Assistant Driller Assessor Guide

Assistant Driller eOJT Assessor’s Guide

Training Procedures Section 1 Training Procedures

Assistant Driller OJT Module Training Procedures Objectives Upon completion of this module, the participant should be able to: 1. demonstrate a clear understanding of the role and responsibilities of Transocean assistant drillers, and 2. perform basic assistant driller tasks safely and competently. Training Procedure Completing the assistant driller module should take about thirteen working weeks, depending on the effort put in. The mandatory task list is the basic tool for recording progress, and each item on the list shall be completed before participants can receive a module certificate. The task list evaluation guide in this assessor’s guide is to help you assess the competence of the participants. Some flexibility is permitted, but you must be thoroughly satisfied that the level of skill and knowledge demonstrated by each participant is consistent with the objectives of this OJT module. Only when you believe that a participant has truly achieved the required skill level and knowledge required by each task, should you sign off on it. The suppporting self-study DVD-ROMs, CD-ROMs, books and workbook questions helps participants understand the tasks. The use of these tools is voluntary. Many training participants will find the tools very helpful in providing fundamental knowledge. You can customize the task list according to the requirements of your particular rig. A blank section is provided for you to add additional tasks you feel are important and want participants to perform. You cannot, however, delete tasks, except where they do not apply to your rig. When the participant completes the task list requirements to your satisfaction, and has successfully completed the computergenerated final test, complete and sign a completion notification form (CNF). Also, ensure that the participant fills in the employee comments section. Then, forward the completed and signed CNF to the regional training center. After receiving the CNF, the training center will complete the participant in the Training Management System. The RSTC will then be able to print a module certificate from the Training Management System. Keep the completed task list on file at each participant’s assigned location. The training file shall be transferred when the participant is transferred.

Rev. 02: January 2005

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Section 2 Task List Evaluation Guide

Task List Evaluation Guide

Assistant Driller Task List Evaluation Guide 1.

Describe how the OJT system works and the supervisor’s role in it. Ask participants to explain the OJT system and how it works. The OJT task list is the core of the training system and reference tools are provided to support the hands-on-training if needed. Supervisors play a key role implementing the training. Supervisors are, as part of their ongoing duties, expected to continue providing guidance and on-the-job training to crew members. They monitor and track the progress of the participants with the help of the task list and appraisal guidelines. They are required to teach and instruct the participants. The OJT competency based system is a self-paced program that trains and measures a participant’s skills and knowledge required in each job category or function. The OJT system is a tool for self-development and career progression. It is designed to ensure that the participant is exposed to a majority of the important occurrences relative to the particular job category or function. It consists of a combination of practical work on the rig and self-study. The mandatory tasks are supported with optional training tools that consist of books, manuals, interactive CD-ROMs, and films on DVD-ROMs. Open-book questions are also provided. Instruction and evaluation of the training participants is the responsibility of the immediate supervisor(s). Participants must demonstrate competency in each task before the supervisor signs it off as completed. This method of assessment ensures a demonstrated ability from participants as they gain new knowledge and skills required for the job function. All tasks must be completed to the supervisor(s) satisfaction before they are eligible to complete a final computergenerated test. Ask questions such as: “What are the components of the OJT system and how is it implemented?” Module booklets, reference books, and reference software are procured in the conventional manner referencing the order list on the Corporate Training website or EMPAC/TOPS Houston Procurement website. The supervisor gives the module booklet to the participant who follows the self-paced task list. Besides hands-on learning, training tools are also used to help the participant gain knowledge on the tasks. Supervisors assess participants as they perform the tasks. The OJT Modules Assessor’s Guide is provided to guide the supervisors through the assessment process as required. All tasks must be completed to the supervisor’s satisfaction. Workbook questions also support the tasks. The supervisor should evaluate the workbook answers. The participant must successfully complete the final computer-generated test after all other training requirements are completed. The completion notification form (CNF) is completed by the supervisor and participant and sent to the regional training center for recording in the training database (TMS). A certificate is issued to the participant. When the participant is transferred to another location, the task list / training records are also transferred.

2.

Explain the energy isolation system as it applies to the assistant driller. Ask participants to explain energy isolation and give examples of equipment requiring isolation as it applies to the assistant driller’s work. Some examples of this equipment may include the drawworks, casing stabbing board hoisting system, choke manifold, and slick line unit. Prior to working on any equipment, all energy sources will be isolated, and any stored energy will be released. The OIM will authorize individuals as competent persons for each type of energy isolation. A permit to work is an additional requirement when an isolation certificate is issued for maintenance or repair of a system or component containing energy. In some cases, the task is only hazardous because of the energy. When effective isolation is achieved, the task may no longer be hazardous and, hence, the isolation process controls the risks associated with the energy. The person performing the work will confirm the equipment, inoperative by physically trying to operate it. This is done to ensure that prior to working on the equipment it is rendered safe by releasing any trapped energy (electrical, mechanical, hydraulic, thermal, or pneumatic) and that the equipment cannot be energized at either local or remote locations.

3.

Explain the role of the assistant driller during such emergencies as H S, hydrocarbon discharge, fire, man 2 overboard, and abandon rig. Ask participants to explain their role is during emergency situations. Participants must ensure that the assistant driller’s subordinates are following the procedures in the emergency response plan.


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Assistant Driller Task List Evaluation Guide 4.

Show how to conduct a THINK drill at the site where the task will be performed. Observe participants conducting a THINK drill at the work site. They should plan, inspect, identify, communicate and control. Participants should ensure that all concerned parties are involved, encourage input from all personnel concerned, and incorporate suggestions into the work plan. They should also ensure that all safety issues are addressed, all contingency planning is communicated, and key personnel are identified to the group. Participants should discuss the scope of the work, the hazards, and specific procedures to be followed for the job. Communication tools such as sketches, drawings, and manuals help to clearly convey the task strategy. Reference HS&E Manual 9.30000.

5.

Explain the zone classification system on your rig. Ask the participants to describe the zone classification system on the rig. They should show the various zones on the rig using the operation’s manual drawings. Ask questions such as: “What do zones 0, 1, 2, and safe area stand for?” Zone 0 is an area where an explosive air-gas environment is present at all times such as inside a fuel tank. Zone 1 is an area where an explosive air-gas environment may be present during normal operations. Zone 2 is an area where an explosive air-gas environment is present only in abnormal circumstances and, if present, would be only for a short duration. A safe area is an area where an explosive gas-air mixture should not be present. “What precautions should be taken when installing or using equipment in zoned areas?” Ensure that the equipment being installed or used will not provide a source of ignition and is compliant with the zone classification. The equipment needs to be explosion-proof, intrinsically safe, or otherwise protected.

6.

Show how to communicate and work with other departments and third-party personnel. Participants should demonstrate how to establish and maintain good liaison with personnel in such departments as electrical, mechanical, subsea, and marine. They must also ensure concerted action and cooperation while working in a professional manner with third-party company personnel, such as mud loggers, cementers, wireline operators, testing operators, and casing crews.

7.

Assist the driller in filling out the IADC drilling report. Following the driller’s instructions, participants should fill in sections of the GRS and IADC report (electronic or handwritten) such as BHA components, rotating and pumping hours, and washpipe running hours in the comments section.

8.

Explain the assistant driller’s role in managing crews’ productivity and drill floor housekeeping. Ask the participant about the planned drill crews’ work for the day. They should have all jobs organized and working smoothly. Check that the drill floor is clean, tidy, and hazard-free. If it is not, participants must direct the drill crew to put it in order. Putting the floor in order may involve removing unnecessary items from the floor, checking and cleaning various tools and equipment, and washing down the floor.

9.

Explain and show how to align the standpipe manifold and the choke manifold for testing, cementing, drilling, and reverse circulating. Ask participants explain and show how to line up the manifolds for operations such as reverse circulating, cementing, and pumping through the kill line.

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Assistant Driller Task List Evaluation Guide 10. Show how to maintain the fastline guide system on the drilling line. Ask participants to check the drilling line guide system and stabilizer for wear and to describe potential problems. For example, they should check for worn rollers; and they should make sure that the guide system wires and guide system pulleys are in good shape. Also, they should check all bolts, sheaves, bearings, and grease fittings for wear, and ensure that they are in place and operating properly. Further, they should remove excess grease and wireline tar. Reference Drilling Line Care and Maintenance book 9.11000 and DVD-ROM 20.0228. 11. Show how to inspect and change drawworks turnback rollers. Participants should inspect the turnback rollers and check for roller and shaft wear. They should make sure the bearings are in good condition, and they should check the kick-back plate inside the drum for wear. The plate fasteners should be in good repair. Participants should also know how to replace or invert rollers, change bearings and shaft, and maintain rollers in working condition. Reference Drilling Line Care and Maintenance book 9.11000 and DVD-ROM 20.0228. 12. Show how to adjust the drawworks brake band equalizing bar or calibrate disc brake. Observe participants adjusting the brake band equalizing bar or measuring and calibrating the disc brake. Ensure that the traveling block is secured. They should identify all fittings to check on the disc brake arrangement. For a band brand setup, ensure that both sides of the bar have equal gaps. Participants should ask the driller for confirmation of 45-degree brake arm angle and then set the jam nuts. They should adjust the kickback rollers and look for broken grease lines and fittings. 13. Show how to adjust and reset the crown block saver (Crown-O-Matic) or how to adjust and reset floorsavers, if applicable. Observe participants adjusting and resetting the Crown-O-Matic. It should slide smoothly. They should set the Crown-OMatic for tripping to prevent the traveling block from hitting the crown block. Then, they should set it for drilling to prevent damaging the rotary hose. Participants must ensure that the driller function-tests the crown block saver after the reset. On newer rigs, encoders installed on spears of main shafts of drawworks for crownsaver should be checked. Rigs with crownsavers running off of proximity switches mounted on the derrick track should be check for block height calibration. Reference DVD-ROM 20.0803. 14. Show how to visually inspect drilling line. Ask participants to visually inspect the drilling line. They should be able to identify correct spooling on the drawworks drum, and wear at high-wear points. They should also be able to differentiate between normal and excessive wear. Participants should also look for broken or stretched wires, flattened wire, wickers, and for internal and external rust. Reference Drilling Line Care and Maintenance book 9.11000 and DVD-ROM 20.0227.


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Assistant Driller Task List Evaluation Guide 15. Explain and show how to calculate drilling line ton-miles (tonne-kilometres) while drilling and/or tripping and how to use this information. Ask participants to explain stress points on the drilling line and the importance of avoiding these points. They should describe how many feet to cut and maximum ton-miles per foot. Ask participants to calculate the tonmiles (megajoules or tonne-kilometres) for the drilling line using a computer, calculator, or tables. The drilling line is an expendable working machine with intricate moving parts. It requires proper monitoring, care, and maintenance. A good cutoff program using accurate records and routine visual inspection is imperative. Reference Drilling Line Care and Maintenance book 9.11000 and DVD-ROM 20.0230. 16. Explain drilling line slip-and-cut procedures. Ask participants to explain slip-and-cut procedures. Hang off the traveling block. Loosen the deadline anchor bolts. Mark the line. Reverse the drawworks to unspool the line. Cut the line using proper equipment and PPE (especially goggles). Take precautions such as covering the cutter with rags to prevent splinters from flying. Prepare the end of the line by removing the grease. Fasten the socket and spool the line carefully by maintaining the tension on the line. No one should be in or near the drawworks when it is being rotated. The cut line should be measured to confirm that the proper amount of line was cut off. Also need to follow rig specific procedures. Reference IADC Drilling Manual 10.10010 and DVD-ROM 20.0229. 17. Explain how to identify washouts in drill string components. Participants should be able to identify the slip area on the drill pipe body as being the most common area for washouts to occur. They should also be able to identify the lower box thread area on drill collars and tool joint connection on drill pipe as the most common region for washouts on these tubulars. Reference IADC Drilling Manual 10.10010. 18. Show how to prepare BHA sheets and pipe tally. Check a BHA sheet and a pipe tally sheet completed by participants. Comment on any deficiencies and make sure that they fully understand the correct procedure. Reference IADC Drilling Manual 10.10010. 19. Explain and show how to prepare and fill out a trip sheet. Check a trip sheet completed by participants. Comment on any deficiencies and make sure that they fully understand the correct procedure. Reference Practical Well Control book 2.80040 and CD-ROM 61.10160. 20. Show how to use a gauge ring for typical bits and stabilizers used on your rig. Observe participants gauging a bit or a stabilizer. Make sure that they follow the proper procedures for measuring and calculating the gauge. They should explain why the bit and stabilizers are gauged both before and after they are run.

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Assistant Driller Task List Evaluation Guide 21. Show how to check for bit wear and assist with dull bit grading for fixed cutter and roller cone bits. Ask participants to assist the driller in grading a used bit. The IADC standard grading system must be used. They should identify specific wear areas on the bit. Reference IADC Drilling Manual 10.10010. 22. Show how to install, redress, and remove a bit sub float valve. Observe participants redressing a float valve (flapper or plunger type). Ensure that the valve, valve seat, spring, and seals are in good condition. Replace if required. Observe participants installing the bit float valve and Totco ring. Ask them to describe the consequences of installing a float valve upside down. Installing the float upside down will not allow normal circulation. To remedy the problem, the drill stem will have to be pulled, causing rig downtime and loss of revenue. The corresponding Totco ring must be installed in proper position. Ask participants to explain the purpose of a float valve. It prevents backflow and nozzle plugging, and helps prevent shallow gas from entering the drill stem. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 23. Show how to install and remove jets in typical bits. Observe participants installing and removing jet nozzles. O-ring seals should be lubricated and in place. They should explain the methods of fitting nozzles in bits manufactured by Hughes, DBS Security, Reed, and Smith, as well as other brands of bits used on the rig, if applicable. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 24. Show how to supervise a BHA handling operation on the drill floor. Observe participants supervising the drilling crew during a round trip. They should supervise a crew making up, running in, pulling out, and breaking and laying out a typical BHA. Participants should know how to properly handle downhole motors, shock subs, drilling jars, accelerators, stabilizers, and crossovers. They should be able to tell the drill crew where to properly place the tongs, backup snub lines, and dog collars. Also, they should be able to instruct the crew in the proper way to set and remove the slips. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 25. Identify and explain the use of typical fishing tools used on your rig. Participants should identify and explain the function of a rig’s fishing tools, including such tools as the overshot, spear, taper tap, junk basket, reverse circulation junk basket, fishing magnet, and mill. Participants should be aware of the need to accurately measure various lengths, diameters, and depths of the fishing tools, fishing string, fish, and borehole. They should make a drawing of a typical fishing tool and explain why it is necessary to have an accurate sketch of a fishing assembly. Reference Open-Hole Fishing book 2.30230. 26. Explain and demonstrate how to dress an overshot. Ask participants to explain and demonstrate how to dress an overshot. They should identify the parts needed to make up an overshot including such parts as spiral and basket grapples, seals, control ring, bowl, extension, and top sub. Reference Open-Hole Fishing book 2.30230.


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Assistant Driller Task List Evaluation Guide 27. Show how to identify and measure typical downhole tools and tubulars (including collars, stabilizers, jars, subs, crossovers, and drill bits). Ask participants to identify a BHA drilling assembly and measure downhole tools and tubulars making up the assembly. They should be able to identify the size and type of connection and check the condition of the shoulders and threads. The length, OD, ID, fishneck, and serial number of each BHA component must be measured and recorded. They should be able to log this information and make relevant drawings of it. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 28. Show how to calculate drill string capacity, annular capacity, bit depth at any given time, and the number of stands from surface to shoe, surface to bottom, and bottom to shoe. During routine drilling, ask participants to calculate the current drill string and annular capacities. The number of stands from surface to shoe, surface to bottom, and bottom to shoe should also be explained. Reference IADC Drilling Manual 10.10010. 29. Explain and show how to calculate drilling line ton miles (tonne kilometres) while running casing and how to use this information. Give participants a casing job checklist to follow and observe them preparing the drill floor for a casing job. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 30. Explain and demonstrate a wear bushing retrieval operation. Ask participants how to retrieve the wear bushing. They should calculate landing point and running tool positions in stack. They should be able to make up the running tool and retrieve the wear bushing. Follow the equipment specific procedure for setting wear bushing (J-slot type, shear pin type or cam actuated). 31. Show how to make up a casing shoe track. Observe the participant making up the casing shoe, float collar or landing collar. Clean the threads, screw it on, back it off, mix and apply thread-locking compound, make up, and torque as required. The participant should also explain multistage cementing devices and procedures. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 32. Explain why and show how to test the shoe and float collar while running casing. Ask participants to explain why and how the casing shoe and float collar are tested. To ensure circulation and proper functioning of the nonreturn valve. Observe them rigging up and testing the shoe and float collar on the rig floor. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 33. Show how to change power tong heads and tong dies. Ask participants to explain and show how to change the casing power tong heads and tong dies. They should be able to identify different jaw sizes, and show how to shut down the tong power unit.

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Assistant Driller Task List Evaluation Guide 34. Explain how to dress and install a cementing head, secure high-pressure Chiksan lines or hose, and perform a pressure test. Observe participants dressing a cementing head, rigging it up, and aligning the valves. Participants should identify and load the plugs under direct supervision of tool hand and explain how the head works. They should explain the consequences of loading the head the wrong way. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 35. Show how to perform daily checks on well-control equipment such as IBOP and crossover(s), choke manifold, and accumulator unit. Following the rig-specific daily checklist, observe participants checking well-control equipment. The IBOP must be in the open position with the handle readily available. Crossovers for all anticipated tubulars must be on the rig floor. Participants must check choke manifold alignment, pressure gauges, and the four-way valve position on the accumulator unit. Also check the accumulator fluid level and position of valves on the choke and kill lines on a surface stack. Reference Practical Well Control book 2.80040. 36. Explain Transocean shut-in procedures while drilling. Ask participants to explain shut-in procedures while drilling. Reference Transocean Well Control Manual, Practical Well Control book 2.80040, and CD-ROM 61.10160. 37. Explain Transocean shut-in procedures while tripping. Ask participants to explain shut-in procedures while tripping. Reference Transocean Well Control Manual, Practical Well Control book 2.80040, and CD-ROM 61.10160. 38. Explain the diverter control system and diverter procedures. Ask participants to explain the diverter procedures for your rig, and explain when and why it’s used. They should explain an show valve sequencing, the use of port or starboard overboard lines, and reading and adjusting pressures. Reference Blowout Prevention book 2.30330, DVD-ROM 20.0407, and CD-ROM 61.10160. 39. Explain and show how to change and surface BOP rams, if applicable. Ask participants to describe the safety precautions to be taken when changing surface stack BOP rams and performing routine service. Use a work permit, be aware of high pressure, use climbing PPE, practice safe lifting, and communicate effectively. Observe participants changing the rams. They should know how to open and close bonnets, handle rams, and check bonnet seals. Ask about the purpose of the emergency packing seal and how to determine seal leakage on a surface stack. Reference Practical Well Control book 2.80040 and CD-ROM 61.10140.


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Assistant Driller Task List Evaluation Guide 40. Explain how to change a surface stack annular BOP packing element, if applicable. Ask participants how to change the surface stack annular BOP element and the safety precautions to be taken. Use a work permit, safe climbing techniques, and proper bell nipple and flow-line handling (on a surface stack). They should be able to explain how to bleed pressure, remove the cap, refit the element, and put the cap back on following manufacturer recommendations. For subsea operations, the participant should assist a subsea engineer in servicing an annular BOP. Reference Practical Well Control book 2.80040, Subsea Blowout Preventers and Marine Riser Systems book 2.30410, and CD-ROM 61.10040. 41. Explain and show how to run and retrieve (or nipple up and nipple down) the BOP stack on your rig. Ask participants to explain the steps to nipple up and nipple down a surface stack, if applicable. They should describe precautions to take when working over water, disconnecting the accumulator and rams/choke/kill control lines, removing the bell nipple and flow line, preparing hoisting equipment and slings, removing bolts or clamps, and picking up the stack. Observe participants during a nipple-up or nipple-down operation. They should show how to change out a ring gasket. For subsurface stacks, they should show how to secure control/pod lines, install bulls-eye, guide lines if used, operation of BOP handling equipment and carriers, and use of spider beams. Reference Practical Well Control book 2.80040. 42. Show how to do a complete BOP and choke manifold low and high-pressure test. Participants should perform assistant driller duties during a complete BOP and choke manifold pressure test. They should prepare the testing equipment (test plug/cup tester), and communicate clearly with the driller. Participants should explain the sequence for testing. Also, they should explain the purpose of low-pressure and high-pressure tests. Further, they should know how to use testing equipment. They should explain how to swap pods and carry out function test, how to read flow meters and how to verify function and any safety related issues with testing. Review the written test procedures with participants. Reference Practical Well Control book 2.80040 and CD-ROM 61.10010. 43. Show how to do a complete IBOP, standpipe manifold, top drive, and pump room manifold low and high-pressure test. Participants should perform assistant driller duties during a complete IBOP, top drive and standpipe manifold pressure test. The sequence for filling the standpipe and testing the IBOP valves should be explained. Explain the purpose of the low-pressure and high-pressure tests. They should know to insure stand pipe is not lined up to mud pump unless bleed off is open. Reference Practical Well Control book 2.80040 and CD-ROM 61.10110. 44. Show how to calculate the space out. Participants should show the recorded distances between all ram and annular preventers and the RKB. On surface stacks, they should physically measure it. They should give examples of different tools that will need to be spaced out when running them in BOP stack.

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Assistant Driller Task List Evaluation Guide 45. Explain accumulator system operation including nitrogen precharge system and calculation of useable fluid, and assist with routine maintenance. Participants should thoroughly explain the operation of an accumulator system. They should be able to describe the three pressures (manifold, accumulator, and annular). Expect a clear explanation of the function of four-way valves, the bypass valve, air and electric pumps, annular regulator, and transducer operation. The participant must assist the subsea engineer or mechanic in routine maintenance of the accumulator unit. Ask about the system fluid, how to add it, how to read the sight glass, and how to identify leaks. Reference Practical Well Control book 2.80040 and CD-ROM 61.10010. 46. Describe the assistant driller’s role in the Preventative Maintenance System. Ask participants how the preventive maintenance system works. They should be able to liaison with the maintenance department supervisors and demonstrate organization of the drilling crew for fulfilling the drilling equipment PMS task list requirements. They should describe how the computer-aided maintenance management system is used. 47. Visually inspect and identify typical problems associated with drawworks. Observe participants performing a visual inspection of the drawworks. Check the flow path of cooling water. Check cooling water temperature and measure flow rates (using a stop watch and container). Identify air leaks in the low drum, high drum, cathead friction clutches, and quick-release valves. Check condition of drawworks transmission linkage, chains, sprockets, discs brakes and active heave components if applicable. Reference DVD-ROM 20.0803. 48. Explain how to change out the swivel washpipe and show how to redress the spare. Observe participants rebuilding the swivel washpipe. Ensure proper inspection, cleaning, and lubrication. Check placement of packing and spacer ring assemblies into the packing housing, and O-ring fitting. Ask participants to explain the proce-dure for unscrewing the packing housing from the body, the ring nut from the goose-neck, and removing the assembly through the opening of the swivel housing. Ask how often the washpipe should be changed and how running hours are recorded. Record running hours on the IADC drilling report. Where used, follow rig specifics on installing and rebuilding mechanical packing. 49. Show how to maintain and repair a standpipe gate valve. Observe disassembling, inspecting, and replacing worn parts in a standpipe gate valve. Lubricate stem packing, valve-stem timing, bonnet seals, and O-ring. Replace gates and seats. This task must be performed under close supervision. 50. Explain and assist in maintaining or repairing a choke manifold gate valve. Observe disassembling, inspecting, and replacing of worn parts in a choke manifold gate valve. Replace and lubricate bonnet seals, stem packing, O-rings, and the gate and seat. Check valve-stem timing. This task must be performed under close supervision. 51. Explain maintaining or repairing of a manual and a remote operated choke. Ask participants to explain disassembling, inspecting, and replacing worn parts in a manual and/or remote-operated choke valve. This task must be performed under close supervision. Participants should explain the purpose and function of the choke.


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Assistant Driller Task List Evaluation Guide 52. Show how to service and repair the hydraulic pressure load cell on the standpipe. Observe inspecting and replacing the diaphragm (bladder) in the standpipe manifold’s load cell. Rig specific procedures must be referenced and followed. Ensure the system is bled down and that no pressure or fluid is in the manifold. After replacing the bladder, pump new hydraulic fluid, and pre-energize the load cell. Purge the system. This task must be performed under close supervision. 53. Explain and show how to visually inspect the deadline anchor and the load cell. Observe participants visually inspecting the deadline anchor and load cell. Check tie-down bolts and for free motion of pin and gap. Check to ensure that a 1/2- to 5/8-inch (13- to 16-millimetre) gap exists on the load cell. Check condition of the grease fittings and lubricate as required. Ask for an explanation of how the deadline anchor works. The deadline anchor is firmly attached to the rig structure or other firm support where it provides a strong anchoring point for the dead end of the drilling line. In addition to its anchoring abilities, the deadline anchor must also allow the dead end of the drilling line to flex without stressing the line as it flexes with the addition and subtraction of weight supported by the drilling line. They should explain how electronic load cells work, where applicable. Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210. 54. Explain and show how to replace cathead lines or E-Z torque lines and explain safety precautions, where applicable. Observe participants replacing a cathead line or E-Z torque line following safety pre-cautions such as locking the drawworks, isolating the air-to-friction clutch, and checking the condition of the termination point. Care should be taken when respooling the line. 55. Visually inspect and identify typical problems associated with automated pipe-handling equipment such as pipe racker, Iron Roughneck, conveyor, hydraulic/pneumatic finger board, and pipe spinner. Observe participants inspecting the automated pipe-handling equipment including the Iron Roughneck, pipe racker, conveyor, hydraulic/pneumatic finger board and pipe spinner. Visually check for hydraulic and pneumatic leaks, make sure the tracks are clear, and check for pipe-drive roller wear and loose fasteners. Also, participants should function test each component after inspection. 56. Visually inspect and identify typical problems with the crown block and traveling block assemblies including block retract systems where applicable. Observe participants visually inspecting the crown block and traveling block assemblies. Check for items such as bearing wear, sheave groove wear, excessive tar buildup, grease, loose fasteners, and condition of sheave guards. Reference IADC Drilling Manual 10.10010. 57. Visually inspect and identify typical problems with the top drive or kelly assembly. Observe participants visually inspecting the top drive or kelly assembly. Check for oil and air leakage, loose fasteners, tie wires, pipe handler, doll/carriage rollers and stops, grease lines, sharp threads on saver subs, washpipe condition and running hours, and general condition of the rotary hose and hose bundles. 58. Visually inspect and identify typical problems with mud treatment equipment. Observe participants visually inspecting mud treatment equipment. Routine inspection includes checking cuttings recovery equipment, underflow in the hydrocyclones, the distance of flow on the shaker screens, the condition of the screens on the mud cleaner, drilling fluid leakage, loose fasteners, and overall general working condition. They should be able to follow up on deficiencies pointed out by the derrickhand or floorhand.

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Assistant Driller Task List Evaluation Guide 59. Visually inspect and identify typical problems with mud pumps and show how to replace expendable parts. Observe participants visually inspecting mud pumps. Check for items such as cooling water flow, abnormal sounds, and overall general working condition. They should be able to follow up on deficiencies pointed out by the derrickhand. Reference IADC Drilling Manual 10.10010. 60. Explain and show how to inspect and repair drill string full-opening and nonreturn valves. Ask participants to explain how these valves work, They should know how to disassemble and redress a full-opening safety valve and a nonreturn (Gray) valve or DIV. Function test and pressure test. 61. Show how to change the mud pump’s pulsation dampener bladder and explain the use of the oxygen tester, where applicable. Observe participants changing the pulsation dampener’s bladder in a mud pump. After changing it, they should be able to properly use an oxygen tester and explain that it is important that no air be in the dampener because of the possibility of fire when using oil muds or mud with flammable materials in it. Check the work permit and isolation procedure. If the participants’ rig is equipped with a bladderless pulsation dampener, they should explain the theory of operations. 62. Show how to prepare the drill floor for a typical completion job. Give participants a completion job checklist and oversee preparation of the drill floor before running the completion string. 63. Explain running and retrieving procedures for a hang-off assembly or RTTS. Ask participants to explain the rig specific running and retrieving procedures for a hang-off assembly or RTTS. The drill string should not be in open hole, make up a hang-off assembly (Acme thread should be run chain-tong tight), Gray valve installed one stand below hang-off joint, run in, land with the compensator open, and back out. Ask when a hang-off should be carried out. When preparing for rough weather and possible BOP unlatch. 64. Explain and show how to supervise the drill floor for running or retrieving the riser system. Ask participants to describe the drill floor operational and safety procedures to be followed when running or retrieving riser. All necessary riser running equipment should be in place before the job starts. Pay special attention to correct makeup. Reference CD-ROM 61.10050. 65. Explain and show how to supervise the moon pool area when the BOP stack and riser system are being run or retrieved. Ask participants to explain and show the AD’s role at the moon pool area during BOP and riser running-and-retrieval operations from the beginning to landing. All necessary riser running equipment should be in place before the job starts. Follow the procedures for working over water. Permit to work must be in place. Standby boat should remain at close quarters and participants should maintain radio communication with boat, control room, and rig floor. Observe the operation of guideline and podline winches, podline or mux line. Reference CD-ROM 61.10050.


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Assistant Driller Task List Evaluation Guide 66. Assist in routine maintenance on the riser and guideline tensioner systems or hydraulic riser tensioner cylinders and explain how they work. Ask for a complete explanation of how the riser and guideline tensioner systems or hydraulic riser tensioner work. Observe participants assisting the subsea engineer in lubrication and inspection of the riser and guideline tensioner system. They should assist with slipping and cutting of the riser tensioner lines and demonstrate how to pressure up the APVs and line up the manifold. 67. Visually inspect and identify typical problems of the drill string motion compensator. Observe participants visually inspecting the motion compensator system. Check for hydraulic leaks, contact between moving parts, and overall working condition. Watch for midstroke positioning. Check APV pressure. Participants should be able to identify and correct deficiencies. Reference the rig specific procedure. 68. Explain and show how to supervise moon pool area operations when preparing and running a permanent and/ or temporary guide base, including monitoring of subsea TV cameras or ROV. Ask participants to explain and show the AD’s role in the moon pool area when running a permanent and temporary guide base. All necessary running equipment should be in place before the job starts. Follow the procedures for working over water. Permit to work must be in place. Standby boat should remain at close quarters and participants should maintain radio communication with boat, control room, and rig floor. Observe the operation of running tools and tubulars and ensure that the subsea cameras (or ROV) are in place and properly functioning. 69. Explain the maximum operating weather limits for drilling, tripping, logging, and other critical operations. Participants should be aware of the restrictions weather can impose on drilling, tripping, logging, and other operations on their rig. 70. Explain the function and show how to use drilling instrumentation at the driller’s console on your rig. Observe participants at the driller’s console and ask them to name and explain the function of each instrument and control on the console. 71. Operate the driller’s drawworks controls during a routine trip in a cased-hole section for a limited period and under close supervision. Under close supervision of the driller, for a limited period, and in a cased-hole section, participants should operate the drawworks and driller’s controls on a routine trip. This operation should include use of the auxiliary brake, low- and highdrum clutches, transmission gears, and inertia back brake. Participants must observe and monitor all instruments and equipment controls. They should show an understanding of the hazards involved in mishandling this equipment. Reference DVD-ROM 20.0803. 72. Operate the driller’s drawworks controls during routine drilling for a limited period and under close supervision. Under close supervision of the driller, and for limited periods, participants should operate the drawworks and driller’s controls during routine drilling operations. They must observe and monitor all instruments and equip-ment controls. They should show an understanding of the hazards involved in mishandling this equipment.

Page: 2.12


Assistant Driller Task List Evaluation Guide 73. Operate the driller’s drawworks control while running casing inside cased hole, under close supervision and for a limited period. Under close supervision of the driller, participants should, for limited periods, operate the drawworks and driller’s controls during routine casing operations. They must observe and closely monitor all instruments and equipment controls. They should show an understanding of the hazards involved in mishandling this equipment. Reference DVD-ROM 20.0803. 74. Show how to space out and shut in the well during a kick drill. Participants should show how to properly space out the drill string and shut in the well during a kick drill. Stop rotation, raise string to the hang-off position, stop the pumps and flow check, simulate closing of the annular and opening of choke line failsafe valves, simulate notification of the man in charge, check the space out and simulate closing of hang-off pipe rams. 75. Explain the overall functioning of top drive system and system loadpath during drilling. Participants should describe the basic principle of a top drive drilling system. The description should include the efficient method of rotating the drillstring and handling pipe stands in 90’ lengths and the ability to trip, circulate, rotate and run casing; as well as provision to forward or backream to reduce the risk of stuck pipe. Ask participants to describe the top drive system load path. The systems loadpath during drilling is as follows; the TDS connects to the travelling equipment at the swivel, mainshaft is attached to the swivel and passes directly through gearbox or transmission with electric drilling motor located along side the shaft. IBOP valves are connected to the end of the mainshaft, this assures a direct path from the drill string thru the mainshaft to the swivel. 76. Explain and show the general arrangement of the top drive pipe handler. Participants should explain the general arrangement of the top drive pipehandler on your rig. For example, the pipe handler consists of a link adapter, torque arrestors and rotating head, torque wrench and elevator assembly. The link adapter is captivated around the mainshaft just above the load collar on main shaft. Torque arrestors keep the link adapter up off the shoulder while drilling. The torque arrestors are mounted between the link adapter plate and the rotating head. The link adapter rests on top of the plate and the rotating head bolts onto the gear case. The elevator is hung from a pair of links allowing it to swing out to pick up pipe when the linktilt is actuated. When the elevator has the extra weight of the drill pipe in it, the Link Adapter drops down onto the load collar directing the load up thru the mainshaft to the swivel. The torque wrench assembly is independently hung from the rotating head. 77. Explain which top drive system configuration is on this specific drilling unit. Ask participants to explain the rig specific top drive or power swivel configuration (i.e Varco, National, M/H, Can Rig). Example:

Varco models: TDS-3 Single speed gearbox, 5.33:1 gear ratio. TDS-4 2 speed gearbox, Low 7.95:1, High 5.08:1 gear ratio. TDS-5 Single speed gearbox, 6.67:1 gear ratio. TDS-6 2 motor with 5.33:1 gear ratio. Each of the above is available in following versions: H - High Torque Drilling Motor / Motors. S - Integrated top drive Swivel (not available in TDS-5). E - Pipe Handler using an Ezy Break connection.


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Assistant Driller Task List Evaluation Guide 78. Describe the maximum continuous torque in Ft/Lbs on the rig specific top drive. Example: TDS-3 Motor Type GE752 Shunt GE752 HiTorq Shunt GE752 Series GE752 HiToq Series EMD M89 VTS Series

TDS-4

TDS-5

26,400

Hi 24,800

Low 38,700

33,000

31,000 27,800

Hi 29,100 Hi 26,100

Low 45,500 Low 40,900

38,700 34,800

34,700

Hi 32,500

Low 50,900

43,300

30,200

Hi 28,300

Low 44,300

37,700

79. Describe the maximum RPM at maximum continuous torque rating on this specific top drive. Example: TDS-3 Motor Type GE752 Shunt GE752 HiTorq Shunt GE752 Series GE752 HiToq Series EMD M89 VTS Series

TDS-4

TDS-5

195

Hi 205

Low 130

155

165 185

Hi 175 Hi 195

Low 110 Low 125

130 150

150

Hi 160

Low 100

125

170

Hi 180

Low 115

135

80. Identify the model of pipe handler fitted to this specific top drive, and the maximum breakout capacity in Ft/Lbs. Example: PH60 - 60,000 Ft/Lbs

PH85 -

85,000 Ft/Lbs

81. Explain and show the operational sequence of pipe handler torque wrench in drilling mode. The participants should describe the sequence of events from activating torque wrench on drillers console. Follow rig specific procedures. An example follows: Sequence – pipe handler raises 2" with torque tube engaging splines on upper IBOP valve, it then receives sequenced pressure to clamp the clamping piston on the box end connection. After the clamping pressure is developed, another sequence valve automatically opens and directs pressure to the torque cylinders. The torque cylinders can rotate up to 25 degrees while developing a maximum torque of either 60,000 or 85,000 Ft/Lbs (according to which model – PH60 or PH85). This entire operation is accomplished by one electrical push button on the driller’s console. 82. Explain and show the operational sequence of pipe handler torque wrench when changing out saver sub and / or IBOP valve. The participants should describe the removal of the first stop on the lifting mechanism of the torque wrench which allows further raising of the torque wrench to space out the clamping piston onto the saver sub. This allows the break out and make up of saver sub as required. The removal of the second stop on the lifting mechanism allows the lower IBOP valve to be broken out or made up as required.

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Assistant Driller Task List Evaluation Guide 83. Demonstrate the operation of the linktilt mechanism. Observe participants functioning the linktilt assembly to the intermediate stop mechanism for assisting the derrickhand in racking or running operations and the intermediate stop release lever to allow pick up of pipe from the mousehole. 84. Demonstrate the actuation of the IBOP valves. Observe participants functioning the upper IBOP valve using control handle on drillers console and the lower IBOP valve thru the torque tube opening activated using the hex key. 85. Demonstrate making a single connection with the top drive on at least 5 occasions, where applicable. Observe participants demonstrating picking up a single from the mousehole using the extended linktilt function, once single clears the floor deactivate linktilt to allow single to come to wellbore. Stab the connection at the floor and lower the top drive allowing the added single to enter the stabbing guide. Make up top drive to single using spin function and torque using motor – use a backup tong to react to torque. IBOP valve to be opened ready to resume pumping operations and the top drive brake set to Auto mode ready for drilling ahead. 86. Demonstrate making and breaking a stand connection with the top drive using the pipe handler on at least 5 occasions. Observe participants having a think drill meeting with all parties involved in operation. They should confirm the derrickhand has his safety harness fitted prior to raising travelling blocks. The participants should demonstrate making a connection by ensuring all torque is removed from drill string prior to setting slips, elevators opened for derrickhand when stand drilled down, string weight set in slips and compensator closed. Mud pumps shut down and IBOP closed after pressure reduces. Break out of the saver sub from the drill pipe using the torque wrench in the pipe handler. Spin out the connection using the drilling motor in reverse. Lift the top drive clear of the drill pipe and activate the linktilt mechanism while travelling aloft to assist the derrickhand with latching stand of pipe. Extend RBS and adjust height, clamp RBS tong on elevated box of drill string. Once elevators are confirmed latched, the stand can be picked clear of deck and stabbed into elevated box connection using RBS stabbing head. Lower the top drive into upper end of stand using derrick camera as an aid. Make up top drive to stand using spin function and torque using motor – use RBS clamp to react to torque. IBOP valve to be opened ready to resume pumping operations and the top drive brake set to Auto mode ready for drilling ahead. Release RBS clamp and retract RBS system. The full string weight can be taken and compensator positioned ready for tagging bottom. 87. Explain the counterbalance system on the top drive. Participants should explain that the counterbalance system prevents damage to the tool joint threads while making or breaking connections with the top drive by a preventative cushioned stroke similar to that provided by a hook. This system is required because a hook may not be present in the drill string or, if it is present, the spring will already be collapsed due to the weight of the top drive system suspended from it. This would produce undesirable forces on the tool joint when stabbing the connection. Generally, the system consists of two hydraulic cylinders and attached hardware, two hydraulic accumulators, and a hydraulic manifold with related plumbing. It is designed for 2000psi of hydraulic pressure maximum. The hydraulic cylinders are connected between the top drive unit and the elevator bail ears of the hook, or directly to the block. These cylinders are connected to the hydraulic accumulators located inside the motor frame of the guide dolly assembly. The accumulators are precharged with nitrogen (900psi) and maintained at a specific pressure setting by the counterbalance manifold located on the guide dolly. This manifold is also the source of all hydraulic power to the accessories and includes the valve that operates the torque wrench portion of the Pipe Handler. When properly adjusted all but 825lbs of the top drive weight is taken by the hydraulic cylinders directly to the hook or block, with the weight being transferred through the swivel bail while the top drive system is disconnected from the drill string. With the hydraulic power unit Off, a piloted check valve isolates the counterbalance circuit. As the top drive saver sub is stabbed into the string, the cylinders retract and the swivel bail moves out of contact with the hook. Hydraulic oil under pressure fills the rod end of the cylinders as they stroke, keeping the weight of the system off the threads. Because the accumulator pressure will decrease slightly as the oil is drawn out of them, some weight will be transferred to the threads. This force can range from 6,000 to 10,000lbs depending on overall system weight and the amount the counterbalance cylinders are retracted. If the oil pressure in the accumulators drops below acceptable levels due to leakage or other reasons, the circuitry in the counterbalance manifold will correct this situation automatically any time the hydraulic power unit is switched On. Rev. 02: January 2005

Page: 2.15

Assistant Driller Task List Evaluation Guide 88. Explain and show the rotating head system on the top drive. The participants should explain and show that the rotating head consists primarily of a stationary flange, that bolts directly to the bottom of the gear case, and a rotating swivel block which the torque arrestors and pipe handler hanger shaft are mounted on. The hydraulic and air lines for the various pipe handler functions (link tilt, torque wrench etc…) connect between their respective solenoid valves and the stationary flange. The fluids travel from the flange to the swivel block using sealed rotating passages (commonly referred to as a fluid slip ring). The standard seven-port head assembly has two hydraulic passages, three pneumatic passages, and two spare passages capable of transferring other pneumatic or hydraulic fluid (all are rated at 2000psi). Additional hoses are used to connect the ports in the swivel block to the corresponding devices (link tilt etc…). The swivel block can, therefore, rotate relative to the flange without twisting or damaging any hoses. The unit can rotate freely or be locked into any of the 24 index positions and will automatically return to the pre-selected position, just like a standard rotary hook. 89. Explain and show the motor cooling system on this specific top drive. The participants should explain and show the motor cooling system fitted to the top drive on this installation. Several motor cooling systems may be installed on the drilling motor assembly, depending on regulatory requirements and customer preference. These systems include: 1.

Local Blower – basic motor cooling system designed to provide local cooling air to the drilling motor, it receives air from 20 feet above the rig floor at the lowest point of the motor’s travel. A heavy construction pressure blower is mounted to the motor. The blower is directly driven by a 15hp explosion proof electrical motor which is connected to the blower with a rigid duct. This design provides highly reliable service with positive ventilation through its normal inlet and spark arrestor protected outlets. It provides a safe, visibly verifiable system that will prevent explosion of flammable gasses or vapours coming from the well bore.

2.

Local Blower with Extended Intake – to comply with certain agency requirements, the minimum intake height must be raised. In order to accomplish this, an extended intake may be specified. This system consists of a standard type local blower with ducting to allow the intake to be mounted on the hook or travelling block with a flexible hose running down to the motor. This raises the minimum intake height to approximately 30 feet above the rig floor.

3.

Derrick Mounted Remote Blower – for applications that cannot be assured of safe cooling air, such as enclosed derricks, an alternative system using an 8 inch diameter flexible duct is fitted. The systems operation is identical to the standard system except the blower motor is a 30hp motor that is mounted at the monkey board level and receives cooling air from outside the derrick walls. The extra horsepower is required to force the air through the duct, which is a heavy construction bulk transfer hose of the type used between offshore supply boats and platforms.

Closed Loop – some regulatory agencies define severely restrictive hazardous areas and consequently require a closed loop cooling system that recirculates cooling air over water cooled heat exchangers. The closed loop system consists of two tube type heat exchangers connected to twin blowers driven by a double-ended AC motor. Ducting passes air out the motor exhaust port to the heat exchangers and back to the blower inlets. The heat exchangers are built from cupro-nickel tubes and headers are proof tested to 250 psi.

Page: 2.16


Assistant Driller Task List Evaluation Guide 90. Explain and show the sequence of actions in the event of string stall during drilling or reaming. Observe the participants during string stall out – shutting down mud pumps if hole packing off, releasing string torque using variac on drillers console, closing and locking drill string compensator. Participant must be able to tell maximum overpull allowed to break string free with given tubulars in the hole. 91. Explain and demonstrate the loadpath components inspection. Participants should reference EMPAC tasks for periodic lubrication and inspection of loadpath components. Reference should be made to pressure test frequency, MPI inspection may be at approximately 6 months or 1500 rotating hours, annual ultrasonic inspection of mainshaft and IBOPs. Note that MPI is usually yearly for heavy lift equipment as per HSE. Reference region specific regulations. 92. Explain and show the top drive alignment cylinder and shipping bracket. Participants should explain the top drive alignment cylinder and shipping bracket functions. For example: the motor alignment cylinder is actuated by the counterbalance system accumulators (some models have own system) and aligns the top drive saver sub with the drill pipe when making a connection. It also reduces potential side loading on the swivel stem by maintaining a vertical orientation for the main shaft, while allowing the motor and housing assembly to float slightly about it’s trunnions with a preload in both directions. This is necessary because the motor housing assembly tends to pivot away from the rails due to it’s centre of gravity being located towards the motor. Participants should be able to explain means of adjusting the motor alignment cylinder using a joint of drill pipe in the slips for alignment with top drive saver sub, adjustment of cylinder rod by ¾ of a turn will move saver sub by approximately ¼”. The shipping bracket should only be removed after the main shaft has been stabbed into the motor housing. If the bracket is removed before hydraulic system is turned on, the motor housing will tend to rotate on it’s trunnions. 93. Explain potential dropped objects and secondary retention system. Participants should reference EMPAC task for top drive inspection and reference Varco or other product manufacturer’s website for secondary retention system. Example: (www.varco.com) Quicklinks, Products & Services, Secondary Retention.


Page: 2.17

Section 3 Workbook Question & Answers

Workbook Questions and Answers

Assistant Driller OJT Module

Workbook Questions and Answers Assistant Driller OJT Module workbook questions are provided to enhance learning on subjects covered by the task list. Workbook questions should be completed as fully as practical. Completing the workbooks does not exempt a participant from the mandatory task list. Participants should achieve a score of 70% or more on each workbook. Where scores fall below 70%, the participant should review the corresponding books, DVD-ROMS, and/or CD-ROMs. The supervisor should coach the participant on any weak points to ensure that material is understood. The following workbooks are provided in this section: Workbook 1. 2. 3. 4. 5. 6. 7. 8. 9.

Applied Mathematics Practical Well Control Kick Data and Gauges Drilling Line Care and Maintenance Drilling a Straight Hole Rig Hydraulics Drilling Muds Casing Cementing


Page Numbers 02–04 05–06 07–12 13–16 17–22 23–27 28–33 34–39 40–43

Page: 3.1

Assistant Driller OJT Module Applied Mathematics - Workbook Answers

1.

2.

3.

What is the capacity of a 121/4-inch 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

12.25 in.

What is the annular capacity of a 171/2 inch hole with 5-inch drill pipe inside? A. 0.2732 bbl/ft B. 0.1968 bbl/ft C. 0.1743 bbl/ft D. 0.0895 bbl/ft

5 in.

What is the volume in barrels of a rectangular mud tank with the following dimensions? 6.5 ft Width = 61/2 ft, Length = 181/4 ft, Height = 10 ft A. 211 bbl B. 316 bbl C. 663 bbl D. 1,048 bbl

17.5 in.

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 3.5 m A. 117 m3 B. 738 bbl C. both A and B D. none of the above

4.3 m

7.8 m

5.

What volume in barrels can the tank hold before fluid passes through the overflow pipe? A. 320 bbl B. 230 bbl C. 110 bbl D. none of the above 10 ft

7.5 ft 10 ft

24 ft

Page: 3.2



6.

What is the area of an oval tank cover in square feet, with the following dimensions? Minor Axis = 4 ft, Major axis = 81/2 ft A. 106.8 ft2 B. 75.4 ft2 C. 49.3 ft2 D. 26.7 ft2

8.5 ft

4 ft

7.

Using the dimensions in question number 6, calculate the volume in barrels, of an oval tank 271/2 feet high? A. 254 bbl B. 162 bbl C. 131 bbl D. 85 bbl

8.

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. 71 bbl C. 110 bbl D. 76 bbl

9.

How much water needs to be added to reduce the mud weight from 10.8 ppg to 9.5 ppg in an 1,800-barrel mud system? A. 2,000 bbl B. 1,500 bbl C. 1,000 bbl D. 500 bbl


Page: 3.3


Use the diagram information to answer questions 10 through 14. 10.

What is the hydrostatic pressure at TD? A. 2,261 psi B. 2,661 psi C. 2,785 psi D. 5,357 psi

11.

What is the string capacity in barrels? A. 161 bbls B. 121 bbls C. 101 bbls D. 81 bbls

12.

What is the annular volume in litres? A. 11,789 litres B. 98,864 litres C. 102,030 litres D. 198,468 litres

13.

What is the annular volume in barrels with no string? A. 780 bbls B. 745 bbls C. 130 bbls D. 957 bbls

14.

What is the height of the influx with a 20-barrel pit gain? A. 392 ft B. 239 ft C. 223 ft D. 199 ft

5118 ft 5 in. drill pipe ID 4 in.

239 ft 8 in. drill collar 1/2 in. ID 2!/2

1/4 in. hole with 10 ppg mud 12!/4

Page: 3.4


Assistant Driller OJT Module Practical Well Control - Workbook Answers

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. 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. The pressure loss across the nozzles. B. The pressure loss in the surface lines. C. The pressure loss in the drill stem. D. The pressure loss in the annulus.

3.

At the start of a trip out of the hole for a bit change, the first 20 x 93 foot stands of pipe are pulled from the hole wet with no fill up. Using the following data, calculate the reduction in bottomhole pressure. DP. Metal Displacement = .00764 bbls/ft DP. Capacity = .01776 bbls/ft Casing Capacity = .0758 bbls/ft Mud Weight = 10 ppg A. B. C. D.

4.

48 psi 483 psi 600 psi 683 psi

At the start of a trip out of the hole for a bit change, the first 10 x 93 foot stands of pipe are pulled from the hole dry with no fill up. Using the following data, calculate the reduction in bottomhole pressure. DP. Metal Displacement = .00764 bbls/ft DP. Capacity = .01776 bbls/ft Casing Capacity = .0758 bbls/ft Mud Weight = 12 ppg A. B. C. D.

650 psi 6 psi 65 psi 130 psi

5.

Select the two things that are needed to accurately determine initial circulating pressure. A. Drilling pump pressure and mud weight B. Shut-in drill pipe pressure and mud weight C. Slow circulating rate pressure and final circulating pressure D. Slow circulating rate pressure and shut-in drill pipe pressure

6.

Select the three things that are needed to accurately determine final circulating pressure. A. Drilling pump pressure, drilling mud weight, and kill mud weight B. Shut-in drill pipe pressure, drilling mud weight, and kill mud weight C. Slow circulating rate pressure, drilling mud weight, and kill mud weight D. Slow circulating rate pressure, drilling mud weight, and final circulating pressure

7.

The driller's method of well control normally requires how many circulations to kill a well? A. One circulation B. Two circulations C. Three circulations D. Four circulations


Page: 3.5

Assistant Driller OJT Module Practical Well Control - Workbook Answers

8.

The driller's method of well control will normally result in ______ A. a higher bottomhole pressure than the wait-and-weight method. B. a lower bottomhole pressure than the wait-and-weight method. C. a higher surface pressure than the wait-and-weight method. D. a lower surface pressure than the wait-and-weight method.

9.

During a well-killing operation, a common way to bring the pump up to kill rate without changing bottomhole pressure is to ______ A. keep SIDPP constant at the original shut-in value by opening the choke. B. keep SIDPP constant at the original shut-in value by opening the choke and bringing the pump up to kill-rate speed. C. keep SICP constant at the original shut-in value by opening the choke and bringing the pump up to kill-rate speed. D. ensure that casing pressure and standpipe pressure rise consistently together.

10.

The usable accumulator fluid for a 10 gallon accumulator bottle on a 3,000 psi system with 1,000 psi precharge is approximately ______ A. 9 gallons. B. 7 gallons. C. 5 gallons. D. 3 gallons.

Page: 3.6


Assistant Driller OJT Module Kick Data and Gauges - Workbook Answers

Well Depth

WELL DATA 10,000 ft TVD 11,500 ft MD

Bit size

8.5 in.

Drill Pipe

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

Drill Collars

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

Casing

95/8 in., 47 lb/ft. P110 8.681 in. 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 in. Liners Capacity = 0.117 bbls/stk

While Drilling

PUMP PRESSURE 2,500 psi at 80 spm (APL = 260 psi)

Slow Pump Rate

250 psi at 30 spm (APL = 75 psi)

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

ANNULAR VOLUMES = 0.0505 bbls/ft = 0.0459 bbls/ft = 0.0292 bbls/ft

SIDPP SICP GAIN FRACTURE GRADIENT AT SHOE


WELL CONTROL DATA = 520 psi = 720 psi = 12 bbls = .91psi/ft

Page: 3.7


1.

What is the total capacity of the drill string? A. 150 bbls B. 160 bbls C. 197 bbls D. 180 bbls

2.

Calculate the total annular capacity with the pipe on bottom. A. 482.2 bbls B. 457.5 bbls C. 547.5 bbls D. 627.6 bbls

3.

What is the surface to bit time with the pump running at 80 spm? A. 21 mins B. 25 mins C. 32 mins D. 39 mins

4.

Calculate bit to surface time (bottoms up) at 80 spm. A. 58.5 mins B. 49.7 mins C. 60.3 mins D. 51.5 mins

5.

What kill mud is required to balance formation pressure? A. 13.4 ppg B. 13.0 ppg C. 12.4 ppg D. 16.4 ppg

6.

The ICP (initial circulating pressure) at 30 spm will be approximately ______ A. 270 psi. B. 770 psi. C. 990 psi. D. 1,200 psi.

7.

The FCP (final circulating pressure) at 30 spm will be ______ A. approximately 800 psi. B. approximately 390 psi. C. approximately 500 psi. D. approximately 270 psi.

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. Increase by about 210 psi B. Decrease by about 210 psi C. Remain constant because drill pipe pressure was not changed D. Increase by about 500 psi

9.

What is the hydrostatic pressure at the bottom of the hole before the kick? A. 5,800 psi B. 6,800 psi C. 7,800 psi D. 6,240 psi

Page: 3.8



10.

What is the ECD on bottom while drilling? A. 15.0 ppg B. 12.5 ppg C. 12.0 ppg D. 13.5 ppg

11.

At 80 spm what is the annular velocity around the drill collars? A. 412 ft/min B. 210 ft/min C. 506 ft/min D. 321 ft/min

12.

What is the maximum allowable mud weight? A. 17.5 ppg B. 16.5 ppg C. 18.0 ppg D. 19.0 ppg

13.

What is the approximate length of the influx? A. 1,027 ft B. 850 ft C. 653 ft D. 410 ft

14.

The gradient of the influx is about ______ A. .137 psi/ft. B. .320 psi/ft. C. .465 psi/ft. D. .433 psi/ft.

15.

How many strokes to go from ICP to FCP? A. 1,282 strokes B. 1,368 strokes C. 1,680 strokes D. 1,538 strokes

16.

How many strokes will it require to go from bit to shoe? A. 5,364 strokes B. 4,122 strokes C. 1,658 strokes D. 874 strokes

17.

How long will it take to go from bit to shoe at a pump speed of 30 spm? A. About 214 mins B. About 29 mins C. About 157 mins D. About 55 mins

18.

At 30 spm what is shoe to surface travel time? A. About 101 mins B. About 34 mins C. About 214 mins D. About 76 mins


Page: 3.9


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. 1,250 psi B. 1,500 psi C. 2,000 psi D. 1,950 psi

20.

What would be the new MAASP once the well has been killed? A. 685 psi B. 1,638 psi C. 700 psi D. 585 psi

21.

At 30 spm how long will it take to pump kill mud to the bit? A. 157 mins B. 214 mins C. 56 mins D. 76 mins

22.

If a 100 psi safety margin is included in the kill mud weight, what would the new kill weight be? A. 15.5 ppg B. 16.0 ppg C. 15.4 ppg D. 13.2 ppg

23.

What would be the approximate pressure step down from ICP to FCP in psi/100 strokes? A. 30 psi/100 stks B. 46 psi/100 stks C. 50 psi/100 stks D. 66 psi/100 stks

24.

The kill operation has started. 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 okay.

TOTAL STROKES 900 1000 1100 800 1200 700

60

800

PSI

600

1500

500

400

1600

400

100

1800 0 1900

100

30

DRILLPIPE PRESSURE

1800 0 1900

CASING PRESSURE

770

720

OPEN

Page: 3.10

1600 1700

200

PUMP SPEED

1400 1500

300

1700

200

1300

PSI

600

1400

500

300

900 1000 1100 1200

700

1300

CHOKE CLOSE POSITION



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. 900 1000 1100 D. Decrease the pump speed. 800 1200 700 1300 E. Nothing, everything looks okay. PSI

600

TOTAL STROKES

300

800 700

1500

500

400

1600

400

1800 0 1900

100

1600 1700

200

30

CASING PRESSURE

770

750

OPEN

26.


The pit levels are reported to be increasing slightly. What are you going to do now? A. Open the choke a little. B. Close the choke a little. TOTAL STROKES C. Increase the pump speed. 900 1000 1100 1000 D. Decrease the pump speed. 800 1200 700 1300 E. Nothing, everything looks okay. PSI

600

800 700

1500

500

400

1600

400

100

1800 0 1900

1300

PSI

1600 1700

200 100

PUMP SPEED

30

DRILLPIPE PRESSURE

850

OPEN

Casing pressure is still slowly increasing. What are you going to do now? A. Open the choke a little. B. Close the choke a little. C. Increase the pump speed. 900 1000 1100 D. Decrease the pump speed. 800 1200 700 1300 E. Nothing, everything looks okay. PSI

600


TOTAL STROKES

3000

800 700

1500

500

400

1600

400

100

1800 0 1900

30

770

1400 1500 1600 1700

200

PUMP SPEED

DRILLPIPE PRESSURE

100

1800 0 1900

CASING PRESSURE

950

OPEN


1300

PSI

300

1700

200

900 1000 1100 1200

600

1400

500

300

1800 0 1900

CASING PRESSURE

750

27.

1400 1500

300

1700

200

900 1000 1100 1200

600

1400

500

300

1800 0 1900

100

PUMP SPEED

DRILLPIPE PRESSURE

1400 1500

300

1700

200

1300

PSI

600

1400

500

300

900 1000 1100 1200


Page: 3.11


28.

The casing pressure has been reducing for the last few hundred strokes. How are things going? A. Open the choke a little. B. Close the choke a little. TOTAL STROKES C. Increase the pump speed. 900 1000 1100 900 1000 1100 4750 D. Decrease the pump speed. 800 1200 800 1200 700 1300 700 1300 E. Good, everything looks okay. PSI

600

1500

500

400

1600

400

300 100

1800 0 1900

100

30

DRILLPIPE PRESSURE

1800 0 1900

CASING PRESSURE

770

520

OPEN

Page: 3.12

1600 1700

200

PUMP SPEED

1400 1500

300

1700

200

PSI

600

1400

500



Assistant Driller OJT Module Drilling Line Care and Maintenance - Workbook Answers

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. Crossover wear B. Drum crush C. Doglegs D. Tension breaks 2.

How does drum crush occur? A. Extreme pressure is brought down on the wire by an additional wrap on the drawworks. B. The line passes over sharp corners or small diameter sheaves. C. It occurs at the crossover points as the line hits the turnback roller and starts a new layer. D. The line is overloaded.

3.

Where does crossover wear occur? A. At the deadman anchor B. At the top of the crown block sheaves C. At the bottom of the travelling block sheaves D. At the new layer position on the drawworks

4.

What is a ton-mile? A. The weight of the drill string multiplied by the depth of the hole B. The work needed to move one ton over a one-mile distance C. The maximum drawworks capacity D. The depth of the hole divided by the weight of the string

5.

What always takes precedence over ton-miles when it comes to drilling line replacement? A. Visual inspection B. Depth of trip to be performed C. Weight of assembly to be tripped D. How long until the end of the shift

6.

What does 6 x 19 IWRC mean? A. The number of wires allowed to be damaged over a given length B. 6 strands, at 19 wires per strand, wrapped around an independent wire rope core C. 19 strands, at 6 wires per strand, wrapped around an independent wire rope core D. 19 strands of size 6 wire, wrapped around an independent wire rope core

7.

Why do we cut the line rather than spooling more and more onto the drawworks? A. To prevent spooling problems B. To avoid damage to the line of other wraps C. To avoid accumulating too much line on the drawworks D. all of the above

8.

If we keep ton-mile records why do we inspect the drilling line? A. To check for damage caused by jarring, fishing, or other operation. B. To ensure the slip-and-cutoff program is adequate. C. both A and B D. none of the above

9.

Maintenance of what equipment has a direct bearing on the condition of a drilling line? A. Crown block, travelling block, drawworks, Crown-O-Matic, deadline stabilizer, deadline anchor, wireline turnbacks B. Crown block, travelling block, drawworks, Crown-O-Matic, deadline stabilizer, wireline turnbacks C. Crown block, travelling block, drawworks, deadline anchor, wireline turnbacks D. Crown block, travelling block, Crown-O-Matic, deadline stabilizer, deadline anchor


Page: 3.13


10.

How should wireline clips be attached to a line? A. With the U-bolts over the dead end of the line B. With the U-bolts over the live end of the line C. With the base of the clip against the dead end of the line D. both B and C

Part II 11. What needs to be reset after string-up or cutoff? A. The driller’s brake B. The drawworks auxiliary brake C. The Crown-O-Matic D. none of the above 12.

How much gap should the load cell sensator have without a load on the hook? A. 5 / 8 in. B. 3/ 8 in. C. 4 / 16 in. D. none of the above

13.

How often should the crown block sheaves be greased? A. Every 8 hours B. After tripping only C. After 200 ton-miles D. Daily

14.

What is likely to be the effect of a damaged sheave? A. Stuck pipe B. Slow rate of penetration C. Higher rotary torque D. Damaged or broken drilling line

15.

What should be inspected on the drawworks? A. Damaged grooving B. Wear plates C. Wireline turnbacks D. all of the above

16.

What should be attached to the derrick above the drawworks to prevent fastline flopping? A. A wireline guide B. A deadline stabilizer C. A deadline anchor D. A turnback roller

17.

Brass inserts can be replaced in what piece of equipment? A. A wireline guide B. A deadline stabilizer C. A deadline anchor D. A turnback roller

18.

How many wraps of line should be put on the drawworks with the travelling block at the lower pick up point? A. 18 B. 16 C. 12 D. 8

Page: 3.14



Part III 19.

What is the standard operating safety factor for drilling line? A. Seven B. Six C. Five D. Four

20.

Where are the critical points of wear on the drilling line? A. At the top of the crown block sheaves on pickup points B. At the bottom of the travelling block sheaves on pickup points C. At crossover points on drawworks and at the deadline anchor D. all of the above

21.

What two things does slipping and cutting of drilling line accomplish? A. It moves worn line away from critical wear points and continuously replaces worn line. B. It removes old line from service and moves points of heavy wear to non-critical points. C. It moves less worn line to the critical wear points and adds new line into the system. D. all of the above

22.

When should visual inspection of drilling line take precedence over ton-mile goals? A. Always B. After jarring operations C. Prior to running a heavy casing string D. During an end of well inspection

23.

What does the wire rope service curve explain? A. The required safety factor B. The number of days between slip and cut C. The relationship between safety factor and ton-mile goals D. 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 24–26. 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) 61/2-in. x 23/4-in. drill collars, 5 in. 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 24.

What is the excess weight allowance? A. 45,900 lbs B. 35,900 lbs C. 25,900 lbs D. 15,900 lbs

25.

How many ton-miles were incurred tripping? A. 600 B. 547 C. 494 D. 464

26.

The trip before this involved 444 ton-miles tripping. How many ton-miles were used in drilling between trips? A. 468 B. 309 C. 150 D. 60


Page: 3.15


TON-MILES FORMULA – Calculator Method Refer to the IADC Drilling Manual: Ton-Mile Calculations Section and use the calculation below to answer questions 27–29. Tr = D(Ls+ D ) Wm + D(M + 1/2 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 ft (101 lbs/ft) 6 3/4-in. x 2 3/4-in. drill collars, 5 in. 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 27.

What is the excess weight allowance? A. 60,000 lbs B. 50,000 lbs C. 40,000 lbs D. 30,000 lbs

28.

How many ton-miles were incurred while tripping? A. 537 B. 493 C. 411 D. 386

29.

The trip before this involved 245 ton-miles. How many ton-miles were used in drilling between trips? A. 876 B. 744 C. 498 D. 423

Page: 3.16


Assistant Driller OJT Module Drilling a Straight Hole - Workbook Answers

Section: Hole Angle Change and Causes of Hole Deviation 1.

Straight-hole drilling should result in ______ A. a perfectly straight hole. B. a trouble-free hole with no sharp edges or changes in direction. C. a wellbore that has no changes in angle. D. 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. True vertical depth = 4,968 ft; horizontal drift = 566 ft B. True vertical depth = 5,000 ft; horizontal drift = 0 ft C. True vertical depth = 99.36 ft; horizontal drift = 11.32 ft D. True vertical depth = 993.6 ft; horizontal drift = 113.2 ft

3.

Doglegs are likely to develop when ______ A. the rate of hole angle change is greater than 3° per 100 feet of hole. B. the total hole angle change is greater than 3°. C. weight on bit is suddenly and drastically reduced. D. the penetration rate is too high.

4.

Use the table in figure 1.7 to determine the dogleg severity with the following data: First Survey Second Survey Vertical angle: 8° 15' Vertical angle: 2° 45' (8 1/4°) (2 3/4°) Direction: S 34° E Direction: S 9° E Depth: 6,400 feet Depth: 6,475 feet A. B. C. D.

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

5.

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.

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 D. none of the above

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.


Page: 3.17


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 to the right, 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.

13.

Which of the following contribute to unwanted deviation of the wellbore? A. Dull bits B. Low bit weight C. Mnimum 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.

A

B

C

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.

Page: 3.18



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.

20.

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: 81/8 in. Hole class: R Formation dip: 15°

Hole angle: 4° Drill collar size: 7 in.

A. The driller can run 39,162 lbs on the bit with the 7-in. drill collars and maintain hole angle. B. Bit weight can be increased to 68,500 lbs if 7 1/2-in. drill collars are used and a stabilizer run at 60 ft above the bit without changing hole angle. C. Hole angle can be reduced to 2° by reducing bit weight by 7,362 lbs and adding a stabilizer 80 ft above the bit. D. The driller can increase weight on bit to 46,200 lbs 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 to the right, 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.


D

C A B

Page: 3.19


26.

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 11/2 in.) 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.

33.

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 lbs.

Page: 3.20



35.

How much does a standard-length drill collar weigh if it has a 51/2-inch OD and 21/4-inch ID? A. 67 lbs B. 2,010 lbs C. 6,700 lbs D. 201.0 lbs

36.

What total weight of drill collars in air is required with the following drilling conditions?

A. B. C. D. 37.

How many 71/4-inch OD x 21/4-inch ID standard-length drill collars will be needed with the following drilling conditions?

A. B. C. D. 38.

Bit weight required: 68,500 lbs Safety factor: 15% Drilling mud density: 12.2 ppg Vertical hole: 0° inclination 6,457 lbs 68,500 lbs 78,775 lbs 96,775 lbs

Bit weight required: 32,440 lbs Drilling mud density: 9.8 ppg Safety factor: 15% 14 12 8 7

If seven standard-length 6-inch OD x 213/16-inch ID drill collars are used, how many standard-length 71/2-inch OD x 213/16-inch ID collars will be needed with the following conditions?

A. B. C. D.

Bit weight required: 46,129 lbs Drilling mud density: 12 ppg Safety factor: 17% 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.


Page: 3.21


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.

44.

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 full gauge hole.

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 sandline.

Page: 3.22


Assistant Driller OJT Module Rig Hydraulics - Workbook Answers

Section: Introduction and The Hydraulic System 1. A properly designed hydraulic system will ______ A. gouge out new hole in all formations by powerful jet nozzle action. B. deliver adequate power to the bit nozzles for bottomhole cleaning. C. provide enough pressure to the drilling mud to transport cuttings out of the annulus. D. 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. mud viscosity B. rotary speed C. bit weight D. mud weight

3.

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. True B. False

4.

Use the 10D2 rule to determine the input pump power for properly cleaning an 8 1/2-inch 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

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 hhp B. 570 hhp C. 518 hhp D. 633 hhp


Page: 3.23


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-in. ID; hose–55 ft with 3-in. ID; swivel–5 ft with 21/4-in. ID; kelly–40 ft with 31/4-in. ID. Circulation rate is 570 gpm with 10-ppg mud. A. 254 psi B. 91 psi C. 56 psi D. 38 psi

13.

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. True B. False

Use figures 2.9 and 2.10 with the following drilling conditions to answer questions 15, 16, and 17. Drill pipe: Size: 41/2-in. OD Weight: 16.6 lbs/ft Tool joint type: XH 15.

Page: 3.24

Drill collar size: 2-in. bore, 8-in. OD Circulation rate: 490 gpm

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

19.

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. True B. False

22.

Pressure losses in the annulus are affected by the ______ A. size of the drill string. B. circulation rate. C. size of the 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. True B. False

24.

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


Page: 3.25


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. 26.

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 in. 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 increased 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. True B. False

Section: 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.

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33.

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-in. OD and 3.34-in. ID; hole size– 7.875 in. 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. all of the above


Page: 3.27

Assistant Driller OJT Module Drilling Muds - Workbook Answers

Section: Introduction and Drilling Fluid Composition and Properties 1. When added to water, a good drilling clay will ______ A. hydrate. B. react with the inert fraction. C. thin the mud. D. 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.

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. True B. 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

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10.

Inert solids in the drilling mud ______ A. dissolve 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. 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. 14.

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


Page: 3.29


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.

21.

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

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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

28.

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. True B. False

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

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

35.

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


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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. They 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.

42.

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. 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. True B. False

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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.

49.

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. True B. False

50.

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


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Assistant Driller OJT Module Casing - Workbook 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. to provide a means of controlling well pressure. B. to confine production to the wellbore. C. to allow production from multiple producing formations. D. to permit installation of artificial lift equipment. E. 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. True B. 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

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. 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. True B. False

Page: 3.34



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. tie-back casing. D. all of the above

12.

Frequently, the heaviest string of pipe set in the well is the ______ A. intermediate string. B. tie-back string. C. conductor. D. production string.

Section: 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. 14.

The most frequently used casing is ______ A. Range 1, 16–25 ft in length. B. Range 2, 25–34 ft in length. C. Range 3, 34–48 ft 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. True B. 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.


Page: 3.35


19.

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

20.

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

21.

When couplings are screwed onto the casing hand 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 lbs B. 75,600 lbs C. 233,334 lbs D. 23,334 lbs

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.

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28.

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. True B. 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. 35.

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


Page: 3.37


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. True B. False

40.

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.

41.

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 first 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.

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45.

The volume of mud gain by the pits when a 15,000 foot, 51/2-in. OD casing is run in a well and completely filled up (assume no fluid loss) is ______ A. 100 bbls. B. 10.9 bbls. C. 109.0 bbls. D. 190.0 bbls.

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

47.

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. True B. 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


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Assistant Driller OJT Module Cementing - Workbook Answers

Section: Mixing Cement 1. In addition to providing support for casing, primary cementing is essential to the well because it ______ A. prevents casing corrosion. B. allows formation fluids from different zones to mix and flow to the surface. C. prevents the hole from caving below the casing. D. makes drilling the well easier. 2.

If a well has a high-quality casing job, cement is usually not needed. A. True B. 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. 101/2 gallons per sack of cement. B. 111/4 gallons per sack of cement. C. 5 1/2 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.

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.

Section: 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. Page: 3.40



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. True B. False

15.

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


Page: 3.41


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 in., 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 cu ft. B. 2,688 cu ft. C. 2,500 cu ft. D. 2,000 cu ft. 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. True B. False

22.

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-inch hole with 7-inch 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.

Section: 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.

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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.

28.

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. 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

35.

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


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© Transocean 2005 Issue Date: 01 January 2005

Assistant Driller Assessor Guide

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