameter (D1). d. The derrick vents pipe height (H4) and inside diameter (D2).
GAS TO VENT FROM CHOKE MANIFOLD MUD/GAS SEPERATOR TO SHALE SHAKERS LIQUID SEAL
D1
D3
D2
H1
H2
H4
Gulf Technical & Safety Training centre Page 78 of 137 3. Use the illustration of the mud/gas separator in Figure below and the following
data to calculate the operating pressure at which gas blow-through may occur:- H1 - body height = 20 feet. H2 - dip tube height = 15 feet. H4 - derrick vent line height = 147 feet. Mud density = 10 ppg
a. 3 - 4 psi b. 5 psi c. 7 - 8 psi d. 76 - 77 psi GAS TO VENT FROM CHOKE MANIFOLD MUD/GAS SEPERATOR TO SHALE SHAKERS LIQUID SEAL
D1
D3
D2
H1
H2
H4
4. What is the purpose of a Vacuum Degasser? a. It is only used while circulating out a kick.
b. It is mainly used to remove gas from mud while drilling c. It is mainly used to separate gas from liquids while testing.
d. It is a standby in the event of the “Mud/Gas Separator (Poor Boy)” failing. 5. Based on the following diagram, with a mud weight of 11.3 ppg flowing through
the MGS and liquid seal. Height of Dip Tube = 18 ft.
A. How much hydrostatic head (back pressure) would have to be overcome before gas vented to the shale shakers? (i.e. the Maximum Safe Operating Pressure). Answer ……….. Psi GAS TO VENT FROM CHOKE MANIFOLD MUD/GAS SEPERATOR TO SHALE SHAKERS LIQUID SEAL D1 D3 D2 H3 H1 H2 H4
Gulf Technical & Safety Training centre Page 80 of 137 B. Which dimension would determine the normal working pressure of the
above MGS for a given flow rate? a. Vessel diameter and length. b. Liquid seal diameter and length. c. Height of vessel above flowline. d. Vent line diameter and length.
6. Based on the following diagram, with a mud weight of 11.3 ppg flowing through the MGS and liquid seal, how much hydrostatic head (back pressure) would have to be overcome to allow gas to vent to the shale shakers?
Answer ………. psi GAS TO VENT FROM CHOKE MANIFOLD MUD/GAS SEPERATOR TO SHALE SHAKERS LIQUID SEAL 10 ft 15 ft
7. The illustration represents a mud/gas separator.
Which of the following dimensions is the primary factor in limiting the capacity of the mud-gas separator?
a. The height of the dip tube (H2) b. The height of the main body (H1) c. The total height of the vent line (H4)
GAS TO VENT FROM CHOKE MANIFOLD MUD/GAS SEPERATOR TO SHALE SHAKERS LIQUID SEAL
D1
D3
D2
H1
H2
H4
Gulf Technical & Safety Training centre Page 82 of 137 8. In the figure below. Which of the following dimension is the primary factor in
limiting the capacity of the mud-gas separator?
\
a. The height of the dip tube (H2). b. The height of the main body (H1). c. The total height of the vent line (H4).
9. A Vacuum Degasser is often used to remove gas from drilling fluid while drilling. Where the suction line to the Vacuum Degasser should be connected according to best practice?
a. Upstream of the mud/gas separator. b. From the mud/gas separator vent line. c. Inside the mud/gas separator.
d. Downstream of the mud gas separator.
10. Why can a Vacuum Degasser not to be used in place of a Mud/Gas Separator during the control of a kick?
a. Because it has capacity limitations.
b. Because it is not sited in an explosion proof area. c. Because cuttings must be removed first
Gulf Technical & Safety Training centre Page 84 of 137
Section VIII
Volumes and BOP Testing
1. How much hydraulic fluid is required to close then open: - „Three pipe rams and One annular preventer‟
Annular Preventer: 35 gallons to close. 33 gallons to open. Pipe ram: 15 gallons to close. 12 gallons to open. Answer : …….gallons.
2. How much hydraulic fluid is required to close then open: - „Three pipe rams and One annular preventer‟
Without a safety margin, given the following fluid volumes: Annular Preventer: 28 gallons to close. 26 gallons to open. Pipe ram: 11 gallons to close. 9 gallons to open. Answer : …….gallons.
3. How much hydraulic fluid is required to close, open then close again: - „Three pipe rams and One annular preventer
Annular Preventer: 22 gallons to close. 18 gallons to open. Pipe ram: 16 gallons to close. 12 gallons to open Answer : ………….gallons.
4. How much hydraulic fluid is required to close, open then close again: - Three Pipe Rams, One Annular Preventer, one Kill Line and one Choke line valve‟.
Annular Preventer: 22 gallons to close. 20 gallons to open. Pipe ram: 16 gallons to close. 13 gallons to open Kill and Choke Line Valves: 1.5 gallon to close. 1.5 gallon to open Answer: ………….gallons.
5. In a BOP stack with one annular, three rams, an HCR on the kill line and an HCR on the choke line the following volumes are required:
Annular RAM HCR
Close 31.1 24.9 2 Open 31.1 23 2
How many gallons are required to close, open and close all functions? Answer: ………….gallons.
Gulf Technical & Safety Training centre Page 86 of 137 6. In the drawing of the Surface BOP stack, it requires 24.9 gallons to close and 23
gallons to open each Ram. The annular preventer requires 31.1 gallons to close and 31.1 gallons to open. Each HCR valve requires 2 gallons to open and the same volume to close. It is required to close, open and close all functions on the BOP, how many gallons of fluid will be required if a safety factor of 20% is included?
Show calculations below. Answer: ………….gallons.
Testing
1. When testing a Surface BOP stack with a test plug, the side outlet valves below the plug should be kept in the open position.
(Two Answers)
a. Because the test will create extreme hook loads. b. Because of potential damage to casing/open hole.
c. Otherwise reverse circulation will be needed to release test plug. d. To check for a leaking test plug.
2. Under what circumstances would a „CUP-TYPE‟ tester be used in preference to „TEST-PLUG‟ when testing a surface BOP stack.
a. There is no difference, they are interchangeable.
b. When you require to test entire casing head, outlets and casing to wellhead seals.
c. To test stack without applying excess pressure to wellhead and casing. 3. A test cup for 9-5/8 inch casing is used to test a BOP stack to a pressure of
10,000 psi using 5 inch drill pipe. The area of the test cup subjected to pressure is 42.4 square inches.
What is the MINIMUM grade of drill pipe to use (exclude any safety margin)? a. Grade E-75 premium drill pipe, tensile strength = 311,200 lbs.
b. Grade X-95 premium drill pipe, tensile strength = 394,200 lbs. c. Grade G-105 premium drill pipe, tensile strength = 436,150 lbs. d. Grade S-135 premium drill pipe, tensile strength = 560,100 lbs. e. Any grade will withstand the stress of the test.
Gulf Technical & Safety Training centre Page 88 of 137 4. When testing the BOP stack with a test plug or cup type tester in place, why is a
means of communication established from below the tool to atmosphere? a. To avoid the creation of extreme hook load.
b. To avoid potential damage to the casing/open hole.
c. Otherwise reverse circulation will be needed to release the tool. d. To avoid swabbing a kick during the test.
5. You are testing a Surface BOP stack with a test plug, the side outlet valves below the plug should be kept in the open position. (Choose two answers).
a. Because of potential damage to casing/open hole.
b. Otherwise reverse circulation will be needed to release test plug. c. Because the test will create extreme hook loads.
d. To check for a leaking test plug.
6. What pressure does the manufacturer use to test the body of a new 10,000 psi BOP? a. 15,000 psi.
b. 10,000 psi. c. 20,000 psi. d. 17,500 psi.
7. The body of a new BOP is given a hydrostatic body or shell test after manufacte. If the BOP has a Rated Working Pressure of 15,000 psi, what hydrostatic body test pressure is required according to API recommendations?
a. 15,000 psi. b. 17,500 psi. c. 20,000 psi. d. 22,500 psi. e. 25,000 psi
8. After connecting the open and close hoses to the BOP good practice would be to carry out which of the following first?
a. Take a slow circulating rate.
b. Drain accumulator bottles and check precharge. c. Function test all items on the stack.
d. Place all functions to neutral (block) position to charge up the hoses. 9. What is the first action that should be taken after connecting the open and close
hydraulic lines to the surface installed BOP stack?
a. Drain the accumulator cylinders and check the nitrogen precharge pressure. b. Function tests all items on the stack.
c. Place all functions in neutral position and start pressure testing the BOP stack. d. Perform accumulator unit pump capacity test.
10. According to API RP 53, 1997; BOP stacks should be pressure tested on a regular basis. This would include: (THREE answers)
a. After any disconnection or repair. b. Prior to a known high pressure zone. c. Not to exceed 21 days.
d. Prior to „spud‟. Or upon installation. e. After each new casing string.
11. When should a BOP function test be performed according to API RP53? a. Only after installation of the BOP stack.
b. At least once a week. c. Once per shift.
Gulf Technical & Safety Training centre Page 90 of 137 12. The lower kelly cock, upper kelly cock, drill pipe safety valve and inside BOP are
tools used to prevent flow from inside the drill string. To what pressure should these components be tested?
a. Two times the rated working pressure of the tool used (up to 5,000 psi).
b. One and a half times the rated working pressure of the tool used. c. Always use a pressure equal to 10,000 psi.
d. Test to a pressure at least equal to the maximum anticipated surface pressure, but limited to the maximum rated working pressure of the BOP stack in use.
13. Drillstring safety valves are required to be tested (According to API RP53): (TWO answers).
a. Less often than the BOP. b. Each time the BOP is tested. c. To the same pressure as the BOP. d. To the same RWP as the kelly/top drive.
14. What is the Rated Working Pressure for BOP equipment according to API RP 59?
a. Maximum anticipated bottom hole pressure. b. Maximum anticipated pore pressure.
c. Maximum anticipated surface pressure.
15. What is the correct definition for “Rated Working Pressure” according to API (SPEC 16E)?
a. The maximum test pressure the equipment is designed to contain and/or control.
b. The maximum internal pressure the equipment is designed to contain and/or control.
c. The hydrostatic proof test pressure a body or shell member shall hold prior to shipment from the manufacturer‟s facility.
16. Regarding the Rated Working Pressure (RWP) of a BOP, are the following statements true or false?
a. The criteria used to determine the required R.W.P. of a BOP is the maximum anticipated surface pressure.
□ True □False
b. The Rated Working Pressure of a BOP is the maximum internal pressure it is designed to hold.
□ True □False
17. How should the manually operated and hydraulically operated kill line valves on the BOP be pressure tested?
a. From the well bore side; with the check valve installed.
b. From the pump side; with the check valve removed so that the pressure can be bled off.
c. From the well bore side; with the check valve removed and the kill line vented.
d. From the pump side; because the check valve on the outside of the valves prevents the detection of a faulty valve if they are pressure tested from the
Gulf Technical & Safety Training centre Page 92 of 137
Section IX
BOP Control Unit
ACCUMULATOR UNIT – PART I
1. Match the items listed to the diagram.a. ………..…… Accumulator bottles. b. ………... …Electric pump.
c. ……….... …Hydro-electric pressure switch. d. ………. …Hydro-pneumatic pressure switch. e. ……… ….Air pump.
f. ……….. Air filter.
g. ……….. ….Annular pressure gauge. h. ………. Annular regulator.
j. ……… ……..Accumulator pressure gauge. k. ………...…...Accumulator pressure relief valve. l. ……….. ...…....Pressure transmitter (transducer) m. ………..…...Unit / Remote switch.
n. ………….….….. …Accumulator isolator valve. o. ………. By-pass valve.
p. …………..……….... Four way valve (4 way valves). q. ………. Manifold pressure gauge.
Gulf Technical & Safety Training centre Page 94 of 137 2. Figure below illustrates a hydraulic control schematic for a BOP Control
System.
Select the list below that indicates the valves that should be open while drilling. a. Valves; 2, 3, 5, 6, 7, 8, 11, 13, 14, 16, 17, 18.
b. Valves; 1, 3, 5, 7, 8, 10, 11, 14, 15, 17, 18. c. Valves; 2, 3, 4, 7, 9, 10, 12, 13, 15, 16, 18. d. Valves; 1, 2, 4, 5, 7, 8, 9, 11, 12, 14, 17.
3. Figure below illustrates a hydraulic control schematic for a BOP Control System.
Select the list below that indicates the valves that should be closed while drilling a. Valves; 1, 4, 9, 10, 12, 15.
b. Valves; 2, 4, 8, 10, 11, 15, 17. c. Valves; 3, 5, 7, 9, 13, 16, 18. d. Valves; 3, 4, 6, 9, 11, 16, 17.
Gulf Technical & Safety Training centre Page 96 of 137
Reservoir Tanks
1. What type of fluid should be used in the reservoir of the BOP Control Unit when temperatures below zero degrees centigrade (32 degrees fahrenheit) are expected?
(subsea)
a. Diesel oil. b. Kerosene.
c. Fresh water with added kerosene
d. Fresh water with added lubricant and glycol.
2. What is the minimum (API RP53) recommended capacity of the hydraulic fluid reservoir on the hydraulic BOP control unit?
a. Two times the usable fluid of the accumulator. b. Two times the closing volume of the BOP. c. Two times the accumulator capacity
3. The hydraulic control unit has a reservoir filled with hydraulic control operating fluid. The capacity of this reservoir should be equal to at least twice the usable fluid capacity of the closing unit system. What type of fluid should be used?
(subsea) (select two answers)
a. Fresh water containing lubricant. b. Salt Water.
c. Gearbox oil
d. Fresh water containing lubricant and glycol for ambient temperatures below 0 deg Celsius (32 deg Fahrenheit).
4. The closing unit should have a fluid reservoir to at least: a. The usable fluid capacity of the accumulator system. b. Twice the usable fluid.
