IWCF practice questions

8/10/2019 IWCF practice questions

1/95

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. YesB. 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. YesB. 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 chokeline?

A. YesB. No

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 underpressure?

A. Yes B. No


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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. YesB. No

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. YesB. No


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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. YesB. No

d. With the well shut in on 5 pipe rams under pressure, is it possible to change blind

rams to 5 pipe rams?

A. YesB. No

e. With the well shut in on 5 pipe rams under pressure, can the annular element be replaced?

A. YesB. 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


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5/95

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

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. YesB. No

b. With no drillstring in the hole and the well shut-in on blind/shear rams, can we

repair the HCR valve?

A. YesB. 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. YesB. No


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7/95

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?

1. Valve Nos. 2, 4, 5, 7, 8, 10, 14, 16, 25

2. Valve Nos. 1, 4, 5, 6, 8, 9, 10, 11, 12, 19, 25

3. Valve Nos. 2, 4, 7, 9, 10, 12, 15, 18, 25

4. Valve Nos. 1, 3, 10, 11, 14, 19, 25

5. Valve Nos. 1, 4, 9, 10, 11, 12, 14


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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 - 7 - 8 - 9 - 25


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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?


1. Valve Nos. 2, 7, 8, 9, 16, 25, 17, 18, 19

2. Valve Nos. 2, 3, 7, 8, 10, 11, 14, 19

3. Valve Nos. 2, 7, 9, 11, 12, 15, 18

4. Valve Nos. 1, 3, 7, 8, 10, 11, 13, 14, 19

5. Valve Nos. 2, 7, 8, 9, 10, 11, 12, 14, 20

6. Valve Nos. 2, 3, 7, 8, 10, 13, 16, 17, 25


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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.


1. Valve Nos. 2, 3, 5, 8, 9, 10, 11, 14, 19,

2. Valve Nos. 1, 3, 4, 6, 7, 8, 10, 11, 13, 18, 25

3. Valve Nos. 3, 7, 8, 9, 10, 11, 12, 19, 25

4. Valve Nos. 2, 3, 5, 8, 9, 10, 11, 12, 15, 17,

5. Valve Nos. 3, 5, 8, 9, 10, 11, 14, 16, 19, 25

6. Valve Nos. 2, 3, 4, 6, 7, 8, 9, 10, 11, 14, 16,


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5. Which valves would need to be open to circulate, using the mud pump, down the d

rillstring, through the remote choke and mud gas separator?

Valve Numbers:1 3 6 7 8 9 10 16

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?


12/95

Valve Numbers: 2 - 4 - 5 - 6 - 7 - 13 - 14 - 15 - 16

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?


13/95

Valve Numbers: 1 OR 2 - 7 - 8 - 9 - 16 - 17 - 18 - 19 - 25


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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 OpenClosed










15/95

Volumes to Open & Close

1. How much hydraulic fluid is required to close then open: -

Three pipe rams and One annular preventer

Annular Preventer: 35gallons to close. 33 gallons to open.

Pipe ram: 15 gallons to close. 12 gallons to open.

Answer : 149.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.


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


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


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 2Open 31.1 23 2

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

Answer : 323.7.gallons.

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?


16/95

SHOW CALCULATIONS BELOW.

Answer : 388.4.gallons.


17/95

Testing/Wellheads/etc

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)

1. Because the test will create extreme hook loads.

2. Because of potential damage to casing/open hole.

3. Otherwise reverse circulation will be needed to release test plug.

4. To check for a leaking test plug.

2. Under what circumstances would a CUP-TYPE tester be used in preference to

a TEST-PLUG when testing a surface BOP stack.

1. There is no difference, they are interchangeable.

2. When you require to test entire casing head, outlets and casing to wellhead seals.

3. 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)?

1. Grade E-75 premium drill pipe, tensile strength = 311,200 lbs.

2. Grade X-95 premium drill pipe, tensile strength = 394,200 lbs.

3. Grade G-105 premium drill pipe, tensile strength = 436,150 lbs.

4. Grade S-135 premium drill pipe, tensile strength = 560,100 lbs.

5. 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?

1. To avoid the creation of extreme hook load.2. To avoid potential damage to the casing/open hole.

3. Otherwise reverse circulation will be needed to release the tool.

4. 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).

1. Because of potential damage to casing/open hole.

2. Otherwise reverse circulation will be needed to release test plug.

3. Because the test will create extreme hook loads.

4. 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?

1. 15,000 psi.

2. 10,000 psi.

3. 20,000 psi.

4. 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


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test pressure is required according to API recommendations?

1. 15,000 psi.

2. 17,500 psi.

3. 20,000 psi.

4. 22,500 psi.

5. 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?

1. Take a slow circulating rate.

2. Drain accumulator bottles and check precharge.

3. Function test all items on the stack.

4. 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?

1. Drain the accumulator cylinders and check the nitrogen precharge pressure.

2. Function test all items on the stack.

3. Place all functions in neutral position and start pressure testing the BOP stack.

4. 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)

1. After any disconnection or repair.

2. Prior to a known high pressure zone.

3. Not to exceed 21 days.

4. Prior to spud.

5. After each new casing string.

11. When should a BOP function test be performed according to API RP53?

1. Only after installation of the BOP stack.

2. At least once a week.

3. 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?

1. Two times the rated working pressure of the tool used (up to 5,000 psi).

2. One and a half times the rated working pressure of the tool used.

3. Always use a pressure equal to 10,000 psi.

4. 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).

1. Less often than the BOP.


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2. Each time the BOP is tested.

3. To the same pressure as the BOP.

4. To the same RWP as the kelly/top drive.

14. What is the Rated Working Pressure for BOP equipment according to API RP 59

1. Maximum anticipated bottom hole pressure.

2. Maximum anticipated pore pressure.

3. Maximum anticipated surface pressure.

4. Maximum anticipated hydrostatic drilling mud pressure.

5. Maximum anticipated dynamic choke pressure.

15. What is the correct definition for Rated Working Pressure according to

API (SPEC 16E)?

1. The maximum test pressure the equipment is designed to contain and/or control.

2. The maximum internal pressure the equipment is designed to contain and/or control.

3. The hydrostatic proof test pressure a body or shell member shall hold prior to

shipment from the manufacturers facility.

16. Regarding the Rated Working Pressure (RWP) of a BOP, are the following statements

true or false?

1. The criteria used to determine the required R.W.P. of a BOP is the maximum

anticipated surface pressure.

TrueFalse

2. The Rated Working Pressure of a BOP is the maximum internal pressure it is

designed to hold.

TrueFalse

17. When testing a pipe ram at the weekly B.O.P test you are informed that the Weep hole on

the ram is leaking fluid.

What action would you take?

1. The 'weep hole' only checks the closing chamber seals so leave it till next maintenance

schedule.

2. Energise emergency plastic packing ring. If leak stops then leave it till next

maintenance schedule.

3. Primary mud seal is leaking and you should repair immediately.

4. Ram packing elements on ram body are worn and should be replaced immediately.

5. A leak here is normal because metal sealing faces in the ram need some lubrication to

minimise damage.


20/95

Flanges

1. Figure below illustrates the profile of an API 6BX type flange.

API Type 6BX Flange

Which number indicates the Nominal flange dimension?

1. Dimension No. 1.2. Dimension No. 2.

3. Dimension No. 3.

4. 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?

1. API type 6B.

2. API type 6BX.

3. What is the meaning of 6BX when referring to a flange?

1. Type.

2. Serial Number.

3. Dimension.

4. Trademark.

4. Which of the following statements about ring gaskets are correct?

(TWO ANSWERS)

1. Ring gaskets may be used several times

2. The same material specifications apply to ring gaskets as to ring grooves.

3. Type RX and BX ring gaskets provide a pressure-energised seal.

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


21/95

5

. Figure below shows an API Type 6BX Flange

T

he 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.

1. Type R Octagonal.

2. Type R Oval.

3. Type RX.

4. Type BX.


22/95

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)


2. Type R Oval.

3. Type RX.

4. Type BX.

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.


2. Type R Oval.

3. Type RX.

4. Type BX.

8. What is a 7-1/16, 10,000 psi flange?

1. It is designed for RX ring gasket type.

2. It has a 10,000 psi test pressure and 5000 psi working pressure.

3. It has a 10,000 psi working pressure and 7-1/16 ID.

4. 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?

1. The rating would remain at 10,000 psi..

2. The rating would become 5,000 psi.

3. 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?


23/95

1. The external diameter of the flange or hub.

2. The external diameter of the BOPs.

3. The cylinder diameter of the hydraulic actuator for the ram BOPs.

4. The through-bore (inside diameter) of the BOP.

11. a. Of the 4 types of gasket listed, indicate which flange (API 6B, API6BX) they would

be used with.

Type R Octagonal 6B

Type R Oval 6B

Type R RX ..6B

Type BX ..6BX

b. Which two of the above gaskets are pressure energised?

RX & BX

12. Are the following statements true or false regarding API ring gaskets?

a. Pressure energised type gaskets should be re-used.

TrueFalse

b. 6BX flanges with BX gaskets require more checking than 6B with RX gaskets.

TrueFalse

c. The nominal size of a flange is the diameter of the required gasket.

TrueFalse


24/95

13. Which statements are correct with respect to ring gaskets used for flange to flange make

up?

(TWO ANSWERS)

1. Type RX and BX ring gaskets provide a pressure energised seal.

2. The same material specifications apply for ring gaskets as for ring grooves.

3. Ring gaskets may be used several times.

4. Type BX flanges, which are designed for face-to-face make up, make use of type

BX ring gaskets only.

1

4. 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.

1. Type R Octagonal

2. Type R Oval

3. Type RX

4. Type BX

15. F

igures 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 thedescription:

1. Clamp hub connection.: 2..

2. Flanged connection.: .3..3. Studded connection.: .1..


25/95

Diverters

1. What are the main components of a diverter system?

(TWO ANSWERS)

1. A vent line of sufficient diameter to permit safe venting using the mud-gas separator

2. A vent line of small diameter, sufficient to create a back pressure on bottom while

circulating.

3. A high pressure ram type preventer with a large internal diameter.

4. A low pressure annular preventer with a large internal diameter.

5. A vent line of sufficient diameter to permit safe venting and proper disposal of flow

from the well.

2


26/95

. Figure below illustrates an integral diverter system.

Match the correct components to the descriptions below.

1. 5. Insert packer

2. 2. Outer packer (outer active seal).

3. 1. Diverter packer closing port.

4. 4. Flowline seals.

5. 8. Insert packer lockdown dogs.

3. Diverter systems are designed to totally seal in a well.


27/95

True False

4. The main purpose of a diverter is to divert shallow gas.

True False

5. Diverters vent lines must be small diameter lines.

True False

6. 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

7. Pick the correct procedure for the operation of a surface diverter system. Wind

direction is starboard to port.

1. Open starboard vent, close shaker valve, close diverter.

2. Close diverter, close shaker valve, open starboard vent.

3. Close diverter, open port vent, close shaker valve.

4. Open port vent, close shaker valve, close diverter.

8. What are the components of a 29-1/2 inch diverter system? (select two answers)

1. A low pressure annular preventer with a large internal diameter.

2. A vent line of sufficient diameter to permit safe venting using the mud-gas

separator.

3. A high pressure ram type preventer with a large internal diameter.

4. A vent line with a manually operated full opening valve.

5. A vent line of sufficient diameter to permit safe venting and proper disposal of flow

from the well.


28/95

Annulars

1. Figure below illustrates a Hydril GK Annular Preventer commonly used for

Surface BOP installations

Match the correct numbers to the component below

1. 3Opening Chamber.

2. 4Closing Chamber Hydraulic Inlet.

3. 6Preventer Body.

4. 5Operating Piston.

5. 1Screwed Head.

6. 2Packing Unit.


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2. Figure below illustrates a Cameron D type Annular Preventer

D Type Annular BOP

Match the correct numbers to the component below.

1. 9 Closing hydraulic port.

2. 3 Opening hydraulic port.

3. 2 Packer inserts.

4. 8Operating Piston.

5. 5 Ring groove.

6. 1 Packer.


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3. Figure below illustrates a Cameron DL type annular preventer

DL Type Annular BOP

Match the correct numbers to the component below.

1. 12. . Operating Piston.


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2. 4. Pusher Plate.

3. 2. Packer Insert.

4. 6 & 11Vent.

5. 8. Donut.

6. 9. Packer.

7. 5. Opening Hydraulic Port.

8. 13... Closing Hydraulic Port.

9. 7. Quick Release Top.

10. 3. Locking Grooves.

4. Figure below illustrates a Hydril GL Annular Preventer.

Match the correct numbers to the components below

1. 4 Opening Chamber.

2. 6 Closing Chamber Hydraulic Inlet.

3. 7 Piston.

4. 2 Head Quick Release Screws.

5. 1 Packing Unit.


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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)

1. Lowest required hydraulic closing pressure when closing chamber and secondary chamber are connected.

2. Lowest required hydraulic closing pressure when opening chamber and secondary chamber are connected.

3. The secondary chamber allows balancing the open force on the piston created by drilling fluid hydrostatic pressure in the marine riser.


33/95

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.

1. 1. Latched head.

2. 8. Operating piston.

3. 3. Packing unit.

4. 5. Opening chamber

5. 2. Wear plate

6. 4. Opening chamber head.


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7

. Identify the parts of the Hydril GK.


2. 5. Closing chamber

3. 3. Piston

4. 2. Packing unit

5. 1. Head (screw)


35/95

8. Identify the parts of the Shaffer.



3. 2. Packing unit

4. 4. Piston

5. 1. Head (latched)


36/95

9. Identify the parts of the Cameron D Type.

6.5. Opening chamber


8. 4. Packing unit (Donut)

9. 3. Packing/Sealing insert

10. 6. Piston

11. 2. Head (latched)

12. 1. Ring groove


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10. Match the items listed below to the number indicated on the drawing.

1. 4. Opening Chamber

2. 6. Primary Closing Chamber

3. 8. Balance or Secondary Closing Chamber

4. 3. Opening Chamber Head

5. 2. Packer Element

6. 5. Piston

7. 7. Piston Seals.


38/95

11. Why is it important to reduce the regulated hydraulic pressure for annular BOP

before running a large sized casing?

1. To prepare for the Soft Shut in procedure.

2. To reduce the closing time.

3. To avoid collapsing the casing, during closing.

4. 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.

1. True.

2. False.

13. Which three statements about Annular Preventers are true?

(select three answers)

1. Can be used as a means of secondary well control.

2. Is designed to seal around any object in the well bore.3. Cannot seal on a square or hexagonal kelly.

4. Will not allow tool joints to pass through.

5. Will allow reciprocating or rotating the drill string while maintaining a seal against

well bore pressure.

6. 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 becharged up two or more times before an acceptable test is obtained

Why is this?

1. Annular BOPs always leak until the packing element finds its new shape. This motion can take several minutes.

2. The compressibility of the hydraulic fluid from the hydraulic control unit below the closing piston causes the test pressure to drop.

3. 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)

1. Temperature rating of the element.

2. Type of mud to be used.

3. Desired hydraulic closing pressure.

4. Maximum pipe outside diameter.

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 gaugereads 1,000 psi.

U


39/95

sing the diagram below what hydraulic pressure should the annular closing pressure be adjusted to for stripping?

1. 200 - 400 psi.

2. 400-600 psi.

3. 600 - 800 psi.

4. 1000-1500 psi


40/95

Ram Components

1. Match the items listed below to the number indicated on the Cameron blind/shear ram.

1. 2. Side Packers.

2. 3. Ram Face Seal.

3. 1. Top Seal.

4. 5. Lower Ram Assembly.

5. 6. Top Ram Block.

6. 4. Top Ram Assembly.

2. Figure below illustrates a shear/blind ram.

Match the numbered parts to the correct components listed below.

1. 6. Shear blade.

2. 1. Upper rubber seal.

3. 7. Upper ram block holder.


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4. 2. Upper ram block.

5. 4. Lower ram block.

6. 5. Lower rubber seal.

3

. Figure below illustrates a pipe ram.

Match the numbered parts to the correct components listed below.

1. 4. Top Seal.

2. 1. Ram Packer.

3. 2. Ram Block.

4. 3. 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)

1. To support the weight of the drillstring during hang-off.

2. To prevent the rubber extruding top and bottom when the rams are closed.

3. To feed new rubber into sealing contact with the pipe when the sealing face

becomes worn.

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


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5. Match the items listed below to the numbers indicated on the drawing.

1. 1. Body

2. 6. Cylinder, Operator

3. 3. Bonnet

4. 4. Ram Assembly

5. 22. Bonnet seal

6. 9& 10... Ram change piston

7. 12... Bonnet Bolt

8. 7. Locking Screw Housing

9. 8. Locking screw

10. 2. Intermediate Flange

11. 20... Seal Rings, Connecting Rod

12. 5. Piston, Operating

13. 11... Ram change cylinder


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6. Identify the parts of the Cameron pipe ram.

1.

4. Ram Packer

2. 2. Top Seal

3. 3. Ram Block

4. 1. Anti-extrusion plate

7. Identify the parts of the Shaffer blind/shear ram.

1. 1. Upper Ram block.

2. 3. Lower Ram block

3. 7. Upper seal/rubber

4. 2. Lower seal/rubber

5. 6. Upper holder

6. 4. Lower holder

7. 5. Lower shear blade

8

. Identify the parts of the Shaffer pipe ram.


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1. 3. Holder.

2. 1. Block

3. 2. Seal / Rubber

9. The main functions of the weep hole on ram type B.O.P is to:

(Two answers)

1. Show the bonnet seal is leaking.

2. Show the primary mud seal on the piston rod is leaking.

3. Release any overpressure that may occur during testing.

4. Prevent damage to the opening chamber.

10. With regard to ram locking devices, are the following statements True or False?

1. All rams have locking devices.

True False

2. Locking devices increase the closing pressure on rams.

True False

3. Locking devices keep rams closed if hydraulics fail.

True False

4. 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. Select the correct definition of the Closing Ratio of a ram preventer.

1. Operating pressure required to close the ram against maximum wellbore

pressure.

2. Operating pressure required to close the ram against a specific wellbore

pressure.

3. Operating pressure required to close the ram at BOP R.W.P.

4. Ratio of the packer area against the piston rod area.

13. 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.

1. The fluid leaves the operating cylinder and drains off in the borehole through a

check valve.

2. The fluid leaves the operating cylinder and returns back to the opposite side of

the piston to enforce the closing pressure.

3. The fluid leaves the operating cylinder and returns back to the fluid reservoir

(as a function of the four-way valve for each preventer).

14. Which statements are correct with respect of fixed bore ram type BOPs?

(select two answers)

1. Ram type BOPs are designed to contain and seal Rated Working Pressure


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from above the closed rams as well as from below.

2. Ram type BOPs should be equipped with a mechanical locking system.

3. Fixed bore ram type BOPs can close and seal on various pipe sizes.

4. Fixed bore ram type BOPs can be used to hang off the drill string.

15. What are ram type preventers designed to do?

1. Hold pressure only from above.

2. Hold pressure only from below.

3. Hold pressure from both above and below.

16. 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?

1. Open.

2. Closed.

3. Neutral (Block).

4. In any position, it does not matter.

17. Which of the following statements about fixed bore ram type BOPS are correct(THREE ANSWERS)

1. Ram type BOPs are designed to contain and seal Rated Working Pressure

from above the closed rams as well as from below.

2. Ram type BOPs should be equipped with a mechanical locking system.

3. Fixed bore ram type BOPs can close and seal on various pipe sizes.

4. Fixed bore ram type BOPs can be used to hang off the drill string.

5. Ram type BOPs are designed to contain and seal Rated Working Pressure only

from below the closed rams.

18. When a ram type BOP on a surface stack is closed, what happens to the operating fluid displaced from the opening chamber?

1. The fluid drains into the well bore.

2. The fluid is used to boost closing pressure.

3. The fluid is returned to the reservoir.

19. Why does the Driller on a floating rigneed information about tides?

(TWO ANSWERS)

1. To adjust the marine riser tensioners.

2. To know the position of tool joints in the stack relative to the rams.

3. To calculate riser tensioner ton miles.

4. To correctly hang off during a well control operation.

5. To set ram closing pressures correctly.

20. Which ram type preventer on a Cameron 13-5/8, 10,000 psi BOP stack is equipped with thicker intermediate flanges?

1. Pipe rams.

2. Blind rams.

3. Shear rams.

4. Variable rams.

21. What is the main purpose of Blind/Shear rams?

1. To shear tubulars like drill pipe while simultaneously sealing the hole.


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2. To shear tubulars like drill pipe without sealing the hole.

3. To effect a seal with drill collars in the hole.

22. What is the meaning of Closing Ratio for a ram type BOP - as defined by API

RP53?

1. The ratio between opening and closing volume.

2. The ratio of the wellhead pressure to the BOP closing pressure.

3. The ratio between opening and closing time.

4. The ratio between BOP rated working pressure and hydraulic control unit working pressure.

23. 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?

1. Yes

2. No

24. Can ALL ram type BOPs close on Rated Working Pressure in the well bore when the hydraulic operating pressure is 1,500 psi?

1. Yes

2. No

25. Bottom rams should always be used to circulate up a kick.

TRUE FALSE


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26. 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 1000.. psi

27. 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 1429.. psi

28. For the following ram type BOP:

BOP R.W.P. 15000 psiClosing ratio 6.8 : 1Opening ratio 3 : 1

Accumulator operating pressure 3000 psi

What is the minimum pressure required to close the BOP at maximum wellbore

pressure?

Answer: 2206. psi

29. What is the correct meaning of the term primary seal and secondary seal when used in connection with ram type BOPs?

1. 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.

2. Primary seal is well control utilising only mud hydrostatic pressure. Secondary

seal is well control utilising both mud hydrostatic pressure and the BOPs.

3. 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.

4. 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.

30. What are the correct reasons for including a weep hole on ram type BOPs?

(TWO ANSWERS)

1. The weep hole indicates if the primary ram shaft packing is leaking well bore

fluid.

2. The weep hole prevents leakage through the primary ram shaft packing from

the well bore into the opening chamber.

3. The weep hole allows for visual inspection of the ram shaft and should be

plugged with a bull plug between inspections.


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4. To allow the installation of a grease nipple so that the ram shaft can be

greased.

5. The weep hole is a grease release port that prevents over-greasing of the ram

shaft packing.

31. What is the primary function of a weep hole (drain or vent hole) on a ram type BOP?

1. To show that the ram body rubbers are leaking.

2. To show that the closing chamber operating pressure is too high.

3. To show that the mud seal on the piston rod is leaking.

4. To show that the bonnet seals are leaking.

32. 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?

1. The weep hole only checks the closing chamber seals, leave it till the next

maintenance schedule.

2. Energise emergency packing. If leak stops, leave it till the next maintenance

schedule.

3. A leak is normal because the metal to metal sealing face in the bonnet needs

some lubrication to minimise damage.

4. Ram packing elements on the ram body are worn out, replace immediately.

5. Primary ram shaft seal is leaking, secure the well and replace immediately.

33 The primary function of the "weep hole" on ram type B.O.P is to:

1. Show the seals on the bonnet is leaking.

2. Show the primary mud seal on the piston rod is leaking.

3. Release any overpressure that may occur during testing.

4. Prevent damage to the opening chamber.

34. If a primary mud seal fails during a kill operation you have no back-up seal.

TRUE FALSE


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IBOPs & Valves

1. What mechanisms are used to close the choke and kill line valves on a subsea

BOP?

(TWO ANSWERS)

1. Hydraulic motor.

2. Pneumatic motor.

3. Spring force.

4. Hydraulic pressure.

5. Well bore pressure.

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?

1. NC50 (4-1/2 inch IF) Box x 6-5/8 inch Reg. pin.

2. NC50 (4-1/2 inch IF) Box x 7-5/8 inch Reg. pin.

3. NC50 (4-1/2 inch IF) Box x 6-5/8 inch Reg. box.

4. 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)

1. NC50 (4-1/2 inch IF) box x 6-5/8 inch Reg. pin.

2. NC50 (4-1/2 inch IF) box x 7-5/8 inch Reg. pin.

3. NC50 (4-1/2 inch IF) pin x 6-5/8 inch Reg. box.

4. 6-5/8 inch Reg. Pin x 7-5/8 inch Reg. Pin.

5. NC50 (4-1/2 inch IF) pin x 7-5/8 inch Reg. box.

4


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. 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.

1. 2. Bit sub bored for float.

2. 6. Cup type tester

3. 4. Dart sub.

4. 5. Pump down dart.

5. 1. Dart type drill pipe float

6. 3. Flapper type drill pipe float.


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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)

1. Easier to stab if strong flow is encountered up the drill string.

2. Must not be run in the hole in the closed position.

3. Has to be pumped open to read Shut In Drill Pipe Pressure.

4. Will not allow wireline to be run inside the drill string.

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

6. 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)

1. Easier to stab if strong flow is encountered up the drill string.

2. Must not be run in the hole in the closed position.

3. Has to be pumped open to read Shut In Drill Pipe Pressure.

4. Will not allow wireline to be run inside the drill string.5. Has potential to leak through the open/close key.

6. 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?

1. To avoid flowback while tripping or during a connection.

2. To read the drill pipe pressure value following a well kick.

3. To allow reverse circulation.

4. To reduce surge pressure.


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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)

1. It increases the risk of hydraulic collapse of the drill pipe - if not filled.

2. It increases tripping time.

3. It increases flow-back through the drill string.

4. It reduces surge pressure on the formation.5. It reduces flow-back in the flow line.

6. 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

1. Yes.

2. No.


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

1. Yes.2. No.


Is surge pressure generated when tripping in?

1. Yes.

2. No.


Is it possible to reverse circulate?

1. Yes.

2. 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.)

1. Only the drill pipe safety valve in the closed position.

2. Only the inside BOP.

3. The drill pipe safety valve (open) with an inside BOP installed on top.

4. The inside BOP with a drill pipe safety valve (closed) installed on top.

5. Only the drill pipe safety valve in the open position.

14. What is an Inside Blowout Preventer?

1. An element inserted into the annular preventer to reduce the inside diameter.

2. A ball valve installed immediately above the bit.


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3. A device that can be installed in the drillstring to act as a back-pressure valve.


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15. Match the items listed below to the numbers indicated on the drawing.


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1. 8. Valve spring

2. 3. Release tool

3. 5. Valve seat

4. 2. Valve release rod

5. 1. Release rod locking screw

6. 6. Valve insert

7. 7. Valve head

8. 9. Lower body

9. 4. Upper body


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16. Match the items listed to the numbers on the diagram.

1. 5. Ball

2. 3. Lower Seat

3. 4. Upper Seat

4. 1. Body

5. 2. Crank

17. 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.


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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?

1. Floats allow reverse circulating.

TRUE FALSE

2. Floats increase surge and swab pressures.

TRUE FALSE

3. Floats prevent back flow up the drillstring.

TRUE FALSE

4. Floats protect the bit from plugging.

TRUE FALSE

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

TRUE FALSE

6. Floats allow SIDPP to be read without further action.

TRUE FALSE

21. 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)

1. Drillpipe collapse.

2. Drop in BHP due to air bubble.

3. Riser collapse.

4. Mud losses.

5. Stuck pipe.

22. Full Opening safety valves are easier to stab than Non return valves if back flow occurs.

TRUE FALSE

23. Non Return valves require the use of a key to close.

TRUE FALSE

24. Full Opening valves have to be pumped open to read S.I.D.P.P.

TRUE FALSE

25. Full Opening valves must not be run into the hole in the closed position.

TRUE FALSE

26. A well kicks with the bit off bottom and is shut in. The decision is made to strip back into the hole. What equipment should be made up onto the string prior to

performing the stripping operation safely, assuming there is no float sub or dart sub in the string?

1. Only the Drill Pipe Safety Valve (closed).

2. Only the Inside Blowout Preventer.

3. Drill Pipe Safety Valve (open) with Inside Blowout Preventer installed on top.

4. Inside Blowout Preventer with Drill Pipe Safety Valve (closed) on top.

5. Only the Drill Pipe Safety Valve (open).


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Chokes

1. What is the purpose of the choke manifold vent /bleed line that by-passes the chokes?

1. To connect to the mud/gas separator.

2. To by-pass the chokes and connect the choke manifold to the kill line.

3. 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?

1. The same diameter as the other lines on the choke manifold.

2. At least equal to the diameter of the choke line.

3. At least 5 inches.

3. What is the main function of the choke in the overall BOP system?

1. To direct hydrocarbons to the flare.

2. To direct wellbore fluids to the mud/gas separator.

3. To shut the well in softly.

4. To hold back pressure while circulating out a kick.

4. Why are two chokes fitted into most choke manifolds?

1. To direct returns to the separator.

2. To direct returns to the pits.

3. To direct returns to the flare.

4. To minimise back-pressure when circulating through the manifold.

5. 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?

1. To minimize the effect of hot climates.

2. To help prevent hydrate formation while circulating a kick.3. To help fluids flow better during well testing.

4. To protect rubber goods in high temperature wells.

6. Which method is used to operate the remotely operated valves on the choke line?

1. Hydraulic fluid.

2. Air.

3. Nitrogen.

4. Wires.

7. The reason for having at least two chokes in the manifold is:

1. To reduce back pressure.

2. To allow separation of fluid and gas.

3. To reduce load on the mud gas separator.

4. To provide a back up in case of washout/plugging.

8. The main function of the Choke in the overall B.O.P system is:

1. To divert fluid to the mud tank.

2. To divert contaminant to burning pit.

3. To close the well in softly.

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


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Mud Gas Separators

1.Which of the following dimensions in the diagram below, limit the maximum working pressure of the mud/gas separator?

1. The height of the main body (H1).

2. The height of the dip tube (H2).

3. The total height of the vent line (H4).

4. Diameter of the inlet pipe (D3).


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2

. In the figure below, which dimension determines the back-pressure generated within the seperator?

1. The length and the inside diameter (D3) of the inlet pipe from the buffer tank to the choke manifold.

2. The dip tube height (H2).

3. The body height (H1) and the body inside diameter (D1).

4. The derrick vent pipe height (H4) and inside diameter (D2).


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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

1. 3 - 4 psi

2. 5 psi

3. 7 - 8 psi

4. 76 - 77 psi


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4. What is the purpose of a Vacuum Degasser?

1. It is only used while circulating out a kick.

2. It is mainly used to remove gas from mud while drilling

3. It is mainly used to separate gas from liquids while testing.

4. 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 OperatingPressure).

Answer 10.5.. psi

B. Which dimension would determine the normal working pressure of the above MGS for a given flow rate?

1. Vessel diameter and length.

2. Liquid seal diameter and length.

3. Height of vessel above flowline.

4. Vent line diameter and length.


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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) wouldhave to be overcome to allow gas to vent to the shale shakers?

Answer 5.8. psi


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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?

1. The height of the dip tube (H2)

2. The height of the main body (H1)

3. The total height of the vent line (H4)


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ACCUMULATOR UNIT PART I

Control Unit Components

1. Match the items listed to the diagram.


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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) areexpected?

1. Diesel oil.

2. Kerosene.

3. Fresh water with added kerosene

4. 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?

1. Two times the usable fluid of the accumulator.

2. Two times the closing volume of the BOP.

3. 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)

1. Fresh water containing lubricant.

2. Salt Water.

3. Gearbox oil

4. 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:

1. The usable fluid capacity of the accumulator system.

2. Twice the usable fluid.

3. Three times the usable fluid.


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Control Unit Pumps

1. How many independent sources of power should be available on each BOP hydraulic control unit, according to API RP53?

1. Only one.

2. Not less than two.

3. It is the rig owners choice

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

1. An electrical system.

2. An air system.

3. A dual air/electric system

4. An 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 hydraulicallyoperated 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: -

1. 1minute or less.

2. 2minutes or less.

3. 3minutes or less

4. 4minutes or less.

4. What is the minimum pressure at which the charge pumps start up, according to API RP53?

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

pressure.


pressure.


pressure.


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Accumulator Bottles

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

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

expected.

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

3. It should be conducted once per shift.

4. 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?

1. Air.

2. Nitrogen.

3. Oxygen.

4. Carbon Dioxide (CO2).

5. Methane.

3. What is the minimum recommended (API RP53) pre-charge pressure for the accumulator bottles on a 3000-psi Hydraulic Control Unit?

1. 3000 psi.

2. 1000 psi.

3. 1200 psi.

4. 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)

1. To operate the IBOP in the Top Drive

2. To enable the BOP to be closed in the event of a power failure.3. To activate the emergency packing on the Rams.

4. To operate the remote choke.

5. To reduce the closing time of BOP functions.


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

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

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

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

operating pressure and the minimum operating pressure.


operating pressure and the pre-charge pressure.


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?

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

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

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

pressure.

3. 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?

1. 40 gallons.

2. 100 gallons.

3. 66 gallons.

4. 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?

1. 40 gallons.

2. 27 gallons.

3. 66 gallons.

4. 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 froma 10 gallon capacity bottle?

Answer 5. 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 12.5. 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. -


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

1. 240 gallons

2. 480 gallons

3. 120 gallons

4. 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 psiClosing 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.

1. 30 cylinders.

2. 36 cylinders.

3. 41 cylinders.

4. 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 psiClosing 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 Pressureof the BOP.

1. 12 cylinders.

2. 24 cylinders.

3. 36 cylinders.

4. 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

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

Answer 323. Gallons

b. The operators requirements as per API RP53 are for a minimum operating pressure of 1200 psi. How many 10 gallon capacity accumulator bottles arerequired to provide enough useable fluid.

Answer 65. Bottles


72/95

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.

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

Answer 1429. PSI

2. Hydraulic fluid requirement to close, open and close all functions is 258 gallons. How many 10 gallon accumulator bottles will be required?

Answer 71. Bottles


73/95

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)

1. They are capable of manual operation.

2. They cannot be remotely operated.

3. They can be placed in 4 positions.

4. 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?

1. All valves in the open position.

2. All valves in the closed position.

3. All valves in the neutral position.

4. 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?

1. 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.

2. 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.

3. 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?

1. Open

2. Closed

3. Open or closed depending on item of equipment


74/95

Hi-Lo Bypass Valve

5. On the remote panel the High-Low bypass valve allows you to put full accumulator pressure to which of the following.

1. Rams only.

2. Annular only.

3. All functions.

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

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

(manifold valve) facility?

1. Variable bore rams.

2. Blind/Shear rams.

3. 5 inch pipe rams.

4. 3-1/2 inch pipe rams.

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

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

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

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

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

manifold.

8. What is the purpose of the bypass button on the drillers remote control panel for a surface BOP installation?

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

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

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

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


75/95


76/95

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)

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

and hydraulic fluid flows to the preventer.

2. 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.

3. 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)

1. Air Pressure Gauge.

2. Accumulator Pressure Gauge.3. Manifold Pressure Gauge.

4. 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)

1. Air pressure gauge.

2. Accumulator pressure gauge.

3. Manifold pressure gauge.

4. 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)

1. Air pressure gauge.

2. Accumulator pressure gauge.

3. Manifold pressure gauge.

4. Annular pressure gauge.


77/95

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


78/95

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

drillers remote panel?

Gauge No 1 3000 psi

Gauge No 2 120. psi

Gauge No 3 1500 psi

Gauge No 4 600-1500psi

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

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

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

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

4. 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?

1. Gauge 1 & 2

2. Gauge 2 & 4

3. Gauge 3 & 4

4. Gauge 1 & 4

5. Gauge 3 & 2


79/95

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

(TWO ANSWERS)

1. Ram BOP Preventers.

2. Hydraulically operated choke and kill line valves.

3. Annular BOP Preventer

4. All BOP stack functions.

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

1. 3000 psi.

2. 2500 psi.

3. 1500 psi.

4. 700 - 1500 psi.

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

1. 3000 psi.

2. 2500 psi.

3. 1500 psi.

4. 1000 psi.

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

1. 250 psi.

2. 600 1,500 psi.

3. 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?

1. Zero.

2. 500 psi.

3. 1,500 psi.

4. 3,000 psi.


80/95

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

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

2. Annular preventer only.

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

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

valves.

5. 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)

1. 1,500 psi

2. 3,000 psi

3. 10,000 psi


81/95

Closing Times

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

1. Less than 30 seconds.


3. 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

a. 13 5/8 15K RWP Ram 30 Seconds

b. 21 5K RWP Annular 45 Seconds

c. 16 3/8 5K RWP Annular 30 Seconds

d. 11 5K RWP Ram 30 Seconds

Subsea Stack

e. 13 5/8 15K RWP Ram Seconds

f. 16 10K RWP Annular Seconds

g. 21 5K RWP Annular Seconds


82/95

Master Valve

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

1. Activates the hydraulic fluid circuit at the panel.

2. Activates the air circuit at the panel.

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

4. 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?

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

2. To activate the open or close lights.

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

4. 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 releasedbefore operating a BOP function.

1. True.

2. 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.

1. True.

2. 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 thehandle/button.

1. True.

2. 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.

1. True.

2. False.

7. If a function is operated on the remote BOP control panel without operating the master control valve, how will the function work?

1. Slower.

2. Faster.

3. The same.

4. Will not work at all.

8. Which of the following procedures is the correct one to activate a BOP function from the Drillers electric remote control panel on a surface BOP stackinstallation?

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

function button is depressed.

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

3. 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?


83/95

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

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

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

made.

4. 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:

1. To check the rig air pressure is correct.

2. To allow a build up of air pressure to operate the 3 position valve.

3. To bleed air from the system.

4. 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:

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

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

3. The master valve must be continually operated whilst functions on the panel are made.4. 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


84/95


85/95

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?

1. Gauge No 1 120.. psi

2. Gauge No 2 3000.... psi

3. Gauge No 3 1500.... psi

4. Gauge No 4 600 - 1500.. psi

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

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

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

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

4. All functions on the remote panel will operate normally


86/95

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?

1. Gauge 1 & 2

2. Gauge 2 & 4

3. Gauge 3 & 4

4. Gauge 1 & 4

5. Gauge 3 & 2


87/95

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 doesnot drop. What has happened?

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

2. 4-way ram valve on accumulator unit has failed to shift

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

4. 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 helddown

3 PositionValve not

moved

Closedline

blocked.

Leak inline orBOP.

Air lost. Bulbblown.

Close light doesnot illuminatebut pressure

drops and laterrecovers.

X

Light does notilluminate and

pressure gaugedoes not drop.

X X X

Pressure gaugedrops but does

not rise back up.

X

Lightilluminates but

pressure gaugedoes not drop.

X


88/95

6. On the Drillers 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?

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

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

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

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

5. Electric position switches are malfunctioning.

7. On the drillers 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?

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

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

3. Electric pressure switches are malfunctioning.

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

5. 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?

1. Everything is correct.



4. All stack functions can be operated from the remotepanel.

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?

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

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

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

4. 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.

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


89/95



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?

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

2. There is a leakage on the hydraulic circuit.

3. The rams did not close.

4. 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 hasreturned to normal.

What is the cause of the problem?

1. Hydraulic closing line to BOP is leaking.

2. The 4-way valve has not actuated.

3. 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 lightdoes not illuminate.

What is the reason for this?

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

2. There is a leak on the hydraulic unit.

3. The rams did not close.

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


90/95


91/95

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

1. Everything OK.

2. There is a leak in the hydraulic system.

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

4. There is a malfunction

IWCF practice questions

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