4. Assistant Driller Module Trainee Booklet

ASSISTANT DRILLER MODULE

Assistant Driller Module

Integrated Project Management Modular Training Program Table of Contents

1)

Program Guide Sheet

2)

Task List

3)

Tool List

4)

Workbook Questions Workbook 1: Applied Mathematics Workbook 2: Practical Well Control Workbook 3: Kick Data and Gauges Workbook 4: Drilling Line Care and Maintenance Workbook 5: Drilling a Straight Hole Workbook 6: Rig Hydraulics Workbook 7: Drilling Muds Workbook 8: Casing Workbook 9: Cementing

5)

Personal Notes

6)

Completion Notification Form

Ref: ADMOD.DOC Section: TOC Page: 1 Issued: 31 December 2006 Revision: 02


Program Guide Sheet


Integrated Project Management Modular Training Program

Ref: ADMOD.DOC Section: 1 Page: 1 Issued: 31 December 2006 Revision: 02

Program Guide Sheet- For the Participant INTRODUCTION The Modular Training Program is designed to help you do your job more safely and effectively, and to progress in your career with IPM. It is rig-based, and focuses on the tasks specific to each job. The program allows you to progress at your own speed, with the help of your Supervisor. Don't hesitate to ask if there's anything you don't understand. PREREQUISITE Before you start this module, you must complete the Derrickman Module. OBJECTIVES Upon completion of this module, you should be able to: 1)

demonstrate a clear understanding of the role and responsibilities of the Assistant Driller in IPM.

2)

perform basic Assistant Driller tasks safely and competently.

TRAINING MATERIAL The Assistant Driller Module includes: 1)

Task List, a list of tasks which you must be able to perform.

2)

Tool List, a list of reference DVD and books in the Training Room on your rig.

3)

Workbook exercises, a set of review quizzes.

4)

Personal Notes, a section for note keeping.




Program Guide Sheet- For the Participant

TRAINING PROCEDURE You can expect to complete this module in about 6 working weeks, depending on the effort put in. Please try to complete the module in the scheduled time. Completion of the Task List is mandatory, and will be checked periodically by your Supervisor. The movies, reference books and workbook questions will help your understanding of the tasks. Your Supervisor may ask you to re-study any workbook material not fully understood. The Notes section is for any sketches or notes you may find helpful. You must first finish the Task List requirements to your Supervisors satisfaction. Once the Task List is completed you will need to take the computer generated test using QMP. On successful completion of the test your supervisor can then mark your LMS record for Completion of the module. The signed CNF is then forwarded to the HQ in Dubai for Module certificate processing. The completed Task List is kept on file at your location of assignment.

Note: The Assistant Driller Module Task List is the main component for measuring your progress. Completion of the training is indicated when all of the topics on the Task List are checked off by the Supervisor and the assessment is successfully completed.

Thanks for your interest and participation in the IPM Modular Training Program.


Task List

Reference: Issued: Revision Page:

Task Lists

ASSISTANT DRILLER MODULE Supervisor Name:

Rig #:

Employee Name:

Position:

Training Source

Task # General Safety Topics 1

Explain the Permit To Work System as it applies to the A.D.

QHSE

2

Describe the Company accident analyses and alerts systems.

QHSE

3

Explain the role of the Assistant Driller during emergency (including H2 S, fire, man overboard, abandon rig).

QHSE

4

Conduct a pre-job (tool box) meeting.

QHSE

Participate in the pre spud meeting.

QHSE

5

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General Rig Floor 6

Explain the Assistant Driller's role in managing drill floor housekeeping.

7

Show how to align standpipe manifold for testing, cementing and drilling.

ü ü

ü

ADMOD.DOC 31 December 2006 02 01 Date Comp

Supv Sign


Task Lists


Rig #:

Employee Name:

Position:

Training Source

Task # General Rig Floor (cont.) 8

Show how to maintain the drilling line fastline guide system.

7.11000

9

Show how to inspect and change drawworks turnback rollers.

7.11000

10

Explain and show how to rig up and down rotary hose.

11

Show how to make up the single-shot (Totco) survey tool and explain the methods to run and recover it.

12

Show how to service and repair the tong torque load cell on the tong arm.

DVD02.016

ü ü ü ü DVD02.016

ü ü ü ü ü ü 2.01210

ü ü ü

ü ü

Working With The Drill String 13

Show how to adjust the brake band equalizing bar.

14

Show how to adjust and reset the crown block saver (Crown-O-Matic).

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Task Lists

Supervisor Name:

Rig #:

Employee Name:

Position:

Training Source

Task # Working With The Drill String (cont.) 15

Show how to visually inspect drilling line.

7.11000

16

Explain and show how to calculate ton-miles for the drilling line.

7.11000

17

Explain drilling line slip and cut procedures.

10.10010

18

Explain how to identify washouts in drill string components.

19

Show how to prepare BHA sheets and pipe tally.

20

Explain and show how to prepare and fill out a trip sheet.

21

Show how to compound tong lines for making up or breaking out tubulars requiring high torque.

22

Show how to use a gauge ring for typical bits and stabilizers used on your rig.

DVD02.015

ü ü ü ü ü ü

ü

ü ü ü ü

ü ü ü DVD05.010

ü ü ü 10.10010

ü ü ü

ü ü


Supv Sign


Task Lists


Rig #:

Employee Name:

Position:

Training Source


Show how to check for bit wear and assist with dull bit grading.

24

Show how to install, re-dress and remove a bit sub float valve.

25

Show how to install and remove jets in typical bits.

26

Show how to supervise a BHA handling operation on the drill floor.

27

Identify and explain the use of typical fishing tools used on your rig.

28

Explain and demonstrate how to dress an overshot.

29

Show how to identify and measure typical downhole tools and tubulars (including collars, stabilizers, jars, subs crossovers and, bit).

10.10010

ü ü ü ü ü ü ü

ü ü ü ü ü ü

2.01210

ü ü

ü


Supv Sign


Task Lists


Rig #:

Employee Name:

Position:

Training Source

Task # Running and Cementing Casing 2.01210

30

Explain and show how to organize the drill floor for a casing job.

31

Explain and demonstrate the wear bushing retrieval operation.

32

Show how to make up the casing shoe and float collar.

2.01210

33

Explain and show how to test the shoe and float collar while running casing.

2.01210

34

Show how to change power tong heads and tong dies.

35

Explain how to dress and install the cementing head and secure high-pressure chiksan lines or hose and test.

ü ü ü ü ü ü ü ü

ü ü ü ü ü

2.01210

ü ü

ü

Well Control and Related Equipment 36

Show how to perform daily checks on well control equipment such as IBOP and crossover(s), choke manifold, accumulator unit.

2.80040

ü ü

ü


Supv Sign


Task Lists


Rig #:

Employee Name:

Position:

Training Source

Task # Well Control and Related Equipment (cont.) 37

Explain IPM shut in procedures while drilling.

2.80040

38

Explain IPM shut in procedures while tripping.

2.80040

39

Explain the diverter control system and diverter procedures .

2.80040

40

Explain and show how to change and service BOP rams.

2.80040

41

Explain and show how to change an annular BOP packing element.

2.80040

42

Explain and show how to nipple-up or nipple-down a surface BOP stack.

2.80040

43

Show how to do a complete BOP and choke manifold pressure test.

2.80040

44

Show how to do a complete IBOP and standpipe manifold pressure test

2.80040

DVD05.005



ü ü ü ü ü ü ü ü ü ü ü ü ü ü

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Supv Sign


Task Lists


Rig #:

Employee Name:

Position:

Training Source

Task # Well Control and Related Equipment (cont.) 45

Show how to calculate the space out.

46

Show how to prepare a typical kick sheet and explain its significance.

47

Explain the accumulator system operation (nitrogen precharge, useable fluid) and assist with routine maintenance.

DVD02.004

ü ü ü DVD02.004

ü ü ü 2.80040

DVD02.004

ü ü ü ü

Equipment Maintenance 48

Describe the Assistant Driller's role in the PMS system.

49

Visually inspect and identify typical problems associated with drawworks.

50

Explain how to change out the swivel washpipe and show how to re -dress the spare.

51

Show how to maintain and repair a standpipe gate valve.

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ü ü ü ü


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Task Lists

Supervisor Name:

Rig #:

Employee Name:

Position:

Training Source

Task # Equipment Maintenance (cont.) 52

Explain and assist in maintaining or repairing a choke manifold gate valves.

53

Explain and assist in maintaining or repairing a manual and a remote operated choke.

54

Show how to service and repair the hydraulic pressure load cell on the standpipe.

55

Explain and show how to visually inspect the deadline anchor and the load cell.

56

Explain and show how to replace cathead lines and explain safety precautions.

57

Visually inspect and identify typical problems associated with automated pipe handling equipment (pipe racker, iron roughneck, pipe spinner).

58

Visually inspect and identify typical problems with crown block and traveling block assemblies.

59

Visually inspect and identify typical problems with the top drive or kelly assembly.

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ü ü ü

ü ü ü ü ü ü

ü ü ü ü ü

7.11000


Supv Sign


Task Lists


Rig #:

Employee Name:

Position:

Training Source


Visually inspect and identify typical problems with mud treatment equipment.

61

Visually inspect and identify typical problems with mud pumps.

62

Show how to inspect and repair drill string full opening and non-return valves.

63

Show how to inspect and repair a plug (lo-torq) valve.

64

Show how to inspect and repair low-pressure mud system valves (butterfly, gate, and dump valves).

65

Show how to prepare the drill floor for a typical completion job.

Operations on Floating Rigs 66

Explain the running and retrieving procedures for the hang-off assembly.

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Supv Sign



Task Lists

Supervisor Name:

Rig #:

Employee Name:

Position:

Training Source

Task # Operations on Floating Rigs (cont.) 67

Explain and show how to supervise the drill floor for riser running / retrieving operations.

68

Explain and show how to supervise moon pool area operations during BOP / riser running or retrieval.

69

Assist in routine maintenance on the riser / guideline tensioner systems and explain how it works.

70

Visually inspect and identify typical problems with drill string motion compensator.

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Moving Operations on Land Rigs 71

Explain and show how to prepare for heavy lifts.

72

Show how to disassemble and reassemble the mast and substructure.

73

Show how to reeve the drilling line over blocks, drawworks drum and deadline anchor.


Supv Sign


Task Lists


Rig #:

Employee Name:

Position:

Training Source

Task # Moving Operations on Land Rigs (cont.) 74

Show how to rig down / up the standpipe manifold assembly and choke manifold.

75

Show how to rig down / up the drawworks, rotary table, and drill floor sections.

76

Show how to rig down / up Driller's console instrument panel.

77

Explain and show how to supervise the rig down/up of mud pumps, discharge and suction lines.

78

Explain and show how to supervise the rig down/up of mud tanks, low-pressure lines and solids control equipment.

79

Explain and show how to supervise the rig down/up of the swivel and kelly or top drive.

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ü ü ü

ü ü ü

ü ü ü

ü

ü

Supervisory Skills 80

Show how to communicate and work with other departments and third party personnel.


Supv Sign



Task Lists

Supervisor Name:

Rig #:

Employee Name:

Position:

Training Source

Task # Supervisory Skills 81

Assist the Driller in filling out the IADC drilling report.

82

Explain the Assistant Driller's role in training crew members.

83

Operate the Driller's drawworks controls during a routine trip, and under close supervision, for a limited period. (cased hole section)

84

Operate the Driller’s drawworks controls during routine drilling, and under close supervision, for a limited period.

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ü

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Supv Sign


Task Lists

Supervisor Name:

Rig #:

Employee Name:

Position:

Task # Additional Rig Specific Topics


Training Source


Supv Sign



Task Lists

ADMOD.DOC 31 December 2006 02 14

Training Source Legend

Modular Training Reference Books & IPM Documents Practical Hands-On DVD Viewing Instructions by Supervisors or Traveling Instructors Computer Based Training Referencing Required:

ü

Referencing Not Required: For the most effective learning it is better to use as many training sources as possible


Tool List

Assistant Driller Module Reference

Ref: ADMOD.DOC


Section: 3 Page: 1 Issued: 31 December 2006

Tool List Reference DVD In Training Room

DVD 03.022 DVD 03.023 DVD 03.024 DVD 03.025 DVD 06.012 DVD 02.015 DVD 02.016

Prerequisite: mandatory completion of Derrickman Module Solids Control Seminar Part -1 Solids Control Seminar Part- 2 Solids Control Seminar Part -3 Solids Control Seminar Part -4 Installation and Operation of Diverter Systems [Offshore Only] Drilling Line Care and Maintenance part 1: Inspection and Cutoff Drilling Line Care and Maintenance part 2: Equipment and String-up

DVD 02.017 DVD 02.018 DVD 05.001 DVD 05.002 DVD 05.003 DVD 05.004 DVD 05.005 DVD 05.006 DVD 05.007 DVD 05.008 DVD 05.009 DVD 05.010 DVD 05.011 DVD 05.012 DVD 05.025 DVD 05.026 DVD 05.027 DVD 05.028 DVD 05.029 DVD 05.030 DVD 05.031 DVD 05.032 DVD 05.033 DVD 05.034 DVD 05.035

Load Cells Care and Maintenance part 1: Field Servicing the Sensator Load Cells Care and Maintenance part 2: Maintenance of Weight Indicator Head Well Out Of Control Disaster Anatomy of a Kill OilWell Blowouts Well Control - Early warnings of a Kick Well Control - Kicks while Drilling Well Control - Kicks while Tripping Kicks : A Formula for Control Well Control Calculations - Drillers Method . Well Control Calculations- Wait & Weight Method . Well Control Operations - Instructions on BOP Equipment Koomey Control System, Identifying the Components Koomey Control System, How it Works Hydraulic Gate Valve Manual Gate Valve Fail Safe Closed Hydrulic Gate Valve Maintaining The Hydril Annular BOP Cameron Type D Annular BOP NL Shaffer Spherical Type BOP NL Shaffer Ram Type BOP’s Hydril Ram Type BOP Cameron Type U BOP Cameron Type U BOP Inspection & Maintenance Cameron Type U BOP Replacement of Leaking Seals

PETEX Cat. Nos. 2.80040 10.10010 2.01210 1.60040 2.30330 7.11000

Reference Books In Training Room Practical Well Control IADC Drilling Manual Drilling Technology Series – Segment II: Drilling Operations Applied Mathematics for the Petroleum and Other Industries Rotary Drilling Blowout Prevention Drilling Line Care and Maintenance

Revision: 02

Date

Date


PETEX Cat. Nos. 7.30010 7.30020 7.30030 7.30040 7.30050 7.30060 7.30070 7.30080 7.30090 7.30100 71.10010

Interactive CD-ROM Software In Training Room Oilwell Drilling: An Introduction, Vol.1, Rig Types and Basic Drill String Components Oilwell Drilling, Vol.2, Basic BOP Equipment Oilwell Drilling, Vol.3, Introduction to Drilling Fluids Oilwell Drilling, Vol.4, Mud Circulation and Treating Equipment Oilwell Drilling, Vol.5, Hoisting Equipment Oilwell Drilling, Vol.6, Rotating Equipment, Mast and Substructure Oilwell Drilling, Vol.7, Pipe Handling Equipment Oilwell Drilling, Vol.8, Casing and Cementing Oilwell Drilling, Vol.9, Well Logging, Mud Logging, and DST Oilwell Drilling, Vol.10, Power Systems and Instrumentation Inside BOP’s, Safety Valves and Kelly Cocks

Date


Workbook Questions

Assistant Driller Module Workbook 1

Ref: ADMOD.DOC

Integrated Project Management


Modular Training Program

Revision: 02

Applied Mathematics Workbook Questions Refer to Applied Mathematics for the Petroleum and Other Industries. Each question has only one correct answer. 1.

What is the capacity of a 12 ¼” hole in barrels per foot? A. 0.1222 bbl/ft B. 0.1326 bbl/ ft C. 0.1457 bbl/ft D. 0.1547 bbl/ft

2.

What is the annular capacity of a 17 ½” hole with 5” Drill Pipe inside? A. B. C. D.

3.

12.25”

0.2732 bbl/ft 0.1968 bbl/ft 0.1743 bbl/ft 0.0895 bbl/ft

5”

17.5”

What is the volume in barrels of a rectangular mud tank with the following dimensions? Width = 6 ½ feet, Length = 18 ¼ feet, Height = 10 feet A. B. C. D.

211 bbl 316 bbl 663 bbl 1048 bbl

6.5 ft 10 ft

18.25 ft 4.

What is the volume of a rectangular mud tank with the following dimensions? Width = 3.5 m, Length = 7.8 m, Height = 4.3 m A. B. C. D.

117 m3 738 bbl answer A or B none of the above

3.5 m 4.3 m

7.8 m


Ref: ADMOD.DOC




Revision: 02

Applied Mathematics Workbook Questions 5.

What volume in barrels can the tank hold before fluid passes through the overflow pipe? A. B. C. D.

320 bbl 230 bbl 110 bbl none of the above 10 feet

10 feet

7.½ feet

24 feet 6.

What is the area of an oval tank cover in square feet, with the following dimensions? Minor Axis = 4 feet, Major axis = 8 ½ feet A. B. C. D.

7.

8.5 feet 4 feet

Using the dimensions in question number 5, calculate the volume in barrels, of an oval tank 27 ½ feet high? A. B. C. D.

8.

106.8 ft2 75.4 ft2 49.3 ft2 26.7 ft2

254 barrels 162 barrels 131 barrels 85 barrels

What is the volume increase in barrels when raising the mud weight from 9.4 ppg to 10.6 ppg in a 1,400 barrel system? A. 256 bbl B. 171 bbl C. 110 bbl D. 76 bbl



Ref: ADMOD.DOC Section: 4 Page: 3 Issued: 31 December 2006


Revision: 02

Applied Mathematics Workbook Questions 9.

How much water needs to be added to reduce the mud weight from 10.8 ppg to 9.5 ppg in a 1,800 barrel mud system? A. B. C. D.

2000 bbl 1500 bbl 1000 bbl 500 bbl Use the diagram information to answer questions 10 through 14.

10.

What is the hydrostatic pressure at TD? A. B. C. D.

11.

What is the string capacity in barrels? A. B. C. D.

12.

5118 feet 5” pipe ID 4 “

11,789 litres 98,864 litres 102,030 litres 198,468 litres

What is the annular volume in barrels with no string? A. B. C. D.

14.

161 bbls 121 bbls 101 bbls 81 bbls

What is the annular volume in litres? A. B. C. D.

13.

2,261 psi 2,661 psi 2,785 psi 5,357 psi


What is the height of the influx with a 20 bbl pit gain? A. B. C. D.

392 ft 239 ft 223 ft 199 ft

239 feet 8” drill collar ID 2 ½ “

12 ¼ Hole w/ 10 ppg mud




Practical Well Control Workbook Questions Refer to PETEX Practical Well Control, Fourth Edition. Each question has only one correct answer. 1.

Overburden pressure is: A. the pressure exerted at any given depth by the weight of the rocks and sediments. B. the pressure exerted at any given depth by the weight of the sediments, or rocks and the weight of the fluids that fill the pore spaces in the rock. (Reference: Page 1-1) C. the pressure exerted at any given depth by the weight of the rocks. D. the pressure exerted at any given depth by the weight of the fluid in the pore space of the rocks.

2.

Of all the pressure losses in the circulating system, which one acts only on the borehole? A. B. C. D.

3.

The pressure loss across the nozzles. The pressure loss in the surface lines. The pressure loss in the drill stem. The pressure loss in the annulus. (Reference: Page 1-8)

At the start of a trip out of the hole for a bit change, the first 20 x 93 ft stands of pipe are pulled from the hole wet with no fill up. Using the following data calculate the reduction in bottom hole pressure? DP. Metal Displacement DP. Capacity Casing Capacity Mud Weight A. B. C. D.

4.

= .00764 bbls/ft = .01776 bbls/ft = .0758 bbls/ft = 10 ppg

48 psi 483 psi (Reference: Page 2-5) 600 psi 683 psi

At the start of a trip out of the hole for a bit change, the first 10 x 93 ft stands of pipe are pulled from the hole dry with no fill up. Using the following data calculate the reduction in bottom hole pressure? DP. Metal Displacement DP. Capacity Casing Capacity Mud Weight A. B. C. D.

= .00764 bbls/ft = .01776 bbls/ft = .0758 bbls/ft = 12 ppg

650 psi 6 psi 65 psi (Reference Chapter 2 Page 2-5) 130 psi




Practical Well Control Workbook Questions 5.

Select the two things that are needed to accurately determine an Initial Circulating Pressure? A. B. C. D.

6.

Select the three things that are needed to accurately determine a Final Circulating Pressure? A. B. C. D.

7.

a higher bottom hole pressure than the wait and weight method. a lower bottom hole pressure than the wait and weight method. a higher surface pressure than the wait and weight method. (Reference Page 6-4) a lower surface pressure than the wait and weight method.

During a well-killing operation, a common way to bring the pump up to kill rate without changing bottomhole pressure is to: A. B. C. D.

10.

one circulation two circulations (Reference Page 6-2) three circulations four circulations

The Drillers Method of Well Control will normally result in: A. B. C. D.

9.

drilling pump pressure, drilling mud weight and kill mud weight shut in drill pipe pressure, drilling mud and kill mud weight slow circulating rate pressure, drilling mud weight and kill mud weight (Reference Page 4-8) slow circulating rate pressure, drilling mud weight and final circulating pressure

The Drillers Method of Well Control normally requires how many circulations to kill a well? A. B. C. D.

8.

drilling pump pressure and mud weight shut in drill pipe pressure and mud weight slow circulating rate pressure and final circulating pressure slow circulating rate pressure and shut in drill pipe pressure (Reference Page 4-2)

keep SIDP constant at the original shut-in value by opening the choke. keep SIDP constant at the original shut-in value by opening the choke and bringing the pump up to kill-rate speed. keep SICP constant at the original shut-in value by opening the choke and bringing the pump up to kill-rate speed. (Reference Page 9-6) ensure that casing pressure and standpipe pressure rise consistently together.

The usable accumulator fluid for a 10 gallon accumulator bottle on a 3,000 psi system with 1,000 psi precharge is approximately: A. B. C. D.

9 gallons. 7 gallons. 5 gallons. (Reference Page 10-16) 3 gallons.


Ref: ADMOD.DOC



Kick Data and Gauges Workbook Questions Use the Well Data to answer the questions. Each question has only one correct answer. WELL DATA Well Depth

10,000 ft TVD 11,500 ft MD

Bit size

8.5”

Drill Pipe

5” OD. 19.5 lbs/ft Capacity = 0.01776 bbls/ft

Drill Collars

61 /2 ” x 213 /16 ” x 750 ft Capacity = 0.00768 bbls/ft

Casing

95 /8 ”, 47 lb/ft. P110 8.681” ID 100% Internal yield = 10,900 psi Set at 7,000 ft TVD

Mud weight in use

12 ppg.

Pumps

National triplex 12-P-160 With 61 /2 ” Liners Capacity = 0.117 bbls/stk PUMP PRESSURE

While Drilling

2500 psi at 80 spm (APL = 260 psi)

Slow Pump Rate

250 psi at 30 spm (APL = 75 psi) ANNULAR VOLUMES

Drill pipe - Casing Drill pipe - Casing Drill pipe - Open hole Drill collars - Open hole

= 0.0505 bbls/ft = 0.0459 bbls/ft = 0.0292 bbls/ft WELL CONTROL DATA

SIDPP SIDPP SICP GAIN FRACTURE GRADIENT AT SHOE

= 520 psi = 720 psi = 12 bbls = .91psi/ft

Workbook Questions

Revision: 02


Integrated Project Management Modular Training Program Kick Data and Gauges

1.

What is the total capacity of the drill string? A. B. C. D.

2.

Calculate the total annular capacity with the pipe on bottom? A. B. C. D.

3.

58.5 minutes 49.7 minutes 60.3 minutes 51.5 minutes

What kill mud is required to balance formation pressure? A. B. C. D.

6.

21 minutes 25 minutes 32 minutes 39 minutes

Calculate bit to surface time (bottoms up) at 80 spm? A. B. C. D.

5.

482.2 bbls 457.5 bbls 547.5 bbls 627.6 bbls

What is the surface to bit time with the pump running at 80 spm? A. B. C. D.

4.


13.4 ppg 13.0 ppg 12.4 ppg 16.4 ppg

The ICP (initial circulating pressure) at 30 spm will be approximately? A. B. C. D.

270 psi 770 psi 990 psi 1200 psi





Kick Data and Gauges Workbook Questions 7.

The FCP (final circulating pressure) at 30 spm will be approximately? A. B. C. D.

8.

After reaching FCP it is decided to increase the pump speed to 40 spm. What would happen to BHP if the drill pipe pressure is held constant at the original FCP value? A. B. C. D.

9.

approximately 800 psi approximately 390 psi approximately 500 psi approximately 270 psi

increase by about 210 psi decrease by about 210 psi remain constant because drill pipe pressure was not changed increase by about 500 psi

What is the hydrostatic pressure at the bottom of the hole before the kick? A. B. C. D.

5800 psi 6800 psi 7800 psi 6240 psi

10. What is the ECD on bottom while drilling? A. B. C. D.

15.0 ppg 12.5 ppg 12.0 ppg 13.5 ppg

11. At 80 spm what is the annular velocity around the drill collars? A. B. C. D.

412 ft/min 210 ft/min 506 ft/min 321 ft/min

12. What is the maximum allowable mud weight? A. B. C. D.

17.5 ppg 16.5 ppg 18.0 ppg 19.0 ppg


Integrated Project Management Modular Training Program Kick Data and Gauges Workbook Questions

13. What is the approximate length of the influx? A. B. C. D.

1027 ft 850 ft 653 ft 410 ft

14. The gradient of the influx is about? A. B. C. D.

.137 psi/ft .320 psi/ft .465 psi/ft .433 psi/ft

15. How many strokes to go from ICP to FCP? A. B. C. D.

1282 stks 1368 stks 1680 stks 1538 stks

16. How many strokes will it require to go from bit to shoe? A. B. C. D.

5364 stks 4122 stks 1658 stks 874 stks

17. How long will it take to go from bit to shoe at a pump speed of 30 spm? A. B. C. D.

about 214 minutes about 29 minutes about 157 minutes about 55 minutes

18. At 30 spm what is shoe to surface travel time? A. B. C. D.

about 108 minutes about 34 minutes about 214 minutes about 76 minutes





Kick Data and Gauges Workbook Questions 19. If the casing shoe is tested with 12 ppg mud in the hole, how much pressure is applied at the surface to give a fracture gradient of .91 psi/ft? A. B. C. D.

1250 psi 1500 psi 2000 psi 1950 psi

20. What would be the new MAASP once the well has been killed? A. B. C. D.

685 psi 1638 psi 700 psi 585 psi

21. At 30 spm how long will it take to pump kill mud to the bit? A. B. C. D.

157 mins 214 mins 56 mins 76 mins

22. If a 100 psi safety margin is included in the kill mud weight, what would the new kill weight be? A. B. C. D.

15.5 ppg 16.0 ppg 15.4 ppg 13.2 ppg

23. What would be the approximate pressure step down from ICP to FCP in psi/100 strokes. A. B. C. D.

30 psi/100 stks 46 psi/100 stks 50 psi/100 stks 66 psi/100 stks

Ref: ADMOD.DOC





Revision: 02

Kick Data and Gauges Workbook Questions Answer the following gauge questions as the well is killed using the Drillers method. TOTA L STRO KES 9 00

1 00 0

60

1 10 0

80 0

12 00

700

9 00

PSI

16 00

30 0

PSI

16 00

3 00

1 70 0 2 00

1 80 0 1 00

1 40 0 1 50 0

4 00

1 70 0 2 00

1 3 00

500

1 50 0

4 00

12 00

6 00

1 40 0

5 00

1 10 0

70 0

1 30 0

6 00

1 00 0

80 0

19 0 0

30

DRILLP IP E PRE SS URE

1 80 0 1 00

PUMP S PE ED

19 0 0

CA SING PRE SS URE

770

720 OPEN

CH OKE POSITION

C LOSE

24. The kill operation has started. This is what the choke control console shows. What should you do? A. B. C. D. E.

open the choke a little close the choke a little increase the pump speed decrease the pump speed nothing everything looks alright

TOTAL STROKES 900 1000 1100 800 700

900 1000 1100

300

1200

800

600

PSI

1600

300

1600

300

1700 200

1800 100

1400 1500

400

1700 200

PSI

500

1500

400

1300

600

1400

500

1200

700

1300

1900

PUMP SPEED

DRILLPIPE PRESSURE

30

1800 100

CASING PRESSURE

770

750 OPEN

CHOKE POSITION

1900

CLOSE

25. The operation has been going for 10 minutes. What should you do? A. open the choke a little B. close the choke a little C. increase the pump speed D. decrease the pump speed E. nothing everything looks alright

Ref: ADMOD.DOC





Revision: 02

Kick Data and Gauges Workbook Questions

TOTAL STROKES 900 1000 1100 800 700

900 1000 1100

1000

1200

800

1300

600

PSI

1600

200

1600 1700

300 200

1800 100

1400 1500

400

1700

300

PSI

500

1500

400

1300

600

1400

500

1200

700

1900

DRILLPIPE PRESSURE

1800 100

PUMP SPEED

1900

CASING PRESSURE

30

750

850 OP EN

CHOKE POS ITION

CLOSE

26. The pit levels are reported to be increasing slightly. This is what you see on the panel. A. B. C. D. E.

open the choke a little close the choke a little increase the pump speed decrease the pump speed nothing everything looks alright TOTAL STROKES 900 1000 1100 800 700

900 1000 1100

3000

1200

800

1300

600

PSI

1600

300

1600

300

1700 200

1800 100

1400 1500

400

1700 200

PSI

500

1500

400

1300

600

1400

500

1200

700

1900

PUMP SPEED

DRILLPIPE PRESSURE

1800 100

1900

CASING PRESSURE

30

770

950 OPEN

CHOKE POSITION

CLOSE

27. Casing pressure is still slowly increasing. What are you going to do now? A. B. C. D. E.

open the choke a little close the choke a little increase the pump speed decrease the pump speed nothing everything looks alright

Ref: ADMOD.DOC





Revision: 02

Kick Data and Gauges Workbook Questions TOTAL STROKES 900 1000 1100 800 700

900 1000 1100

4750

1200

800

1300

600

PSI

1600

300

1600

300

1700 200

1800 100

1900

PUMP SPEED

DRILLPIPE PRESSURE

1400 1500

400

1700 200

PSI

500

1500

400

1300

600

1400

500

1200

700

1800 100

1900

CASING PRESSURE

30

770

520 OPEN

CHOKE POS ITION

CLOSE

28. The casing pressure has been reducing for the last few hundred strokes. How are things going? A. B. C. D. E.

open the choke a little close the choke a little increase the pump speed decrease the pump speed good everything looks alright





Drilling Line Care and Maintenance Workbook Questions Refer to IPM Drilling Line Care and Maintenance workbook. Each question has only one correct answer. Part I 1.

Sharp corners, bad drum winding, loops in the line, or operating over small diameter sheaves, will cause what type of damage? A. B. C. D.

2.

How does drum crush occur? A. B. C. D.

3.

at the dead man anchor at the top of the crown block sheaves at the bottom of the travelling block sheaves at the new layer position on the drawworks

What is a ton-mile? A. B. C. D.

5.

Extreme pressure is brought down on the wire by an additional wrap on the drawworks. The line passes over sharp corners or small diameter sheaves. It occurs at the crossover points as the line hits the turn -back roller and starts a new layer. The line is overloaded.

Where does crossover wear occur? A. B. C. D.

4.

crossover wear drum crush doglegs tension breaks

the weight of the drill string multiplied by the depth of the hole the work needed to move one ton over a one mile distance the maximum drawworks capacity the depth of the hole divided by the weight of the string

What always takes precedence over ton-miles when it comes to drilling line replacement? A. B. C. D.

visual inspection depth of trip to be performed weight of assembly to be tripped how long until the end of the shift

Ref: ADMOD.DOC




Section: 4 Page: 15 Issued: 31 December 2006 Revision: 02

Drilling Line Care and Maintenance Workbook Questions 6.

What does 6 x 19 IWRC mean? A. B. C. D.

7.

Why do we cut the line rather than spooling more and more onto the drawworks? A. B. C. D.

8.

to prevent spooling problems to avoid damage to the line of other wraps to avoid accumulating too much line on the drawworks all of the above

If we keep ton-mile records why do we inspect the drilling line? A. B. C. D.

9.

the number of wires allowed to be damaged over a given length 6 strands, at 19 wires per strand, wrapped around an independent wire rope core 19 strands, at 6 wires per strand, wrapped around an independent wire rope core 19 strands of size 6 wire, wrapped around an independent wire rope core

to check for damage caused by jarring, fishing or other operation. to ensure the slip and cut off program is adequate. both A and B none of the above

Maintenance of what equipment has a direct bearing on the condition of a drilling line? A. B. C. D.

crown block, travelling block, drawworks, crown-o-matic, dead line stabilizer, dead line anchor, wire line turn-backs crown block, travelling block, drawworks, crown-o-matic, dead line stabilizer, wire line turn-backs crown block, travelling block, drawworks, dead line anchor, wire line turn-backs crown block, travelling block, crown-o-matic, dead line stabilizer, dead line anchor

10. How should wire line clips be attached to a line? A. B. C. D.

with the U-bolts over the dead end of the line with the U-bolts over the live end of the line with the base of the clip against the dead end of the line both B and C

Part II 11. What needs to be reset after string up or cut off? A. B. C. D.

the Drillers brake the drawworks auxilliary brake the cown-o-matic none of the above



Modular Training Program Drilling Line Care and Maintenance Workbook Questions

12. How much gap should the sensator have with empty blocks? A. B. C. D.

5/8 inch 3/8 inch 4/16 inch none of the above

13. How often should the crown block sheaves be greased? A. B. C. D.

every 8 hours after tripping only after 200 tonmiles daily

14. If you see a gap under the groove gauge, what is the most common cause? A. B. C. D.

The sheave is too small The drilling line is too big The sheave is worn too much, and should be replaced or re -grooved There is too much tar build-up on the sheave

15. What is likely to be the effect of a damaged sheave? A. B. C. D.

stuck pipe slow rate of penetration higher rotary torque damaged or broken drilling line

16. You should replace a turn -back when what wears out? A. B. C. D.

the drilling line the rubber on the roller the drawworks drum the crown block sheaves

17. What should be inspected on the drawworks? A. B. C. D.

damaged grooving wear plates wire line turn-backs all of the above





Drilling Line Care and Maintenance Workbook Questions 18. What should be attached to the derrick above the drawworks to prevent fast line flopping? A. B. C. D.

a wire line guide a dead line stabilizer a dead line anchor a turnback roller

19. Brass inserts can be replaced in what piece of equipment? A. B. C. D.

a wire line guide a dead line stabilizer a dead line anchor a turnback roller

20. How many wraps of line should be put on the drawworks with the travelling block at the lower pick up point? A. B. C. D.

18. 16 12 8

Part III 21. What is the standard operating safety factor for drilling line? A. B. C. D.

Seven Six Five Four

22. Where are the critical points of wear on the drilling line? A. B. C. D.

at the top of the crown block sheaves on pick up points at the bottom of the travelling block sheaves on pick up points at crossover points on drawworks and at the dead line anchor all of the above

23. What two things does slipping and cutting of drilling line accomplish? A. B. C. D.

It moves worn line away from critical wear points and continuously replaces worn line. It removes old line from service and moves points of heavy wear to non-critical points. It moves less worn line to the critical wear points and adds new line into the system. all of the above


Ref: ADMOD.DOC



Drilling Line Care and Maintenance Workbook Questions 24. When should visual inspection of drilling line take precedence over ton-mile goals? A. B. C. D.

always after jarring operations prior to running a heavy casing string during an end of well inspection

25. What does the wire rope service curve explain? A. B. C. D.

the required safety factor the number of days between slip and cuts the relationship between safety factor and ton-mile goals how much line to be cut off after slipping

Part IV Refer to the ton-miles tables in the IADC Drilling Manual to answer questions 26 - 28. You have just completed a round trip to a depth of 14,000 feet with the following tubulars : 18 x 30 foot (92 lbs/ft) 6 ½” x 2 ¾” Drill Collars, 5” 19.50 lbs/ft. Drill Pipe.(31 ft Average length) The travelling assembly weighs 20,000 lbs and the crown block weighs 10,000 lbs. Mud weight = 10 ppg 26. What is the excess weight allowance? A. B. C. D.

45,900 lbs 35,900 lbs 25,900 lbs 15,900 lbs

27. How many ton-miles were incurred tripping? A. B. C. D.

600 547 494 464

28. The trip before this involved 444 ton-miles tripping. How many ton-miles were used in drilling between trips? A. B. C. D.

468 309 150 60




Drilling Line Care and Maintenance Workbook Questions TON-MILES FORMULA – calculator method Refer to the IADC Drilling Manual: Ton-Mile Calculations Section and use the calculation below to answer questions 29 - 31. T r = D ( Ls + D ) Wm + D ( M + ½ C ) 10,560,000 2,640,000 You have just completed a round trip to a depth of 12,000 feet with the following tubulars: 15 x 30 foot (101 lbs/ft) 6 ¾” x 2 ¾” Drill Collars, 5” 19.50 lbs/ft. Drill Pipe.(31 ft Average length). The travelling assembly weighs 25,000 lbs and the crown block weighs 10,000 lbs. Mud weight = 10 ppg 29. What is the excess weight allowance? A. B. C. D.

60,000 lbs 50,000 lbs 40,000 lbs 30,000 lbs

30. How many ton-miles were incurred tripping? A. B. C. D.

537 493 411 386

31. The trip before this involved 245 ton-miles tripping. How many ton-miles were used in drilling between trips? A. B. C. D.

876 744 498 423




Drilling a Straight Hole Workbook Questions Refer to PETEX Drilling Technology Series Segment II, Routine Drilling Operations: Drilling a Straight Hole. Some questions have multiple answers. Sections: Hole Angle Change and Causes of Hole Deviation 1.

Straight-hole drilling should result in: A. B. C. D.

a perfectly straight hole. a trouble-free hole with no sharp edges or changes in direction. a wellbore that has no changes in angle. true vertical depth.

2. Use figure 1.4 to determine the true vertical depth and the horizontal drift in a hole drilled to 5,000 feet with a constant inclination from the vertical of 6°30'. A. B. C. D. 3.

Doglegs are likely to develop when— A. B. C. D.

4.

True vertical depth = 4,968 feet; horizontal drift = 566 feet True vertical depth = 5,000 feet; horizontal drift = 0 feet True vertical depth = 99.36 feet; horizontal drift = 11.32 feet True vertical depth = 993.6 feet; horizontal drift = 113.2 feet

the rate of hole angle change is greater than 3° per 100 feet of hole. the total hole angle change is greater than 3°. weight on bit is suddenly and drastically reduced. the penetration rate is too high.

Use the table in figure 1.7 to determine the dogleg severity with the following data: First Survey Vertical angle: 8° 15' (8G°) Direction: S 34° E Depth: 6,400 feet A. B. C. D.

5.

Second Survey Vertical angle: 2° 45' (2I°) Direction: S 9° E Depth: 6,475 feet

Dogleg severity = 7.82°/100 feet Dogleg severity = 6.12°/100 feet Dogleg severity = 5.87°/100 feet Dogleg severity = 7.82°

Doglegs are always more dangerous when they occur— A. low in the hole, close to total depth. B. near a key seat. C. in the middle of the wellbore where compression is greatest. D. in the top part of the hole.




Drilling a Straight Hole Workbook Questions 6.

Which of the following factors will increase the amount of fatigue damage to drill pipe? A. Corrosive drilling fluids B. Low tensile load in the pipe at a dogleg C. A severe dogleg

7.

Hole deviation is likely to occur in: A. laminar formations with dips up to 45°. B. uniform formations with dips up to 25°. C. formations with alternating hard and soft layers. D. laminar formations with dips more than 45°.

8.

When drilling in shale with a formation dip of 40°, the bit is most likely to— A. climb downdip. B. drill parallel to the bedding planes. C. be unaffected and drill vertical. D. climb updip.

9.

Key seats are formed when— A. the drill pipe penetrates the point of a dogleg. B. the bit drills through soft formations. C. the surface location is offset. D. total hole angle change exceeds the cone specifications.

10.

In the figure below, maximum tension is occurring at— A. point A. B. point B. C. points A and B simultaneously. D. point C.

11.

Keeping a hole straight is difficult in— A. dipping formations. B. folded formations. C. stratified formations. D. uniform formations.

12.

Drilling a straight hole is generally considered easier in soft formations because— A. less weight is required. B. more weight is required. C. the drill stem will bend less in soft formations than in hard ones. D. fewer joints of drill pipe are needed in soft formations than in hard.





Which of the following contribute to unwanted deviation of the wellbore? A. Dull bits B. Low bit weight C. Minimum clearance between the drill collars and the wall of the hole D. Undersized drill collars

14.

A spiraled and undersized hole can result from— A. low penetration rates in soft formations. B. a limber and unstabilized BHA. C. abrupt reduction of bit weight. D. exceeding the total hole angle change limit.

Section: Controlling Hole Deviation 15.

When formation characteristics cause the wellbore to drift upstructure, the surface location can be offset. This drifting has the result that— A. the surface location will be moved downstructure and the natural tendency of the formation will guide the bit to the target area. B. the well will be drilled with a packed-hole BHA to ensure a vertical borehole. C. penetration rate will be sacrificed because weight on bit must be reduced in order to keep the hole straight. D. the borehole must be plugged back and redrilled so that the contract deviation requirements are met.

16.

In an inclined hole, the most important influence working to keep the hole vertical is— A. the formation reaction. B. the axial load. C. a fulcrum stabilizer. D. gravity.

17.

The pendulum effect is— A. the force of gravity pulling on an unsupported length of drill collar. B. equivalent to the equilibrium condition. C. never greater than the formation reaction. D. increased by a high point of tangency.

18.

In drill collars, the areas most likely to bend are— A. those between the tool joints. B. the pin and the box. C. the body of the collar. D. the first 2 feet on either side of the tool joint.

19.

In the IADC Hole Inclination-Weight Tables (fig. 1.22), a class A formation— A. has severe crooked-hole tendencies. B. is the easiest to drill. C. has mild crooked-hole tendencies. D. can be easily drilled with a slick assembly.


Ref: ADMOD.DOC




It is best to use a pendulum assembly— A. as a corrective measure to reduce angle. B. in soft and unconsolidated formations. C. in a class B formation. D. when alternating hard and soft strata are expected.

21.

Use the table in figure 1.22 to determine which of the following statements are true with the following drilling conditions: Hole size: 8I" Hole class: R Formation dip: 15° A. B. C. D.

Hole angle: 4° Drill collar size: 7"

The driller can run 39,162 lb on the bit with the 7" drill collars and maintain hole angle. Bit weight can be increased to 68,500 lb if 7 1/2" drill collars are used and a stabilizer run at 60 ft above the bit without changing hole angle. Hole angle can be reduced to 2° by reducing bit weight by 7,362 lb and adding a stabilizer 80 ft above the bit. The driller can increase weight on bit to 46,200 lb with the same BHA and not affect hole angle.

22.

A sharp and drastic reduction in bit weight is the best way to reduce hole angle. A. True B. False

23.

The best stabilizer arrangement in a pendulum assembly is composed of— A. placement of a second stabilizer 30 feet above the fulcrum stabilizer. B. a single stabilizer placed immediately above the bit. C. a single stabilizer placed immediately above the first drill collar. D. two stabilizers run immediately above the bit.

24.

In the figure below, the tangency point is— A. point A. B. point B. C. point C. D. point D.

25.

The term gun barrel approach is sometimes used to refer to a— A. perfectly straight hole. B. pendulum assembly. C. packed-hole assembly. D. fulcrum stabilizer.





Moment of inertia, I, is used to express— A. weight on bit. B. rotary speed. C. drill collar stiffness. D. stabilizer weight.

27.

A properly designed packed-hole BHA will— A. minimize the rate of hole angle change. B. eliminate any bending in the drill string. C. reduce the possibility of doglegs. D. improve bit life and performance.

28.

A good packed-hole BHA will require— A. adequate clearance (at least 1 1/2" inches) between the bottom stabilizer and the wall of the hole. B. three stabilizer points. C. the largest-diameter collars that can safely be run in the hole. D. a large-diameter collar immediately above the bit that is at least of standard length, if not longer.

29.

A packed-hole BHA with three stabilizers in zone 1, one stabilizer in zone 2, and one stabilizer in zone 3 would be most suitable for— A. mild crooked-hole conditions. B. moderate crooked-hole conditions. C. severe crooked-hole conditions. D. none of the above.

30.

Increasing the size of the drill collar will— A. slightly increase the stiffness. B. slightly decrease the weight. C. greatly increase the stiffness. D. increase weight and stiffness in the same proportions.

31.

It is usually necessary to reduce weight on bit when changing from a packed-hole assembly to pendulum or packed pendulum BHA. A. True B. False

32.

If a driller reduces the bit weight in order to straighten the hole, he must— A. also change the bit so that the weight will be properly distributed on the cones. B. also decrease rpm. C. reduce the weight quickly so that penetration rate is not lost. D. reduce the weight gradually so that a dogleg will not develop.





Advantages of using downhole motors in straight-hole drilling operations include— A. reduced drill pipe wear. B. lower speeds. C. higher bit weight, allowing for increased penetration rates. D. increased penetration rates because of the higher bit speeds.

Section: Bottomhole Assembly Tools 34.

The buoyancy factor for 12.8-ppg mud is— A. 12.8 ppg. B. 95.75 lb/cu ft. C. 0.804. D. 8.04 lb.

35.

How much does a standard-length drill collar weigh if it has a 5 1/2" OD and 2 1/4" ID? A. 67 lb B. 2,010 lb C. 6,700 lb D. 201.0 lb

36.

What total weight of drill collars in air is required with the following drilling conditions? Bit weight required: 68,500 lb Safety factor: 15% Drilling mud density: 12.2 ppg Vertical hole: 0° inclination A. B. C. D.

37.

6,457 lb 68,500 lb 78,775 lb 96,775 lb

How many 7 ¼’" OD x 2 ¼” ID standard-length drill collars will be needed with the following drilling conditions? Bit weight required: 32,440 lb Drilling mud density: 9.8 ppg Safety factor: 15% A. 14 B. 12 C. 8 D. 7





If seven standard -length 6" OD x 2 13/16" ID drill collars are used, how many standard-length 7 ½” OD x 2 13/16” ID collars will be needed with the following conditions? Bit weight required: 46,129 lb Drilling mud density: 12 ppg Safety factor: 17% A. B. C. D.

24 14 13 7

39.

The point at which the drill collar string changes from compression to tension is called the— A. neutral point. B. equilibrium condition. C. point of tangency. D. fatigue damage.

40.

Large drill collars are the best tools for combating crooked-hole problems. In fact, the largest drill collars available should be used because drill collars cannot be too large in crooked-hole country. A. True B. False

41.

A general rule of thumb that can be used in selecting drill collars for a transition zone is to— A. install the largest-OD, thickest-walled collars possible. B. always use square drill collars. C. reduce drill collar size not more than 2 inches at any crossover. D. use only one drill collar for each size reduction.

42.

Square drill collars— A. should be gauged at every trip and replaced if worn more than 1/4 inch. B. are most effective in soft formations. C. should be only 1/16 inch smaller than the hole when new. D. should be used with a reamer run above the bit for protection.

43.

A properly stabilized BHA should— A. use fewer bits. B. maintain a straight course. C. allow lateral movement of the bit. D. allow use of optimum drilling weight.


Ref: ADMOD.DOC




A nonrotating sleeve stabilizer is best suited for— A. holes with rough walls. B. hard formations. C. holes with temperatures higher than 250°F. D. holes with temperatures less than 250°F.

45.

An appropriate stabilizing tool for a hard formation is— A. one with a large wall contact area. B. a welded-blade stabilizer. C. an integral-blade stabilizer. D. a replaceable-blade stabilizer.

46.

A sleeve stabilizer— A. can be used in soft, medium, and some hard formations. B. can be used in various hole sizes, depending on the sleeve. C. is assembled with high temperatures (up to 750°F). D. allows for blades to be easily changed, as the sleeve can be replaced on the rig floor.

47.

The primary purpose of a roller reamer in the BHA is to— A. stabilize the bit. B. increase bit weight. C. reduce hole angle. D. maintain hole out to gauge.

48.

Which of the following tools would most probably be used in a hard formation? A. Integral-blade stabilizer B. Rolling cutter reamer C. Go-devil D. Welded-blade stabilizer

49.

In very severe crooked-hole conditions, a vibration dampener should be run— A. between zones 1 and 2 in place of a short drill collar. B. immediately above the bit. C. above zone 3, with an additional stabilizer 30 feet above it. D. immediately above zone 2.

50.

Inaccurate recordings from deviation-recording instruments may result from— A. drill pipe movement. B. movement of the drilling fluid. C. inadequate resting time on bottom. D. running and retrieving the barrel assembly on ordinary sand line.




Rig Hydraulics Workbook Questions Refer to PETEX Drilling Technology Series Segment II, Routine Drilling Operations: Rig Hydraulics. Some questions have multiple answers. Sections: Introduction and The Hydraulic System. 1.

A properly designed hydraulic system will: A. B. C. D.

gouge out new hole in all formations by powerful jet nozzle action. deliver adequate power to the bit nozzles for bottomhole cleaning. provide enough pressure to the drilling mud to transport cuttings out of the annulus. not influence other drilling variables such as bit weight and rotary speed.

2. In using prepared tables to determine pressure losses in the hydraulic system, the ______ must be taken account of if it differs from that used in preparing values for the table. A. B. C. D. 3.

mud viscosity rotary speed bit weight mud weight

Reducing the amount of pump input power will not have any effect on the drilling rate if the proper bit has been selected for the drilling operation. A. B.

True False

4.

Use the 10D2 rule to determine the input pump power for properly cleaning an 8 ½” hole. A. 80 hp B. 800 hp C. 810 hp D. 810 hhp

5.

If necessary, two pumps can be compounded in a series to increase— A. fluid output. B. fluid velocity. C. fluid pressure. D. all of the above

6.

Which of the following conditions will result in the largest increase in hydraulic horsepower? A. Increasing fluid pressure and decreasing fluid volume B. Increasing fluid pressure and keeping fluid volume constant C. Increasing both fluid pressure and the fluid volume D. Decreasing both fluid pressure and fluid volume at a slow but constant rate




Rig Hydraulics Workbook Questions 7.

What is the hydraulic horsepower produced by a pump that delivers 419 gpm at 2,330 psi? (Answers are rounded to the nearest whole number.) A. 570 hhp B. 1,714 hhp C. 2,749 hhp D. 976,270 hhp

8.

Determine the input power needed to deliver the amount of hydraulic horsepower in question 7, if the pump is 90% efficient. A. 90 hp B. 570 hhp C. 518 hp D. 633 hp

9.

What is the approximate standpipe pressure for a pump that delivers 590.4 hhp with a circulation rate of 460 gpm? A. 1,714 psi B. 2,200 psi C. 2,729 psi D. 590.4 psi

10.

What hydraulic horsepower is produced by a pump that delivers drilling fluid at a rate of 12 bbl/min with 2,100 psi? A. 14.7 hhp B. 560 hhp C. 617.5 hhp D. 721.2 hhp

Section: Pressure Losses in the System. 11.

The greatest pressure loss in the hydraulic system occurs— A. in the surface equipment. B. across the bit. C. in the annulus. D. at the surface in the mud tank.

12.

Use figures 2.6 and 2.7 in the lesson to determine the pressure loss for the following equipment: standpipe–45 ft with 4" ID; hose–55 ft with 3" ID; swivel–5 ft with 2 ¼” ID; kelly–40 ft with 3 ¼” ID. Circulation rate is 570 gpm with 10-ppg mud. A. 254 psi B. 91 psi C. 56 psi D. 38 psi





If the surface equipment given in question 12 were used with 12.2-ppg mud and circulated at 540 gpm, what pressure loss would occur? A. 82 psi B. 61 psi C. 50 psi D. 44.6 psi

14.

The best way to determine pressure losses in the drill string is to tabulate losses in the drill pipe and drill collars separately and then add them together. A. B.

True False

Use figures 2.9 and 2.10 with the following drilling conditions to answer questions 15, 16, and 17. Drill pipe: Size: 4 ½ “ OD Weight: 16.6 lb/ft Tool joint type: XH

Drill collar size: 2-inch bore, 8” OD Circulation rate: 490 gpm

15.

With 10-ppg mud, the pressure loss through 7,500 feet of drill pipe is— A. 96 psi. B. 490 psi. C. 720 psi. D. 720,00 psi.

16.

If a 10-ppg mud is used, what is the pressure loss through 330 feet of drill collars? A. 151.2 psi B. 211 psi C. 490 psi D. 696.3 psi

17.

If 9-ppg mud is used, what is the total pressure loss occurring through 7,500 feet of drill pipe and 330 feet of drill collars? A. 307 psi B. 1,274.6 psi C. 1,416.3 psi D. 1,573.6 psi

18.

The amount of pressure available for the bit should be ___________ percent of the total pressure from the pump. A. 33–47 B. 50–75 C. 100 D. none of the above





Pressure losses in the drill string will be increased by— A. large-diameter drill pipe. B. low-weight mud circulated at a slow flow rate. C. plastic-lined drill pipe. D. none of the above

20.

If a properly designed hydraulics program delivers a total of 685 hhp at the surface, what is the minimum hhp needed at the bit (bhhp)? A. 342.5 B. 547.6 C. 685 D. 1,027.5

21.

The drilling fluid undergoes a large pressure decrease and a great velocity increase at the bit nozzles. A. B.

True False

22.

Pressure losses in the annulus are affected by— A. size of drill string. B. circulation rate. C. size of hole. D. all of the above

23.

Generally the velocity of the drilling fluid in the annulus should be as high as possible and, in any case, never less than the rate in the drill string. A. B.

24.

True False

Which one of the following drilling fluids would give the highest pressure losses? A. Clear water B. Oil-based mud C. High-density mud D. High-viscosity mud

Section: Bit Hydraulics. 25.

Generally, the amount of horsepower needed at the drilling face is— A. less than 3 hp per square inch of hole bottom. B. 3 to 5 hp per square inch of hole bottom. C. at least 10 hp. D. equal to the hole diameter squared.





Bit hydraulic horsepower, bhhp, is— A. the total fluid power available at the bit. B. the total fluid power available to and used by the hydraulic system. C. decreased by high pressure losses in the drill string. D. increased by high pressure losses in the annulus.

27.

What is the bhhp in a system with the following drilling conditions? Pressure losses in surface equipment and drill string–680 psi; circulation rate–460 gpm; total hhp–564; surface pressure–2,100 psi. A. 377.8 B. 685 C. 247.1 D. 381

28.

A jet nozzle that measures 8/32 inch in diameter of nozzle opening is called a size— A. 0.25. B. 32. C. 8. D. none of the above

29.

In a tricone bit, nozzle velocity can be incre ased by— A. increasing the circulation rate. B. doubling the size of the nozzles and blanking off one jet. C. using smaller nozzles. D. all of the above.

30.

Use the table in figure 2.16 to determine the best nozzle combination for a hydraulics program that has a circulation rate of 820 gpm and pressure available at the bit of 1,560 psi (assume 10-ppg mud). The appropriate nozzle combination is— A. one 16 and two 18s. B. two 16s and one 18. C. three 16s. D. one 15 and two 16s.

31.

Doubling the flow rate and doubling the size of the nozzle will double the nozzle velocity at the bit. A. B.

True False

Sections: Annular Hydraulics and Designing the Rig Hydraulics Program. 32.

In the annulus, the drilling fluid— A. will be in turbulent flow at all times. B. should be maintained at high-velocity laminar flow. C. should remove the cuttings as quickly as possible without causing hole washout. D. can change from laminar flow to turbulent flow in constricted passages.





Slip velocity is decreased by— A. small cutting size. B. high-density mud. C. high-viscosity mud. D. all of the above.

34.

Use tables 1 and 2 to determine the annular velocity for the following drilling conditions: circulation rate–420 gpm; drill pipe size–4" OD and 3.34" ID; hole size– 7 7/8”. A. 96.75 ft/min B. 14 ft/min C. 5 ft/min D. 230.4 ft/min

35.

The main objectives in planning an efficient hydraulics program are to— A. select the correct nozzle combination for bottomhole cleaning. B. project the final depth of the hole. C. increase the effectiveness of bit weight and rotary speed. D. do all of the above.




Drilling Muds Workbook Questions Refer to PETEX Drilling Technology Series Segment II, Routine Drilling Operations: Drilling Muds. Some questions have multiple answers. Sections: Introduction and Drilling Fluid Composition and Properties. 1.

When added to water, a good drilling clay will: A. B. C. D.

hydrate. react with the inert fraction. thin the mud. increase viscosity.

2.

The reactive portion of the drilling mud is sometimes called the: A. liquid phase. B. colloidal fraction. C. inert fraction. D. emulsion.

3.

The plastic viscosity of a drilling mud depends on— A. the strength of the electric charges on the solid particles in the mud. B. mechanical friction in the mud. C. high yield point. D. the concentration, size, and shape of solids in the mud.

4.

According to the clay-yield curve shown in figure 3.6, roughly how many pounds of common drilling clay are needed to produce 1 barrel of 15-centipoise mud? A. 100 B. 20 C. 10 D. 200

5.

A water-base mud can be deflocculated by— A. increasing the viscosity. B. adding chemical thinners. C. neutralizing attractive charges in the mud. D. increasing the yield point.

6.

The gel strength of a mud concerns its ability to— A. temporarily thicken when mud flow stops. B. produce a good filter cake. C. flow after circulation is restarted. D. increase as yield point decreases.




Drilling Muds Workbook Questions 7.

Filtration rate is— A. the amount of clay solids lost to a formation. B. increased by adding inert solids to the mud. C. increased by adding bentonite to the mud. D. the amount of liquid in the mud lost to a formation.

8.

Bentonite, a clay often used in drilling muds, will hydrate greatly when added to the mud, regardless of what the continuous liquid phase is made up of. A. B.

True False

9.

Filter cake is— A. made up of solids in the drilling mud. B. another name for cuttings. C. harmful to the hole wall and should be removed with deflocculants. D. none of the above.

10.

Inert solids in the drilling mud— A. .issolve when they are added to the drilling mud. B. hydrate when wetted. C. are smaller than clay particles in the mud. D. have none of the above characteristics.

11.

The colloidal fraction of a drilling mud can contain— A. low-yield commercial clays. B. drilled solids. C. weight materials. D. all of the above.

12.

An unweighted mud will— A. not contain barite or other weight materials. B. often contain drilled solids. C. generally have a density higher than 10.5 ppg. D. do all of the above.

Section: Functions of Drilling Fluids. 13.

One function of drilling mud is to— A. fill new formations with bentonite. B. help enlarge the wellbore. C. deposit a wall cake on the wellbore. D. maintain high turbulent flow in the annulus.


Ref: ADMOD.DOC




Another function of the drilling mud is to— A. dissolve limestone layers so that drilling through them is easier. B. cool and lubricate the bit and drill string. C. impose back-pressure on the bit. D. allow larger cuttings to settle to the bottom of the hole rather than clog up the annulus.

15.

The density of a drilling fluid is important for— A. cleaning used drill pipe. B. supporting some of the suspended weight of drill pipe or casing. C. increasing the weight of the drill string in the hole. D. controlling formation pressure.

16.

Which of the following factors will cause inaccurate results in an electric log? A. The use of an oil-base mud as the drilling fluid B. Excessive water filtrate in the formation C. The use of seawater as the makeup water for the mud D. None of the above

Section: Water-Base Muds. 17.

Mud-up operations may involve adding— A. premium clays. B. PAC. C. phosphates. D. all of the above.

18.

An additive that can be used to improve filtration in muds with salt contamination higher than 20,000 ppm is— A. barite. B. PAC. C. asbestos. D. CMC.

19.

Water-back is an operation that— A. increases the fluid-to-solids ratio. B. increases the solids-to-fluid ratio. C. increases viscosity. D. lowers the rate of water loss.

20.

Bentonite is added to freshwater muds to— A. decrease mud weight. B. increase viscosity. C. inhibit corrosion. D. lower water loss.





Thinning a mud may involve— A. adding CMC. B. deflocculation. C. flocculation. D. increasing water loss.

22.

Filtration control agents are added to a mud to— A. increase the filtrate. B. decrease formation permeability. C. reduce water loss. D. lower cement contaminants.

23.

Adding barite to mud will— A. increase the mud weight. B. increase the inert solids content. C. increase the mud volume of the system. D. all of the above

24.

High viscosity, yield point, and gel strength can be caused by— A. a low concentration of drilled solids. B. insufficient deflocculation of clay solids. C. contamination from gypsum, cement, or salt. D. all of the above

25.

Water loss from the mud can be lowered by adding— A. PAC. B. gums. C. starch. D. shale.

26.

A drilling mud with a pH of 9.5 is considered— A. acidic. B. neutral. C. alkaline. D. none of the above

27.

Which of the following additives could be used to reduce viscosity and gel strength in a mud with a pH of 10? A. Lignite B. Quebracho C. CMC D. Lignosulfonate


Ref: ADMOD.DOC




With salt contamination, the best way to remove salt from the mud is by— A. adding a commercial flocculating agent. B. treating the mud returns with a large amount of barite at the shale shaker. C. adding a small amount of CMC. D. none of the above

29.

The best procedure for drilling in thick salt beds or dome salt is to convert to clear water for the drilling fluid until the salt formation has been penetrated. A. B.

True False

Section: Water-Base Muds. 30.

Adding lime to a spud mud will— A. make it unusable for drilling through surface casing. B. increase the mud's viscosity. C. require less clay for building viscosity. D. require more barite to increase density.

31.

The viscosity of a good natural mud can be lowered by— A. treating it with phosphates. B. adding premium drilling clay. C. adding large amounts of water. D. all of the above.

32.

A phosphate-treated mud can be effectively used— A. with calcium contamination. B. for reducing viscosity, gel strength, and filtration rate. C. in shallow wells with freshwater formations. D. with saturated salt water as the makeup water.

33.

A characteristic of lignosulfonate muds is that— A. they actively interact with formation clays. B. they are effective with normal calcium and salt concentration. C. they can maintain low viscosity in heavily weighted muds. D. all of the above are true.

34.

A calcium-treated mud can be effectively used for— A. controlling sloughing shales. B. reducing viscosity caused by drilled solids. C. controlling hole enlargement. D. all of the above





Which of the following muds would be most effective in a drilling operation that encounters bottomhole temperatures of 300°F? A. Phosphate-treated muds B. Calcium hydroxide or lime mud C. Lignosulfonate mud D. all of the above

36.

Which of the following additive-effect combinations is correct when used in a saltwater mud? A. CMC to increase filtration B. Lignosulfonate as a thinner C. Bentonite as the primary additive for the colloidal fraction D. Pin oil to reduce the effects of foaming

37.

To function effectively as drilling fluids, clear fresh water and salt water frequently require— A. additives for decreasing viscosity. B. additives for reducing flocculation. C. mechanical equipment for solids control. D. additives for controlling filtration rate.

38.

Advantages of polymer muds include the following: A. Thev can be effectively used with salt water without additional chemical treatment. B. They allow the high viscosity in the annulus necessary for cutting removal. C. They have low viscosity at the bottom of the hole for rapid drilling. D. They require less bentonite to maintain proper viscosity.

39.

Particular care should be exercised in adding chemicals to the mud because some — A. are poisonous. B. cause burns to skin. C. are dangerous when inhaled. D. include all of the above characteristics.

Section: Oil-Base Muds. 40.

Advantages of oil-base muds include— A. low initial costs. B. low density. C. ability to function effectively at high downhole temperatures. D. the fact that barite or other weight materials are not used in oil muds.

41.

A mud with a continuous phase made up of 30% water and 70% diesel oil is called— A. a true oil-base mud. B. a low-solids mud. C. a polymer mud. D. an invert emulsion mud.





In an oil-base mud, the colloidal fraction is— A. comprised of natural clays. B. comprised of bentonite, hectorite, or attapulgite. C. eliminated. D. replaced by defoamers.

43.

In an invert emulsion mud, water will— A. dilute salts and asphalt materials. B. reduce the viscosity of the mud. C. lessen control of fluid loss. D. do none of the above.

44.

The amount of soap formed in an oil-base mud must be controlled because excessive amounts of soap can reduce penetration rates. A. B.

True False

45.

Which of the following units are expressions of density? A. Pounds per gallon B. Gradient in psi per 1,000 feet of mud in the hole C. Pounds per 100 square feet D. Kilograms per litre

46.

When calibrating a mud balance, fill the cup with pure water and set the movable weight to read— A. zero. B. 8.1 ppg. C. 8.33 ppg. D. 10 ppg.

47.

In a field test, the mud man would measure apparent viscosity of the mud— A. in pounds per 100 square feet. B. in terms of specific gravity. C. with a Marsh funnel. D. in seconds per quart (946 cc).

48.

The filtration test measures— A. plastic viscosity over time. B. water loss under pressure. C. thickness of wall cake in 1/32 inch increments. D. specific gravity of the solids.





Procedures for testing oil-base and water-base muds are basically the same except that the funnel viscosity of a water-base mud varies greatly with temperature changes, while the apparent viscosity of an oil mud is not affected by temperature. A. B.

50.

True False

The sand content determination test measures— A. sand content by weight. B. precipitation rate of sand in solution. C. percent of sand by volume. D. none of the above.




Casing Workbook Questions Refer to PETEX Drilling Technology Series Segment II, Routine Drilling Operations: Casing. Some questions have multiple answers. Section: Introduction and Types of Casing. 1.

Each of the following is considered to be a primary function of casing in a well except— A. B. C. D. E.

to provide a means of controlling well pressure. to confine production to the wellbore. to allow production from multiple producing formations. to permit installation of artificial lift equipment. to prevent the hole from caving.

2.

One of the major differences between casing and drill pipe is that— A. the length range of the casing most frequently used is shorter than the standard joint of drill pipe. B. the range of casing OD and wall thickness is much greater than that of standard drill pipe, accounting for the larger diameter and increased weight of casing. C. the ID of most casing is smaller than the ID of drill pipe, accounting for the greater wall thickness of casing. D. drill pipe is threaded on each end and most casing is not.

3.

The conductor pipe is almost always cemented in offshore wells. A. B.

True False

4.

A typical casing arrangement on land is made up in the following order: A. conductor, structural, surface, and intermediate casing. B. surface, intermediate, production, and oil string casing. C. surface, conductor, intermediate, and production casing. D. conductor, surface, intermediate, and production casing.

5.

The short string refers to the— A. intermediate casing. B. conductor. C. oil string. D. liner settings.

6.

Factors influencing the depth at which surface casing is set include— A. state rules and regulations. B. depth of mineral deposits requiring protection. C. formation fracture gradient. D. all of the above


Ref: ADMOD.DOC



Casing Workbook Questions 7.

The casing string that seals off weak zones that might rupture with heavy muds needed to drill deeper and protect against lost circulation in shallow formations is— A. surface casing. B. conductor pipe. C. intermediate casing. D. oil string casing.

8.

The main purpose of surface casing is to— A. isolate the producing formation. B. provide an inexpensive means of testing lower zones. C. protect freshwater formations. D. do all of the above.

9.

Surface casing and intermediate casing have entirely different functions, so in a well where surface casing is set to 5,000 feet, intermediate casing will not be needed. A. B.

True False

10.

Advantages of liner settings are that— A. they are almost always cemented in place. B. their installation involves lower costs. C. they require a relatively short amount of time on bottom for installation. D. they can be used in place of surface casing.

11.

Production casing is sometimes called— A. oil string. B. long string. C. tieback casing. D. all of the above.

12.

Frequently, the heaviest string of pipe set in the well is the— A. intermediate string. B. tieback string. C. conductor. D. production string.

Sections: Casing Standards and Casing String Design. 13.

The main difference in the various grades of steel used in API rated casing is— A. length. B. minimum yield strength. C. outside diameter. D. type of thread.





The most frequently used casing is— A. Range 1, 16–25 feet in length. B. Range 2, 25–34 feet in length. C. Range 3, 34–48 feet in length. D. shorter in length than Range 1.

15.

A casing string for a particular well is usually made up of uniform grades of casing. A. B.

True False

16.

Casing that is shorter in length than the standard ranges is called— A. short strings. B. couplings. C. joints. D. pup joints.

17.

Factors that affect the design of a casing string for a well include— A. tension. B. collapse pressure. C. burst pressure. D. all of the above

18.

The minimum tensile strength for API Casing Grade J-55 is— A. 55,000 psi. B. 80,000 psi. C. 75,000 psi. D. 100,000 psi.

19.

When designing casing strings, designers need not consider couplings because the coupling strength equals the strength of the pipe body. A. B.

20.

True False

Failure of new casing can usually be attributed to— A. damage while being handled. B. excessive pressures. C. improper grade. D. stress concentration cracks.


Ref: ADMOD.DOC




Revision: 02


When couplings are screwed onto the casing handling-tight, they are— A. loose enough to be easily removed by hand. B. tight enough so that a wrench must be used to remove them. C. also tightened to the power-tight position. D. easily removed for cleaning and inspecting before the pipe is used.

22.

Collapse pressures are— A. generally disregarded for surface casing. B. a result of downward force pulling on the casing body and couplings. C. greatest at the bottom of the hole. D. important considerations for selecting some strings, such as the production string.

23.

The casing strings that must withstand the greatest burst pressures are the— A. conductor. B. surface. C. intermediate. D. production.

24.

Use the most commonly employed tension factor to calculate the amount of weight that could be suspended from a top joint with a tensile strength of 420,000 pounds. A. 756,000 pounds B. 75,600 pounds C. 233,334 pounds D. 23,334 pounds

25.

Torsional stress— A. is a result of forces pushing down on the pipe. B. often occurs because of hole deviation or marshy terrain. C. may be expected if rotating scratchers are used. D. occurs when portions of the pipe turn in opposing directions.

26.

Factors affecting the selection of properly sized production casing for a well include— A. method of production for the well. B. common practices in the area. C. rate of production for the well. D. none of the above.

Section: Casing Accessories. 27.

Installing casing accessories by welding is probably not desirable because— A. welding can cause stress concentrations in the metal that may result in pipe failure. B. welding can cause accessories to break off and fall to the bottom of the hole. C. welding will damage the accessories. D. welding prevents casing accessories from moving freely on the pipe.





Experience from the field has shown that some slurry contamination occurs below the top plug. To reduce the chance of slurry contamination in the annulus, an operator may practice— A. not using a top plug. B. using a float collar near the casing shoe. C. using guide shoes. D. using a float collar a distance of one or more lengths above the casing shoe.

29.

The device used to guide the casing around obstructions or ledges in the hole is a— A. float collar. B. baffle collar. C. centralizer. D. guide shoe.

30.

An automatic fill-up shoe will— A. control the amount of fluid entering the bottom of the casing string as it is run into the hole. B. reduce the surge pressure. C. reduce the possibility for lost circulation. D. all of the above

31.

Operators cementing very long casing strings in which the potential for formation damage is high may cement separate sections with the use of— A. high-pressured pumps. B. multistage cementing devices. C. baffle collars. D. any of the above

32.

Casing strings cemented without centralizers are more likely to— A. obtain a better bond between the casing and the formation. B. have less wall cake. C. have a uniform sheath of cement around the pipe. D. none of the above

33.

Scratchers clamped to the casing can add strength to the cement sheath holding the casing in place because they lace the cement with steel cables. A. B.

True False

Section: Setting Casing. 34.

Powered casing tongs are beneficial in running casing because they— A. ensure proper makeup for each threaded joint. B. properly score the casing with die marks. C. eliminate the hazards of the spinning rope. D. save labor.





Thread protectors should be removed from the casing as it is— A. removed from the truck. B. counted. C. stacked on the pipe rack. D. none of the above

36.

In most cases, the regular rig crew will prepare for the casing operation by— A. preparing the hole. B. checking the operating condition of rig machinery. C. making arrangements for filling casing as each joint is made up. D. all of the above

37.

Preparing the hole includes— A. going into the hole with one stand of drill collars and a used bit. B. removing any casing accessories that may have come loose and fallen to the bottom of the hole. C. maintaining circulation until all the cuttings have settled at the bottom of the hole. D. all of the above

38.

Accurate casing measurement is essential on any casing job. The task of measuring casing for a given job may be accomplished by— A. electric logs. B. cement bond logs. C. measuring and counting joints of pipe delivered to the site. D. checking shipping papers. E. using casing tally sheets.

39.

If a clean thread protector is in place as a joint of casing is picked up from the catwalk, it is not necessary to apply thread compound before stabbing. A. B.

40.

True False

Thread-locking compound hardens— A. very slowly over a period of several days. B. to prevent joint back-off. C. to a point at which it is four times harder to break the connection than it was to make it up. D. according to all of the above statements.





Procedures for handling casing properly include— A. gently rolling the casing off the delivery truck onto the ground. B. using a large heavy-duty hook in the ends of the threaded casing to lift the casing if thread protectors are in place. C. neatly stacking the casing on the ground so that there is no danger of the pipe falling and becoming damaged. D. none of the above

42.

Correct procedures for stabbing casing include— A. rolling the pin into the box or coupling if the pipe misses it on the firs t try. B. running at least three joints of casing at a time to ensure adequate weight for efficient stabbing. C. applying as much torque to the connection as possible to overcome any misalignment of threads. D. none of the above

43.

Inadequate conditioning of the hole and improper mud treating may cause problems such as— A. poor cementing. B. stuck pipe. C. redrilling the hole. D. all of the above

44.

During a casing job, it is a good practice to fill the casing periodically as the pipe is run in the hole because— A. large-diameter pipe may collapse because of unbalanced pressure outside the pipe. B. the pipe may stick. C. it aids in the cementing process. D. it helps prevent a blowout.

45.

The volume of mud gain by the pits when a 15,000-ft, 5 ½” OD casing is run in a well and completely filled up (assume no fluid loss) is— A. 100 barrels. B. 10.9 barrels. C. 109.0 barrels. D. 190.0 barrels.

46.

Operators can reduce the chance of losing circulation while running casing by— A. lowering the casing more slowly. B. installing additional casing accessories. C. increasing the mud viscosity. D. none of the above.





Circulating the casing string after reaching bottom produces some desirable effects, including— A. flushing out cuttings and wall cake before cementing. B. conditioning the mud. C. testing the surface piping system. D. all of the above

48.

It is not considered good practice to move the casing either by rotating or reciprocating when scratchers are installed. A. B.

True False

49.

Landing practices recommended by API include— A. slacking off weight when landing casing because the casing hanger cannot withstand the same amount of weight as the elevator. B. landing casing with the same weight on the casing hanger as that supported by the elevator. C. landing casing at the wellhead in the exact position it had when cemented. D. picking up weight on the casing hanger when landing the casing.

50.

Changes in temperature as well as other operational changes in a well require that casing withstand several types of loads, including— A. burst. B. collapse. C. buckle. D. tension. E. all of the above


Ref: ADMOD.DOC



Cementing Workbook Questions Refer to PETEX Drilling Technology Series Segment II, Routine Drilling Operations: Cementing. Some questions have multiple answers. Section: Mixing Cement 1. In addition to providing support for casing, primary cementing is essential to the well because it: A. B. C. D. 2.

prevents casing corrosion. allows formation fluids from different zones to mix and flow to the surface. prevents the hole from caving below the casing. makes drilling the well easier.

If a well has a high-quality casing job, cement is usually not needed. A. B.

True False

3.

A cementing crew may not wish to use water from a stock tank near a well site because— A. the water might contain organic chemicals that affect the setting properties of cement. B. the water might foul pumping equipment. C. the water supply might be inadequate. D. all of the above

4.

The use of seawater with cement will— A. decrease the early strength of the cement. B. result in a stronger cement over a long period (say 28 days) of time. C. prevent the cement from setting. D. increase the early strength of the cement.

5.

The best temperature range for slurry is— A. below 60°F to prevent water loss from evaporation. B. between 60°F and 90°F as it goes into the well. C. between 90°F and 100°F as it goes into the well. D. higher than 100°F to ensure proper viscosity.

6.

Experience from the field suggests that the best water-cement ratio is approximately— A. 10 ½ gallons per sack of cement. B. 11 ¼ gallons per sack of cement. C. 5 ½ gallons per sack of cement. D. 8 gallons per sack of cement.

7.

Given water requirements of 500 gallons per cementing unit and 500 gallons for safety and error and assuming that two cementing units dispatched to a location require 1,500 sacks of cement, the minimum amount of water needed to safely complete the job would be— A. 9,250 gallons. B. 9,750 gallons. C. 10,250 gallons. D. 10,000 gallons.




Cementing Workbook Questions 8.

The recirculating mixer is the most widely used cement mixer because— A. it employs a partial vacuum in the hopper, which is a desirable element for cement mixing. B. cement and water are blended by a stream of air, and this produces a smoother slurry. C. it was the first system widely used, and repair parts are easy to obtain. D. it produces a smooth and homogeneous cement slurry due to the process of mixing the wet cement with recirculated slurry.

Sections: Pumping Cement and Cement Volume Requirements 9.

The purpose of using a preflush in cementing operations is to— A. accelerate the setting time. B. remove some of the wall cake. C. provide a spacer between the drilling mud and the slurry. D. increase the density of the slurry.

10.

Slurry density can be checked with— A. a mud balance. B. a Marsh funnel. C. an automatic recorder. D. all of the above

11.

Each of the following is considered a benefit derived by pumping water as a flushing agent ahead of the cement except— A. it reduces cement contamination. B. it can be put into turbulent flow at a low circulation rate. C. it decreases cement setting time. D. it is easy to obtain.

12.

In order to achieve the maximum amount of mud removal and also some reduction in the amount of filter cake, operators should— A. obtain turbulent flow while pumping cement. B. obtain laminar flow while pumping cement. C. obtain plug flow while pumping cement. D. add friction-reducing chemicals to the cement.

13.

Slurry density should be carefully controlled by the cementer because— A. it is a direct indication of the water-cement ratio that affects hydration. B. it should always be kept lower than 12 ppg. C. it indicates slurry volume. D. it may be particularly important when lost circulation is a factor.

14.

The bottom plug is ruptured by pump pressure, but the solid top plug is not. A. B.

True False


Ref: ADMOD.DOC




An improved cement job results if the operator pumps the slurry— A. at the lowest rate possible with no delays. B. at the highest rate possible with intermittent delays. C. at a moderate rate, changing frequently from the highest rate possible to the lowest rate possible with no delays. D. at the highest rate possible with no delays.

16.

Benefits derived from using a bottom plug in the cementing operation include— A. wiping mud film from inside casing. B. reducing slurry contamination. C. preventing entry of air into slurry. D. all of the above

17.

Pressure should be bled off the casing before — A. the top plug ruptures. B. the cement sets, so the pipe will not bulge. C. the valve in the float collar closes. D. none of the above

18.

Which of the following substances can be used as displacement fluid? A. Seawater B. Fresh water C. Drilling fluid D. all of the above

19.

Using the rule-of-thumb method to calculate the capacity of a 15,000-ft open hole, the diameter of which is 8 5/8 inches, the amount of fluid needed to fill the hole is approximately— A. 1,350 barrels. B. 1,000 barrels. C. 1,500 barrels. D. 1,215 barrels.

20.

Using the information in question 19, assume that 7-in. OD casing, J-55, 26 lb/ft, was run in the hole. Using the rule-of-thumb method, the volume (cubic feet) of fluid required to fill the annular space is— A. 3,400 cubic feet. B. 2,688 cubic feet. C. 2,500 cubic feet. D. 2,000 cubic feet. E. none of the above

21.

To ensure effective cement bonds to casing strings, operators usually cement each casing string from the bottom to the top. A. B.

True False





In determining the volume of an open hole with the diameter-squared method, a slightly larger figure for diameter should be used to allow for— A. larger casing OD. B. hole enlargement. C. errors in calculation. D. an extra amount of cement slurry as a safety factor.

23.

Using the rule-of-thumb method, determine the amount of fluid needed to cement a 9 7/8” hole with 7 “ casing over a 5,000-foot interval. A. 255 cu ft. B. 1,428 cu ft. C. 1,714 cu ft. D. 14,280 cu ft.

24. The casing string most often cemented from the shoe to the surface is the— A. intermediate string. B. oil string. C. surface string. D. conductor pipe. Sections: Considerations after Cementing and Oilwell Cement and Cement Additives 25.

Operators who bleed off some of the pressure on the casing following pump shutdown gain some desirable results, including— A. positive or negative feedback on holding condition of back-pressure valve in the string. B. possibility of immediate nippling-up. C. minimized risk of loosening cement bond after cement hardens. D. all of the above

26.

Since regulations leave waiting-on-cement (WOC) time open when there is a float valve in the string, an operator will probably start drilling out— A. immediately after a reasonable WOC time expires. B. about 8 hours after WOC time starts. C. about 12 hours after WOC time starts. D. at his own discretion.

27.

WOC time generally begins— A. when surface returns are seen around the surface casing. B. after the cement plug is drilled out. C. at a time designated by the operator. D. when the plug bumps the float collar.


Ref: ADMOD.DOC




A problem concerning the height of cement in the annulus may best be solved, shortly after the slurry is displaced, by conducting— A. bond logs. B. radioactive tracers. C. temperature surveys. D. any of the above

29.

An operator desiring to lower the density of cement slurry may do so by adding all of the following except— A. perlite. B. bentonite. C. barite. D. salt.

30.

A temperature survey may be used to determine the top of cement because— A. cement absorbs heat as it sets. B. the empty spaces above the cement are of a higher temperature than the cement. C. cement gives off heat as it sets. D. of none of the above.

31.

Cement additives may be used to— A. increase setting time. B. decrease setting time. C. increase density. D. all of the above

Section: Secondary Cementing 32.

Plug-back cementing is used for each of the following except— A. repairing leaks in casing. B. sealing off a dry hole. C. shutting off depleted formation so that production can be taken from a higher zone. D. repairing primary cementing failure.

33.

The packer squeeze technique differs from the bradenhead technique in that— A. high-squeeze pressure may be achieved. B. greater control over squeeze operation is available. C. the zone to be treated is not isolated from the surface. D. tubing and casing pressures are not tested for leaks.

34.

Squeeze cementing is considered a method of— A. primary cementing. B. plug-back cementing. C. secondary cementing. D. none of the above.





It is generally not necessary to move the pipe (by either rotation or reciprocation) when setting a cement plug. A. B.

True False


Personal Notes Use this section for making notes and sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches





Personal Notes

notes

sketches




Ref: ADMOD.DOC




Revision: 02

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Ref: ADMOD.DOC




Revision: 02


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4. Assistant Driller Module Trainee Booklet

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