Equipment Questions.

Equipment Exercises Rev. 2011

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

Section IX BOP Control Unit

Gulf Technical & Safety Training centre 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. NoGulf Technical & Safety Training centre of 137

RAM

BLIND SHEAR RAM

SPOOL

ANNULAR

HCRHCR

Choke LineKill 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?

A. Yes B. No




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?

A. Yes B. No




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?

A. Yes B. No




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?

A. Yes B. No




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?

A. Yes B. No



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



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: ……………….



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



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,



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?

Valve Numbers: - ………………………………………..



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-...................................................................................



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










WELLHEAD

5” PIPE RAMS

BLIND/SHEAR RAMS

5” PIPE RAMS

ANNULAR PREVENTER(BAG)

MUDPUMP

MUDPUMP

KILLLINE

1

2

4

7

5 6

8 9

10

11 12 14

13 15 20

191817

16

MANUALCHOKE

REMOTECHOKE

MUD GASSEPERATOR

VENTLINE

FLAREBOOM

CEMENTPUMP

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.



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.

g. ............... …Support housing.

h. ................ …Flow Line.



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.



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.

f. Mud pumps running, pumping mud to the bottom of the well.



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.

f. Packing Unit.



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.

f. Packer.



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.

i. …………. Quick – Release Top.

j. …………. Locking Grooves.


1

23

4

56

7

8

9

10111213


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.



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

f. Opening chamber head.



7. Identify the parts of the Hydril GK.

Opening chamber Packing unit

Closing chamber Head (screw)

Piston



8. Identify the parts of the Shaffer.

Opening chamber

Closing chamber

Packing unit

Piston

Head (latched)



9. Identify the parts of the Cameron ‘D’ Type.

Opening chamber

Closing chamber

Packing unit (donut)

Packing/Sealing insert

Piston

Head (latched)

Ring groove



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

Piston Seals



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.

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.

16. A BOP stack is made up from the well head as follows: -Gulf Technical & Safety Training centre of 137


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 Gulf Technical & Safety Training centre of 137


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



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.

d. 300 psi less than the closing pressure of the ram operation.



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.



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

becomes worn.

d. To prevent any swelling when used during high temperature operations.



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

d. ………. Anti-extrusion plate



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

c. Locking devices keep rams closed if hydraulics fail.

□ True □False

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.

b. The fluid is used to boost closing pressure.

c. The fluid is returned to the reservoir.

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



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?

Answer: ………. psi

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.



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.

c. Shear/Blind rams in the intermediate position.



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.



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.

d. Only BX ring gaskets can be used with BX type flanges.

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.

c. Type RX.



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)


b. Type R Oval.

c. Type RX.

d. Type BX.



7. Figure below illustrates the cross-sectional profiles of four different API ring


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.


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 13-5/8 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



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


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

d. The total height of the two flanges assembly.



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.

Gulf Technical & Safety Training centre Page 62 of 137


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.).


(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.



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.

f. Is kept in its open position by a rod secured by a T-handle.



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.





Is it possible to get drill pipe back flow while tripping?

a. Yes.

b. No.



Is surge pressure generated when tripping in?

a. Yes.

b. No.



Is it possible to reverse circulating?

a. Yes.

b. No.



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

g. ………. Valve head

h. ………. Lower body

i. ………. Upper body

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

e. Floats should be run if shallow gas is anticipated.

TRUE FALSE

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.

d. Always when the rotary kelly hose 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).


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.



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.

d. To hold back pressure while circulating up a kick.



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 CHOKEMANIFOLD

MUD/GASSEPERATOR

TO SHALESHAKERS

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 CHOKEMANIFOLD

MUD/GASSEPERATOR

TO SHALESHAKERS

LIQUID SEAL

D1

D3

D2

H1

H2

H4


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 CHOKEMANIFOLD

MUD/GASSEPERATOR

TO SHALESHAKERS

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 CHOKEMANIFOLD

MUD/GASSEPERATOR

TO SHALESHAKERS

LIQUID SEAL

D1

D3

D2

H3

H1

H2

H4


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 CHOKEMANIFOLD

MUD/GASSEPERATOR

TO SHALESHAKERS

LIQUID SEAL10 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)

8.In the figure below. Which of the following dimension is the primary factor in


GAS TO VENT

FROM CHOKEMANIFOLD

MUD/GASSEPERATOR

TO SHALESHAKERS

LIQUID SEAL

D1

D3

D2

H1

H2

H4


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



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:


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


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’.


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?




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.




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.



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 psiGulf Technical & Safety Training centre of 137


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.



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.

d. Maximum anticipated hydrostatic drilling mud 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

well bore side.



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.

i. …………………….. …Manifold 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.



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.



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.

c. Three times the usable fluid.



Control Unit Pumps

1. How many independent sources of power should be available on each BOP

hydraulic control unit, according to API RP53?

a. Only one.

b. Not less than two.

c. It is the rig owner’s choice

2. Which type of power source should be available to operate the BOP control unit

pumps?

a. An electrical system.

b. An air system.

c. A dual air/electric system

d. A hydraulic system.

3. API RP53 states that each closing unit should be equipped with sufficient number

and sizes of pumps to satisfactorily perform the closing unit capacity test.

With the accumulator system isolated, the pumps should be capable of closing

the annular preventer on the size of drill pipe being used, open the

hydraulically operated choke line valve and obtain a minimum of 200 psi

pressure above accumulator pre-charge pressure on the closing unit manifold.

This should be achieved within: -

a. 1 minute or less.

b. 2 minutes or less.

c. 3 minutes or less

d. 4 minutes or less.



4. What is the minimum pressure at which the charge pumps start up, according to

API RP53?

a. When accumulator pressure has decreased to less than 50% of the operating

pressure.

b. When accumulator pressure has decreased to less than 75% of the operating

pressure.

c. When accumulator pressure has decreased to less than 90% of the operating

pressure.



Accumulator Bottles

1. When should a pre-charge pressure test be conducted on the accumulator bottles?

a. It is not necessary to conduct a test as pre-charge pressure losses are not

expected.

b. It should be conducted prior to the start up of each well.

c. It should be conducted once per shift.

d. It should be conducted during the weekly BOP test.

2. Which gas is used to pre-charge the accumulator bottles on a BOP Hydraulic

Control Unit?

a. Air.

b. Nitrogen.

c. Oxygen.

d. Carbon Dioxide (CO2).

e. Methane.

3. What is the minimum recommended (API RP53) pre-charge pressure for the

accumulator bottles on a 3000-psi Hydraulic Control Unit?

a. 3000 psi.

b. 1000 psi.

c. 1200 psi.

d. 200 psi.

4. Nitrogen is the gas used to pre-charge accumulator bottles.

TRUE FALSE



5. The purpose of having stored fluid under pressure in the accumulator bottles is:

(Two Answers)

a. To operate the IBOP in the Top Drive

b. To enable the BOP to be closed in the event of a power failure.

c. To activate the emergency packing on the Rams.

d. To operate the remote choke.

e. To reduce the closing time of BOP functions.

6. What is the correct definition of ‘usable fluid volume’ in an accumulator’?

a. The total volume to be stored in the accumulator bank.

b. The total volume to be stored in the accumulator cylinders.

c. The total volume recoverable from the cylinders between the accumulator

operating pressure and the minimum operating pressure.

d. The total volume recoverable from the cylinders between the accumulator

operating pressure and the pre-charge pressure.

e. The total volume recoverable from the cylinders between the accumulator

operating pressure and 500 psi above the pre-charge pressure.

7. What is the usable fluid volume of an accumulator bottle, according to API

requirements?

a. The total volume to be stored in the accumulator bottle.

b. The volume of fluid recoverable from an accumulator bottle, between

the accumulator operating pressure and 200 psi above the bottle pre-

charge pressure.

c. The volume of fluid recoverable from an accumulator bottle, between

the accumulator operating pressure minus 200 psi and pre-charge

pressure.



8. A BOP hydraulic control unit accumulator bank has 20 cylinders: -

Cylinder capacity (Nitrogen & Fluid) - 10 gallons.

Accumulator pre-charge pressure - 1,000 psi.

Accumulator operating pressure - 3,000 psi.

Minimum accumulator operating pressure - 1,200 psi.

Calculate the total usable fluid volume for the accumulator bank?

a. 40 gallons.

b. 100 gallons.

c. 66 gallons.

d. 200 gallons.

9. A BOP hydraulic control unit accumulator bank has 12 cylinders.

Cylinder capacity (Nitrogen & fluid) - 10 gallons.

Accumulator pre-charge pressure - 1,000 psi.

Accumulator operating pressure - 3,000 psi.

Minimum accumulator operating pressure - 1500 psi.

Calculate the total usable fluid volume for the accumulator bank?

a. 40 gallons.

b. 27 gallons.

c. 66 gallons.

d. 43 gallons.

10. A.P.I. RP53 recommends a minimum operating pressure of 1200 psi and a

maximum operating pressure of 3000 psi. How much usable fluid would you get

from a 10 gallon capacity bottle?

Answer …. Gallons



11. If the capacity of the bottle in the last question was increased to 25 gallons how

much usable fluid would you now have?

Answer ……. Gallons

12. An accumulator system has 24 ten-gallon capacity bottles. How many gallons of

usable fluid are available according to recommendations stated in A.P.I. RP53. -

Maximum operating pressure 3,000 psi - minimum operating pressure 1,200 psi.

a. 240 gallons

b. 480 gallons

c. 120 gallons

d. 100 gallons

13. The following data is given for a surface installed ram type BOP stack.

Nominal size (throughbore) - 13-5/8 inch

Maximum rated working pressure - 15,000 psi

Closing Ratio - 10.6 : 1

Hydraulic fluid requirements (including safety factor) for all functions on this

BOP stack is 150 gallons.

The data for one accumulator bottle is: -

Cylinder capacity (Nitrogen & fluid) - 10 gallons (ignore bladder)

Pre-charge pressure - 1,000 psi

Operating pressure for BOP control unit - 3,000 psi

Calculate the minimum number of accumulator cylinders required in the

accumulator bank to enable closing the ram BOPs on the full Rated Working

Pressure of the BOP.

a. 30 cylinders.

b. 36 cylinders.

c. 41 cylinders.

d. 51 cylinders.



14. The following data is given for a surface installed ram type BOP stack.

Nominal size (throughbore) - 13-5/8 inch

Maximum rated working pressure - 15,000 psi

Closing Ratio – 10 : 1

Hydraulic fluid requirements (including safety factor) for all functions on this

BOP stack is 118.6 gallons.

The data for one accumulator bottle is: -

Cylinder capacity (Nitrogen & fluid) - 10 gallons (ignore bladder)

Pre-charge pressure - 1,000 psi

Operating pressure for BOP control unit - 3,000 psi

Calculate the minimum number of accumulator cylinders required in the

accumulator bank to enable closing the ram BOPs on the full Rated Working

Pressure of the BOP.

a. 12 cylinders.

b. 24 cylinders.

c. 36 cylinders.

d. 48 cylinders.



15. 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:

Close (Gallons) Open (Gallons)

Annular 31.1 31.1

RAM 24.9 23

HCR 2 2

a. How many gallons are required to close, open and close all functions?

Answer ………. Gallons

b. The operator’s requirements as per API RP53 are for a minimum

operating pressure of 1200 psi. How many 10 gallon capacity

accumulator bottles are required to provide enough useable fluid.

Answer ……. Bottles

16. 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.

a. What is the minimum closing pressure required for the BOP?

Answer ………. PSI

b. Hydraulic fluid requirement to close, open and close all functions is 258

gallons. How many 10 gallon accumulator bottles will be required?

Answer ………. Bottles



4-Way Valves

1. 3 position/4 way valves are used on a BOP control unit to control stack functions.

Which of the following statements are true?

(TWO ANSWERS)

a. They are capable of manual operation.

b. They cannot be remotely operated.

c. They can be placed in 4 positions.

d. They have four active connections (inlets/outlets).

2. While drilling, what is the correct position of the selector valves (3-position/ 4-

way valves) on the BOP hydraulic control unit?

a. All valves in the open position.

b. All valves in the closed position.

c. All valves in the neutral position.

d. Open or closed, depending on stack function.

3. On the hydraulic BOP control unit for a surface BOP stack a number of selector

valves are installed. (Selector valves control the BOP functions).

Which is the correct description of a selector valve?

a. A selector valve is a 3 position/4 way directional control valve that has the

pressure inlet port blocked, the operator ports blocked and the pressure trapped

in the centre position.

b. A selector valve has two or more supply pressure ports and only one outlet

port. When fluid is flowing through one of the supply ports the internal shuttle

seals off the other inlet port and allows flow to the outlet port only.

c. A selector valve is a three position directional control valve that has the

pressure inlet port blocked and the operator ports vented in the centre position.



4. In what position should the BOP operating (4-way) valves be in during drilling

operations?

a. Open

b. Closed

c. Open or closed depending on item of equipment



Hi-Lo Bypass Valve

1. On the remote panel the High-Low bypass valve allows you to put full accumulator

pressure to which of the following.

a. Rams only.

b. Annular only.

c. All functions.

d. Rams and H.C.R. valves only.

2. On which ram operation would you be most likely to use the by-pass

(manifold valve) facility?

a. Variable bore rams.

b. Blind/Shear rams.

c. 5 inch pipe rams.

d. 3-1/2 inch pipe rams.

3. What is the purpose of the by-pass valve on a surface BOP Hydraulic Control

Unit?

a. To bleed the accumulator fluid back to the reservoir.

b. To by-pass the 4-way valves.

c. To enable full accumulator pressure to be placed on the annular BOP.

d. To enable full accumulator pressure to be placed on the Ram/HCR closing unit

manifold.



4. What is the purpose of the “bypass” button on the driller’s remote control panel for

a surface BOP installation?

a. To increase the hydraulic annular pressure to existing accumulator pressure.

b. To increase the hydraulic accumulator pressure to 3,000 psi.

c. To increase the hydraulic manifold pressure to 2,000 psi.

d. To increase the hydraulic manifold pressure to existing accumulator pressure.



Unit Remote Function

1. If the “UNIT/REMOTE switch on a surface BOP hydraulic control unit is placed

in “UNIT” position, which of the following is true? (TWO ANSWERS)

a. All BOP functions can be operated from the Driller’s Remote BOP Control

Panel.

b. No BOP functions can be operated from the Driller’s Remote BOP Control

Panel.

c. The hydraulic annular pressure regulator cannot be adjusted from the

Driller’s Remote BOP Control Panel.

d. The air-operated pumps are isolated.

2. The Annular “unit/remote” switch on the accumulator allows you to do what when

“unit” is selected.

a. Adjust the annular regulator from the remote panel.

b. Adjust the manifold regulator from the accumulator.

c. Adjust the manifold regulators from the remote panel.

d. Adjust the annular regulator from the accumulator.



Sequence of Operation and Pressures

1. What happens when the handle on the BOP remote control panel is activated to

close the upper ram preventer? (The master valve has been operated)

a.The handle opens the hydraulic valve in the back of the remote control panel

and hydraulic fluid flows to the preventer.

b.The handle operates an electric switch in the back of the remote panel. The

electric current operates the hydraulic valve at the accumulator unit and this

enables the hydraulic fluid to flow to the preventer.

c.The handle operates an air valve in the back of the remote panel. The air

activates a piston at the accumulator unit that operates the 4-way valve

enabling the flow of hydraulic fluid to the preventer.

2. On which gauges on a remote BOP control panel would a reduction in pressure be

observed when the 3-1/2 inch pipe rams are closed? (TWO ANSWERS)

a. Air Pressure Gauge.

b. Accumulator Pressure Gauge.

c. Manifold Pressure Gauge.

d. Annular Pressure Gauge.

3. On which gauges on a BOP remote control panel will a reduction in pressure be

observed when the Annular preventer is being closed? (TWO ANSWERS)

a. Air pressure gauge.

b. Accumulator pressure gauge.

c. Manifold pressure gauge.

d. Annular pressure gauge.



4. On which gauges on the BOP remote control panel would a reduction in pressure

be observed when the blind/shear ram is closed? (TWO ANSWERS)

a. Air pressure gauge.

b. Accumulator pressure gauge.

c. Manifold pressure gauge.

d. Annular pressure gauge.

5. Answer the following questions using the diagram of a drillers remote control

panel.

A. What are the normal operating pressures seen on the following gauges on the

driller's remote panel?

Gauge No 1 ……… psi

Gauge No 2 …….… psi

Gauge No 3 ……… psi

Gauge No 4….. psi



B. If Gauge No 2 on the remote panel reads zero which of the following

statements is true?

a. The annular preventer can still be operated from the remote panel.

b. Choke and kill lines can still be operated from the remote panel.

c. No stack function can be operated from the remote panel.

d. All functions on the remote panel will operate normally.

C. On which two gauges on the remote panel would you expect to see a reduction

in pressure when the annular preventer is being closed?

a. Gauge 1 & 2

b. Gauge 2 & 4

c. Gauge 3 & 4

d. Gauge 1 & 4

e. Gauge 3 & 2

6. Which of the following functions on a BOP is supplied from Manifold Pressure?

(TWO ANSWERS)

a. Ram BOP Preventers.

b. Hydraulically operated choke and kill line valves.

c. Annular BOP Preventer

d. All BOP stack functions.

7. What is the NORMAL Accumulator pressure reading on a 3000-psi Hydraulic

Control Unit?

a. 3000 psi.

b. 2500 psi.

c. 1500 psi.

d. 700 - 1500 psi.Gulf Technical & Safety Training centre of 137


8. What is the NORMAL Manifold pressure reading on a 3000 psi Hydraulic Control

Unit?

a. 3000 psi.

b. 2500 psi.

c. 1500 psi.

d. 1000 psi.

9. What is the NORMAL Annular pressure reading on a 3,000 psi Hydraulic Control

Unit?

a. 250 psi.

b. 600 – 1,500 psi.

c. 3,000 psi.

10. What would the pressure on the ram opening lines between the BOP Hydraulic

Control Unit and the BOP stack normally be while drilling?

a. Zero.

b. 500 psi.

c. 1,500 psi.

d. 3,000 psi.

11. Which function on a BOP stack is supplied from the annular pressure regulator?

a. Rams and hydraulically operated choke and kill line valves.

b. Annular preventer only.

c. Annular preventer and hydraulically operated choke and kill line valves.

d. Ram preventer, annular preventer and hydraulically operated choke and kill line

valves.

e. No function is supplied with this pressure; the value on the gauge only indicates

the maximum allowable working pressure for the annular preventer in use.



12. What pressure rating should we have on valves and fittings between the closing

unit and the blowout preventer. (10,000 psi)

a. 1,500 psi

b. 3,000 psi

c. 10,000 psi



Closing Times

1. What is the closing time for a ram type BOP - according to API RP53?

a. Less than 30 seconds.

b. Less than 45 seconds.

c. Less than 2 minutes.

2. What is the closing time for a 20 inch Annular BOP - according to API RP53




3. What is the maximum recommended closing time for a 13-5/8 inch Annular BOP -

according to API RP53?




4. What is the closing time for a 21-1/4 inch surface annular BOP - according to API RP53




5. What is the recommended closing time according to API RP 53 for the following

components? Surface Stack

13 5/8” 15K RWP Ram ………………... Seconds

21 ¼” 5K RWP Annular ………………. Seconds

16 3/8” 5K RWP Annular …………… Seconds

11” 5K RWP Ram …………………… Seconds



Master Valve

1. What is the purpose of the master control valve on an air operated remote BOP

control panel?

a. Activates the hydraulic fluid circuit at the panel.

b. Activates the air circuit at the panel.

c. Activates the electric circuit for the open/close lights.

d. Adjusts pipe ram closing pressure.

2. What is the function of the master control valve on the remote BOP control panel

on the rig floor?

a. To allow pressuring up of the 4-way valves on the hydraulic control unit.

b. To activate the open or close lights.

c. To activate power to the control unit charge pumps.

d. To allow pressuring up of the control valves on the remote BOP control panel.

3. On the remote BOP control panel on the rig floor, the master control valve

handle/button must be held depressed for five seconds then released before

operating a BOP function.

a. True.

b. False.

4. On the remote BOP control panel on the rig floor, the master valve handle/button

must be held depressed while BOP functions are operated.

a. True.

b. False.



5. On the remote BOP control panel on the rig floor, the master control valve allows

air pressure to go to each function in preparation for operating the handle/button.

a. True.

b. False.

6. On the remote BOP control panel on the rig floor, if a function is activated without

operating the master control valve - that function will work.

a. True.

b. False.

7. If a function is operated on the remote BOP control panel without operating the

master control valve, how will the function work?

a. Slower.

b. Faster.

c. The same.

d. Will not work at all.

8. Which of the following procedures is the correct one to activate a BOP function

from the Driller’s electric remote control panel on a surface BOP stack

installation?

a. The master button must be depressed for 5 seconds and then released before a

BOP function button is depressed.

b. The master button must be held depressed while a BOP function button is

depressed.

c. The BOP function button is depressed and then released. The master button

must then be depressed to activate the function.



9. Which of the following correctly describes the operation of the master valve on the

BOP remote panel?

a. The master valve when operated moves the 3 position valve to the close

position.

b. The master valve when operated will do a panel light test.

c. The master valve must be continually operated whilst functions on the panel

are made.

d. Holding the master air valve for 5 seconds then releasing it will allow

functions to take place.

10. The correct reason for operating the master air valve for 5 seconds prior to the

function on a remote B.O.P. panel is:

a. To check the rig air pressure is correct.

b. To allow a buildup of air pressure to operate the 3 position valve.

c. To bleed air from the system.

d. To give the operator time to think about what he is doing.

11. Which of the following statements is true concerning the remote B.O.P panel:

a. The master valve when operated moves the 3 position valve to the close position.

b. The master valve when operated will do a panel light test.

c. The master valve must be continually operated whilst functions on the panel are

made.

d. Holding the master air valve for 5 seconds then releasing it will still allow

functions to take place.

12. The following statements relate to the Driller's remote control panel on the rig floor.



For each statement circle what you think is the correct answer.

a.The master control valve when activated supplies air to the other control valves.

TRUE FALSE

b.The master control valve must be operated if other functions are to operate.

TRUE FALSE

c.If you operate a function without operating the master control valve that function

will not work.

TRUE FALSE

d.If you operate the master control valve and a function together that function will

not work.

TRUE FALSE

e.If the upper ram close light on the panel illuminates you know the ram is closing.

TRUE FALSE

f. When the close light on the panel illuminates then you know the 3 position valve

on the accumulator has moved to the close position.

TRUE FALSE

g.Operating the master control valve only will illuminate all lights on the panel.

TRUE FALSE



Remote Panel

1. Where are the electric (activating) switches for the BOP remote control panel

lights located?

a. On the pressure gauge mounted on the remote control panel.

b. On the BOP hydraulic control unit.

c. Inside the BOP operating chambers.

d. On the remote control panel operating handles.

2. Only a small volume of fluid is required to operate the hydraulic valves on the

BOP side outlets on a surface BOP installation.

On a Driller’s air operated panel, if the Driller pushes “Master’ and “Choke

open” simultaneously - he observes that the lights change colour.

Do the changing lights confirm that the choke line valve is in the open

position?

a. Yes. b. No

3. On a driller’s remote B.O.P. control panel you close the annular preventer and the

close light illuminates. What is the light telling you?

a. A hydraulic signal has been sent to the accumulator unit.

b. The annular has closed.

c. The annular 4 way valve on the accumulator unit has functioned and fluid

should be going to the annular.

d. A microswitch in the back of the Driller’s remote B.O.P. control panel has

been activated, indicating that you have pushed the lever to the close

position.

4. The B.O.P stack function has taken place when the indicator light has illuminated on

the remote control panel.

TRUE FALSE



ACCUMULATOR UNIT PART II

USING THE ABOVE DIAGRAM ANSWER THE FOLLOWING QUESTIONS

1.What are the normal operating pressures seen on the following gauges on the drillers

remote panel?

a. Gauge No 1 ……….. psi

b. Gauge No 2 …….... psi

c. Gauge No 3 …….... psi

d. Gauge No 4 ….. ….. psi

2.If Gauge No 1 on the remote panel reads zero which of the following statements is

true?

a. The annular preventer can still be operated from the remote panel

b. Choke and kill lines can still be operated from the remote panel

c. No stack function can be operated from the remote panel

d. All functions on the remote panel will operate normally


WELLHEAD

3 1/2” PIPE RAMS

DRILLINGSPOOL

5” PIPE RAMS

BLIND/SHEAR RAMS

ANNULAR PREVENTER(BAG)

AIR OPERATED REMOTE PANEL

1. AIR

2. ACCUMULATOR

3. RAMMANIFOLD

4. ANNULARMANIFOLD


3.On which two gauges on the remote panel would you expect to see a reduction in

pressure when the annular preventer is being closed?

a. Gauge 1 & 2

b. Gauge 2 & 4

c. Gauge 3 & 4

d. Gauge 1 & 4

e. Gauge 3 & 2

4.You close a ram on the Driller's remote B.O.P control panel. The close light for that

function illuminates but you notice that the manifold pressure gauge does not drop.

What has happened?

a. Air supply has been lost to the Driller's panel

b. 4-way ram valve on accumulator unit has failed to shift

c. Blockage in line between accumulator unit and B.O.P stack

d. You forgot to hold down the master control valve for 5 seconds as instructed

5.When shutting in a well from the remote B.O.P panel, a number of problems may

occur that makes you wonder whether the selected function has operated. From the

chart below place an "X" in the box or boxes where the problem may relate to the

cause.

Note: There may be more than one answer for a problem.



PROBABLE CAUSE CHART

PROBLEM Master

valve not

held

down

3 Position

Valve not

moved

Closed

line

blocked.

Leak in

line or

BOP.

Air lost. Bulb

blown.

Close light does

not illuminate but

pressure drops and

later recovers.

Light does not

illuminate and

pressure gauge

does not drop.

Pressure gauge

drops but does not

rise back up.

Light illuminates

but pressure gauge

does not drop.



6. On the Driller’s air operated panel for a surface BOP the ram close operated and

the following was seen:

Green light went out.

Red light came on.

Annular pressure did not change.

Manifold pressure decreased and later returned to the original position.

Accumulator pressure decreased to 2500 psi and remained steady.

What is the most probable cause of the problem?

a. There is a blockage in the hydraulic line connecting the BOP to the BOP

control unit.

b. There is a leak in the hydraulic line connecting the BOP to the BOP control

unit.

c. The selector valve (3 position/4 way valve) is stuck in the open position.

d. The pressure switch or the pumps on the BOP control unit did not work.

e. Electric position switches are malfunctioning.



7. On the driller’s pnenumatically operated panel for a surface installed BOP, a ram

close function was activated and the following observations were made:

Green light remained on.

Red light remained off.

Annular pressure did not change.

Manifold pressure did not change.

Accumulator pressure did not change.

What is the probable cause of the problem?

a. The selector valve (3 position/4 way valve) is stuck in the open position.

b. There is a leak in the hydraulic line connecting the BOP to the BOP control

unit.

c. Electric pressure switches are malfunctioning.

d. The pumps on the BOP control unit are malfunctioning.

e. There is a blockage in the hydraulic line connecting the BOP to the control

unit.

8. If the manifold gauge on the remote BOP control panel reads zero and other

gauges read normal values, which of the following statements is true?

a. Everything is correct.

b. The annular preventer can still be operated from the remote panel.


d. All stack functions can be operated from the remote panel.



9. When shutting in the well from the Remote BOP Panel the normal sequence may

not occur.

What has happened if the close light does not illuminate, but the gauge drops and

later rises backup?

a. The 4-way valve on hydraulic closing unit failed to shift.

b. The hydraulic closing line to the BOP is plugged.

c. There is a leak in the hydraulic line to the BOP.

d. The bulb has blown.

10. If the air pressure gauge on the remote BOP control panel reads zero, which of

the following statements is true?

Choke and kill line valves can still be operated from the remote panel.

a. All stack functions can be operated from the remote panel.

b. The annular preventer can still be operated from the remote panel.


11. When shutting in the well at the BOP Panel a problem may occur that causes

doubt about whether the selected function has operated.

What has happened if the light does not illuminate and pressure gauge does

not drop?







12. When shutting in the well from the Remote BOP Panel the normal sequence may

not occur.

What has happened if the pressure gauge drops but does not rise back up?





13. When shutting in the well at the BOP Panel, a problem may occur that causes

doubt about whether the selected function has operated.

What has happened if the light illuminates but the pressure gauge does not

drop?





14. When closing the upper rams from the remote control panel on the rig floor the

green light indicator goes out but the red light indicator does not come on. The

Accumulator pressure and the Manifold pressure readings decrease and then

return to normal.

What could be the reason for this?

a. The 4-way valves on the BOP hydraulic control unit did not move.

b. There is a leakage on the hydraulic circuit.

c. The rams did not close.

d. There is an electrical fault with the lights.



15. A pipe ram has been operated from the remote panel. The accumulator and

manifold pressures have dropped by 400 psi, but only the manifold pressure has

returned to normal.

What is the cause of the problem?

a. Hydraulic closing line to BOP is leaking.

b. The 4-way valve has not actuated.

c. The charge pumps are not working.

16. When closing the upper rams, by operating the handle on the BOP remote control

panel, the accumulator and manifold pressures decrease but the close light does

not illuminate.

What is the reason for this?

a. The 4-way valve on the accumulator unit did not move.

b. There is a leak on the hydraulic unit.

c. The rams did not close.

d. The electric switch that activates the close light circuit failed.



17. You are drilling ahead and the gauges on the Accumulator unit show:

(The BOP has not been operated and the charge pump is not running).

Select the best answer

a. Everything OK.

b. There is a leak in the hydraulic system.

c. There is a malfunction in the pressure transducer assembly.

d. There is a malfunction in the hydraulic regulators.

e. Faulty pump stop/start switch.

18. You are drilling ahead and the gauges on the accumulator unit show:



a. Everything is OK

b. There is a leak in the hydraulic system

c. There is a malfunction in the pressure transducer assembly

d. There is a malfunction in the hydraulic regulator




19. You are drilling ahead and the gauges on the accumulator unit show:



a. Everything is OK.



d. There is a malfunction in the hydraulic regulators.


20. After stopping drilling and closing the annular, annular pressure dropped and

recovered, now the accumulator unit shows:


a. Everything is OK.





d. There is a malfunction in the regulators.


21. You are drilling ahead and the gauges on your BOP accumulator control system

reads as follows: (the BOP has not been operated and the charge pump is not

running).


a. Everything OK

b. There is a leak at one of the accumulator bottles

c. There is a malfunction in the remote panel master switch/handle

d. There is a malfunction in a hydraulic regulator

e. Electric motor stop/start switch is faulty


ACCUMULATORPRESSURE

MANIFOLDPRESSURE

ANNULARPRESSURE

3000 psiCONSTANT

1500 psiCONSTANT

600 psiDECREASING


22. You are drilling ahead and the gauges on your BOP accumulator control system

reads as follows: (the BOP has not been operated).


a. Everything is OK


c. There is a malfunction in the remote panel master switch/handle

d. There is a malfunction in the manifold hydraulic regulator



ACCUMULATORPRESSURE

MANIFOLDPRESSURE

ANNULARPRESSURE

3200 psiINCREASING

1500 psiCONSTANT

900 psiCONSTANT


23. You are drilling ahead and the gauges on your BOP accumulator unit system reads

as follows: (the BOP has not been operated and the charge pump is not running).


a. Everything is O.K


c. There is a malfunction in the pressure transducer assembly

d. There is a malfunction in the regulators


f. D and E are correct


ACCUMULATORPRESSURE

MANIFOLDPRESSURE

ANNULARPRESSURE

3000 psiCONSTANT

1500 psiCONSTANT

900 psiCONSTANT




What is the likely reason for the change?

a. Everything is correct.

b. Leakage on the hydraulic circuit.

c. Problem with the automatic hydro-electric pressure switch.

d. Leaking by-pass valve.


ACCUMULATORPRESSURE

MANIFOLDPRESSURE

ANNULARPRESSURE

3000 psiCONSTANT

3000 psiCONSTANT

900 psiCONSTANT





a. Fault on the annular regulator.

b. Leak on the hydraulic circuit.

c. Problem with the automatic hydro-electric pressure switch.

d. Fault on the manifold regulator.


ACCUMULATORPRESSURE

MANIFOLDPRESSURE

ANNULARPRESSURE

2800 psiDECREASE

1700 psiINCREASE

900 psiCONSTANT





a. Problem with the by-pass valve.

b. Everything is correct.

c. Problem with the charging pump.

d. Leak in the hydraulic circuit.


ACCUMULATORPRESSURE

MANIFOLDPRESSURE

ANNULARPRESSURE

2800 psiDECREASE

1300 psiDECREASE

900 psiCONSTANT

Equipment Questions.

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