Assistant Driller eOJT Assessors Guide Training ProceduresSection 1Training ProceduresAssistant Driller OJT ModuleRev. 02: January 2005 Page: 1.1Training ProceduresObjectivesUpon completion of this module, the participant should be able to:1. demonstrate a clear understanding of the role and responsibilities of Transocean assistant drillers, and2. perform basic assistant driller tasks safely and competently.Training ProcedureCompleting 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 participantscan receive a module certificate. The task list evaluation guide in this assessors guide is to help you assess the competenceof the participants. Some flexibility is permitted, but you must be thoroughly satisfied that the level of skill and knowledgedemonstrated by each participant is consistent with the objectives of this OJ T module. Only when you believe that a participanthas 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 foryou to addadditional tasks you feel are important and want participants to perform. You cannot, however, delete tasks, except where theydo not apply to your rig.When the participant completes the task list requirements to your satisfaction, and has successfully completed the computer-generated final test, complete and sign a completion notification form (CNF).Also, ensure that the participant fills in theemployee comments section. Then, forward the completed and signed CNF to the regional training center. After receiving theCNF, the training center will complete the participant in the Training Management System. The RSTC will then be able to printamodule certificate from the Training Management System. Keep the completed task list on file at each participants assignedlocation. The training file shall be transferred when the participant is transferred.Task List Evaluation GuideSection 2Task List Evaluation GuideAssistant Driller Task List Evaluation GuidePage: 2.1 Rev. 02: January 2005Describe how the OJT system works and the supervisors 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 ifneeded.Supervisors play a key role implementing the training. Supervisors are, as part of their ongoing duties, expected to continueproviding guidance and on-the-job training to crew members. They monitor and track the progress of the participants withthe 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 participants skills and knowledgerequired in each job category or function. The OJT system is a tool for self-development and career progression. It isdesigned to ensure that the participant is exposed to a majority of the important occurrences relative to the particular jobcategory or function. It consists of a combination of practical work on the rig and self-study. The mandatory tasks aresupported 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 theimmediate supervisor(s).Participants must demonstrate competency in each task before the supervisor signs it off as completed. This method ofassessment ensures a demonstrated ability from participants as they gain new knowledge and skills required for the jobfunction. All tasks must be completed to the supervisor(s) satisfaction before they are eligible to complete a final computer-generated 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 orderlist on the Corporate Training website or EMPAC/TOPS Houston Procurement website. The supervisor gives the modulebooklet to the participant who follows the self-paced task list. Besides hands-on learning, training tools are also used tohelp the participant gain knowledge on the tasks. Supervisors assess participants as they perform the tasks. The OJTModules Assessors Guide is provided to guide the supervisors through the assessment process as required. All tasksmust be completed to the supervisors satisfaction. Workbook questions also support the tasks. The supervisor shouldevaluate the workbook answers. The participant must successfully complete the final computer-generated test after allother training requirements are completed. The completion notification form (CNF) is completed by the supervisor andparticipant and sent to the regional training center for recording in the training database (TMS). A certificate is issued to theparticipant. When the participant is transferred to another location, the task list / training records are also transferred.1.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 tothe assistant drillers 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 bereleased. The OIM will authorize individuals as competent persons for each type of energy isolation. A permit to work is anadditional requirement when an isolation certificate is issued for maintenance or repair of a system or component containingenergy. In some cases, the task is only hazardous because of the energy. When effective isolation is achieved, the taskmay no longer be hazardous and, hence, the isolation process controls the risks associated with the energy. The personperforming the work will confirm the equipment, inoperative by physically trying to operate it. This is done to ensure thatprior 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.2.ExplaintheroleoftheassistantdrillerduringsuchemergenciesasH2S,hydrocarbondischarge,fire,manoverboard, and abandon rig.Ask participants to explain their role is during emergency situations. Participants must ensure that the assistant drillerssubordinates are following the procedures in the emergency response plan.3.Assistant Driller Task List Evaluation GuidePage: 2.2 Rev. 02: January 2004Show 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, communicateand control. Participants should ensure that all concerned parties are involved, encourage input from all personnelconcerned, and incorporate suggestions into the work plan. They should also ensure that all safety issues areaddressed, all contingency planning is communicated, and key personnel are identified to the group. Participantsshould discuss the scope of the work, the hazards, and specific procedures to be followed for the job. Communicationtools such as sketches, drawings, and manuals help to clearly convey the task strategy.Reference HS&E Manual 9.30000.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 rigusing the operations 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 anarea where an explosive air-gas environment may be present during normal operations. Zone 2 is an area where anexplosiveair-gasenvironmentispresentonlyinabnormalcircumstancesand,ifpresent,wouldbeonlyforashortduration. 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 zoneclassification. The equipment needs to be explosion-proof, intrinsically safe, or otherwise protected.4.5.6. 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 aselectrical, mechanical, subsea, and marine. They must also ensure concerted action and cooperation while working in aprofessional manner with third-party company personnel, such as mud loggers, cementers, wireline operators, testingoperators, and casing crews.Assist the driller in filling out the IADC drilling report.Following the drillers 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.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 workingsmoothly. Check that the drill floor is clean, tidy, and hazard-free.If it is not, participants must direct the drill crew to putit in order. Putting the floor in order may involve removing unnecessary items from the floor, checking and cleaningvarious tools and equipment, and washing down the floor.7.8.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.9.Assistant Driller Task List Evaluation GuidePage: 2.3 Rev. 02: January 2005Show 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. Forexample, they should check for worn rollers; and they should make sure that the guide system wires and guide systempulleys are in good shape. Also, they should check all bolts, sheaves, bearings, and grease fittings for wear, and ensurethat 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.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 bearingsare in good condition, and they should check the kick-back plate inside the drum for wear. The plate fasteners should bein good repair. Participants should also know how to replace or invert rollers, change bearings and shaft, and maintainrollers in working condition.Reference Drilling Line Care and Maintenance book 9.11000 and DVD-ROM 20.0228.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 thatthe traveling block is secured. They should identify all fittings to check on the disc brake arrangement. For a band brandsetup, ensure that both sides of the bar have equal gaps. Participants should ask the driller for confirmation of 45-degreebrake arm angle and then set the jam nuts. They should adjust the kickback rollers and look for broken grease lines andfittings.Show how to adjust and reset the crown block saver (Crown-O-Matic) or how to adjust and reset floorsavers, ifapplicable.Observe participants adjusting and resetting the Crown-O-Matic. It should slide smoothly. They should set the Crown-O-Matic for tripping to prevent the traveling block from hitting the crown block. Then, they should set it for drilling to preventdamaging 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 withcrownsavers running off of proximity switches mounted on the derrick track should be check for block height calibration.Reference DVD-ROM 20.0803.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 drawworksdrum, 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 20.0227.10.11.12.13.14.Assistant Driller Task List Evaluation GuidePage: 2.4 Rev. 02: January 200416.17.18.19.20.15. Explain and show how to calculate drilling line ton-miles (tonne-kilometres) while drilling and/or tripping andhow to use this information.Ask participants to explain stress points on the drilling line and the importance of avoiding these points. Theyshould describe how many feet to cut and maximum ton-miles per foot. Ask participants to calculate the ton-miles (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, andmaintenance. 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.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 withrags to prevent splinters from flying. Prepare the end of the line by removing the grease. Fasten the socket and spool theline 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 specificprocedures.Reference IADC Drilling Manual 10.10010 and DVD-ROM 20.0229.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 tooccur. They should also be able to identify the lower box thread area on drill collars and tool joint connection on drill pipeas the most common region for washouts on these tubulars.Reference IADC Drilling Manual 10.10010.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 thatthey fully understand the correct procedure.Reference IADC Drilling Manual 10.10010.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 thecorrect procedure.Reference Practical Well Control book 2.80040 and CD-ROM 61.10160.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 andcalculating the gauge. They should explain why the bit and stabilizers are gauged both before and after they are run.Assistant Driller Task List Evaluation GuidePage: 2.5 Rev. 02: January 200521. 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 shouldidentify specific wear areas on the bit.Reference IADC Drilling Manual 10.10010.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 Totcoring. 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 bepulled, causing rig downtime and loss of revenue. The corresponding Totco ring must be installed in proper position. Askparticipants to explain the purpose of a float valve. It prevents backflow and nozzle plugging, and helps prevent shallowgas from entering the drill stem.Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210.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 shouldexplain the methods of fitting nozzles in bits manufactured by Hughes, DBS Security, Reed, and Smith, as well as otherbrands of bits used on the rig, if applicable.Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210.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, runningin, pulling out, and breaking and laying out a typical BHA. Participants should know how to properly handle downholemotors, shock subs, drilling jars, accelerators, stabilizers, and crossovers. They should be able to tell the drill crew whereto properly place the tongs, backup snub lines, and dog collars. Also, they should be able to instruct the crew in theproper way to set and remove the slips.Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210.Identify and explain the use of typical fishing tools used on your rig.Participants should identify and explain the function of a rigs 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 needto accurately measure various lengths, diameters, and depths of the fishing tools, fishing string, fish, and borehole. Theyshould make a drawing of a typical fishing tool and explain why it is necessary to have an accurate sketch of a fishingassembly.Reference Open-Hole Fishing book 2.30230.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 upan overshot including such parts as spiral and basket grapples, seals, control ring, bowl, extension, and top sub.Reference Open-Hole Fishing book 2.30230.23.24.25.22.26.Assistant Driller Task List Evaluation GuidePage: 2.6 Rev. 02: January 2004Show 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 theassembly. They should be able to identify the size and type of connection and check the condition of the shoulders andthreads. 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.Show how to calculate drill string capacity, annular capacity, bit depth at any given time, and the number ofstands 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 ofstands from surface to shoe, surface to bottom, and bottom to shoe should also be explained.Reference IADC Drilling Manual 10.10010.Explain and show how to calculate drilling line ton miles (tonne kilometres) while running casing and how touse 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.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 runningtool and retrieve the wear bushing. Follow the equipment specific procedure for setting wear bushing (J-slot type,shear pin type or cam actuated).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.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.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 ableto identify different jaw sizes, and show how to shut down the tong power unit.27.29.30.31.28.32.33.Assistant Driller Task List Evaluation GuidePage: 2.7 Rev. 02: January 200534.36.37.38.35.39.Explain how to dress and install a cementing head, secure high-pressure Chiksan lines or hose, and performa pressure test.Observe participants dressing a cementing head, rigging it up, and aligning the valves. Participants should identify andload the plugs under direct supervision of tool hand and explain how the head works. They should explain theconsequences of loading the head the wrong way.Reference Drilling Technology Series, Segment II: Drilling Operations book 2.01210.Show how to perform daily checks on well-control equipment such as IBOP and crossover(s), chokemanifold, and accumulator unit.Following the rig-specific daily checklist, observe participants checking well-control equipment. The IBOP must be inthe 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 theaccumulator unit. Also check the accumulator fluid level and position of valves on the choke and kill lines on a surfacestack.Reference Practical Well Control book 2.80040.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.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.Explain the diverter control system and diverter procedures.Ask participants to explain the diverter procedures for your rig, and explain when and why its used. They shouldexplain 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.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 performingroutine service. Use a work permit, be aware of high pressure, use climbing PPE, practice safe lifting, and communicateeffectively. 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 asurface stack.Reference Practical Well Control book 2.80040 and CD-ROM 61.10140.Assistant Driller Task List Evaluation GuidePage: 2.8 Rev. 02: January 2004Explain 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). Theyshould be able to explain how to bleed pressure, remove the cap, refit the element, and put the cap back on followingmanufacturer recommendations. For subsea operations, the participant should assist a subsea engineer in servicing anannular BOP.Reference Practical Well Control book 2.80040, Subsea Blowout Preventers and Marine Riser Systems book 2.30410,and CD-ROM 61.10040.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 describeprecautions to take when working over water, disconnecting the accumulator and rams/choke/kill control lines, removingthe 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, operationof BOP handling equipment and carriers, and use of spider beams.Reference Practical Well Control book 2.80040.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. Theyshould prepare the testing equipment (test plug/cup tester), and communicate clearly with the driller. Participants shouldexplain 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 andany safety related issues with testing.Review the written test procedures with participants.Reference Practical Well Control book 2.80040 and CD-ROM 61.10010.Show how to do a complete IBOP, standpipe manifold, top drive, and pump room manifold low and high-pressuretest.Participants should perform assistant driller duties during a complete IBOP, top drive and standpipe manifold pressuretest. The sequence for filling the standpipe and testing the IBOP valves should be explained. Explain the purpose of thelow-pressure and high-pressure tests. They should know to insure stand pipe is not lined up to mud pump unless bleedoff is open.Reference Practical Well Control book 2.80040 and CD-ROM 61.10110.Show how to calculate the space out.Participants should show the recorded distances between all ram and annular preventers and the RKB. On surfacestacks, they should physically measure it. They should give examples of different tools that will need to be spaced outwhen running them in BOP stack.41.43.44.42.40.Assistant Driller Task List Evaluation GuidePage: 2.9 Rev. 02: January 200545.46.47.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 thethree pressures (manifold, accumulator, and annular). Expect a clear explanation of the function of four-way valves, thebypass valve, air and electric pumps, annular regulator, and transducer operation. The participant must assist the subseaengineer or mechanic in routine maintenance of the accumulator unit. Ask about the system fluid, how to add it, how toread the sight glass, and how to identify leaks.Reference Practical Well Control book 2.80040 and CD-ROM 61.10010.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 maintenancedepartment supervisors and demonstrate organization of the drilling crew for fulfilling the drilling equipment PMS task listrequirements. They should describe how the computer-aided maintenance management system is used.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 andcontainer).Identifyairleaksinthelowdrum,highdrum,catheadfrictionclutches,andquick-releasevalves.Checkcondition of drawworks transmission linkage, chains, sprockets, discs brakes and active heave components if applicable.Reference DVD-ROM 20.0803.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 fromthegoose-neck,andremovingtheassemblythroughtheopeningoftheswivelhousing. Askhowoftenthewashpipe 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 mechanicalpacking.Show how to maintain and repair a standpipe gate valve.Observe disassembling, inspecting, and replacing worn parts in a standpipe gate valve.Lubricatestempacking,valve-stemtiming,bonnetseals,andO-ring.Replacegatesandseats. This task must beperformed under close supervision.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 taskmust be performed under close supervision.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-operatedchoke valve. This task must be performed under close supervision. Participants should explain the purpose and functionof the choke.48.50.49.51.Assistant Driller Task List Evaluation GuidePage: 2.10 Rev. 02: January 2004Show how to service and repair the hydraulic pressure load cell on the standpipe.Observe inspecting and replacing the diaphragm (bladder) in the standpipe manifolds load cell. Rig specificprocedures 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 newhydraulic fluid, and pre-energize the load cell. Purge the system. This task must be performed under close supervision.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) gapexists on the load cell. Check condition of the grease fittings and lubricate as required. Ask for an explanation of how thedeadline anchor works. The deadline anchor is firmly attached to the rig structure or other firm support where it providesa strong anchoring point for the dead end of the drilling line. In addition to its anchoring abilities, the deadline anchor mustalso allow the dead end of the drilling line to flex without stressing the line as it flexes with the addition and subtraction ofweight 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.ExplainandshowhowtoreplacecatheadlinesorE-Ztorquelinesandexplainsafetyprecautions,whereapplicable.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 respoolingthe line.Visuallyinspectandidentifytypicalproblemsassociatedwithautomatedpipe-handlingequipmentsuchaspipe racker, Iron Roughneck, conveyor, hydraulic/pneumatic finger board, and pipe spinner.Observe participants inspecting the automated pipe-handling equipment including the Iron Roughneck, piperacker, 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 wearand loose fasteners. Also, participants should function test each component after inspection.Visually inspect and identify typical problems with the crown block and traveling block assemblies includingblock 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 conditionof sheave guards.Reference IADC Drilling Manual 10.10010.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, sharpthreads on saver subs, washpipe condition and running hours, and general condition of the rotary hose and hose bundles.Visually inspect and identify typical problems with mud treatment equipment.Observe participants visually inspecting mud treatment equipment. Routine inspection includes checking cuttings recoveryequipment, underflow in the hydrocyclones, the distance of flow on the shaker screens, the condition of the screens onthe mud cleaner, drilling fluid leakage, loose fasteners, and overall general working condition. They should be able tofollow up on deficiencies pointed out by the derrickhand or floorhand.52.53.55.54.56.57.58.Assistant Driller Task List Evaluation GuidePage: 2.11 Rev. 02: January 2005Visually 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.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-openingsafety valve and a nonreturn (Gray) valve or DIV. Function test and pressure test.Show how to change the mud pumps pulsation dampener bladder and explain the use of the oxygen tester,where applicable.Observe participants changing the pulsation dampeners bladder in a mud pump. After changing it, they should be ableto properly use an oxygen tester and explain that it is important that no air be in the dampener because of the possibilityof 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.Show how to prepare the drill floor for a typical completion job.Give participants acompletion job checklist and oversee preparation of the drill floor before running the completionstring.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 ahang-off should be carried out. When preparing for rough weather and possible BOP unlatch.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 retrievingriser. All necessary riser running equipment should be in place before the job starts. Pay special attention to correctmakeup.Reference CD-ROM 61.10050.Explain and show how to supervise the moon pool area when the BOP stack and riser system are being run orretrieved.Ask participants to explain and show the ADs role at the moon pool area during BOP and riser running-and-retrievaloperations 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 closequarters and participants should maintain radio communication with boat, control room, and rig floor. Observe the operationof guideline and podline winches, podline or mux line.Reference CD-ROM 61.10050.59.60.62.61.63.64.65.Assistant Driller Task List Evaluation GuidePage: 2.12 Rev. 02: January 200467.68.69.71.70.72.Assist in routine maintenance on the riser and guideline tensioner systems or hydraulic riser tensioner cylindersand 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 tensionersystem. They should assist with slipping and cutting of the riser tensioner lines and demonstrate how to pressure up theAPVs and line up the manifold.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 betweenmoving parts, and overall working condition. Watch for midstroke positioning. Check APV pressure. Participants shouldbe able to identify and correct deficiencies. Reference the rig specific procedure.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 ADs role in the moon pool area when running a permanent and temporary guidebase. All necessary running equipment should be in place before the job starts. Follow the procedures for working overwater. Permit to work must be in place. Standby boat should remain at close quarters and participants should maintainradio communication with boat, control room, and rig floor. Observe the operation of running tools and tubulars andensure that the subsea cameras (or ROV) are in place and properly functioning.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 ontheir rig.Explain the function and show how to use drilling instrumentation at the drillers console on your rig.Observe participants at the drillers console and ask them to name and explain the function of each instrument andcontrol on the console.Operate the driller s drawworks controls during a routine trip in a cased-hole section for a limited period andunder close supervision.Under close supervision of the driller, for a limited period, and in a cased-hole section, participants should operate thedrawworks and drillers controls on a routine trip. This operation should include use of the auxiliary brake, low- and high-drum clutches, transmission gears, and inertia back brake. Participants must observe and monitor all instruments andequipment controls. They should show an understanding of the hazards involved in mishandling this equipment.Reference DVD-ROM 20.0803.Operate the drillers 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 drillerscontrols during routine drilling operations. They must observe and monitor all instruments and equip-ment controls. Theyshould show an understanding of the hazards involved in mishandling this equipment.66.Assistant Driller Task List Evaluation GuidePage: 2.13 Rev. 02: January 200573.74.75.Operate the drillers drawworks control while running casing inside cased hole, under close supervision and fora limited period.Under close supervision of the driller, participants should, for limited periods, operate the drawworks and drillers controlsduring routine casing operations. They must observe and closely monitor all instruments and equipment controls. Theyshould show an understanding of the hazards involved in mishandling this equipment.Reference DVD-ROM 20.0803.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 andopening of choke line failsafe valves, simulate notification of the man in charge, check the space out and simulate closingof hang-off pipe rams.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 efficientmethod of rotating the drillstring and handling pipe stands in 90 lengths and the ability to trip, circulate, rotate and runcasing; 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, mainshaftis attached to the swivel and passes directly through gearbox or transmission with electric drilling motor located alongside the shaft. IBOP valves are connected to the end of the mainshaft, this assures a direct path from the drill string thruthe mainshaft to the swivel.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 elevatorassembly. The link adapter is captivated around the mainshaft just above the load collar on main shaft. Torque arrestorskeep the link adapter up off the shoulder while drilling. The torque arrestors are mounted between the link adapter plateand the rotating head. The link adapter rests on top of the plate and the rotating head bolts onto the gear case. Theelevator is hung from a pair of links allowing it to swing out to pick up pipe when the linktilt is actuated. When the elevatorhas the extra weight of the drill pipe in it, the Link Adapter drops down onto the load collar directing the load up thru themainshaft to the swivel. The torque wrench assembly is independently hung from the rotating head.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.76.77.Assistant Driller Task List Evaluation GuidePage: 2.14 Rev. 02: January 2004Describe the maximum continuous torque in Ft/Lbs on the rig specific top drive.Example:TDS-3 TDS-4 TDS-5Motor TypeGE752 Shunt 26,400 Hi 24,800 Low 38,700 33,000GE752 HiTorqShunt 31,000 Hi 29,100 Low 45,500 38,700GE752 Series 27,800 Hi 26,100 Low 40,900 34,800GE752 HiToqSeries 34,700 Hi 32,500 Low 50,900 43,300EMD M89VTS Series 30,200 Hi 28,300 Low 44,300 37,700Describe the maximum RPM at maximum continuous torque rating on this specific top drive.Example:TDS-3 TDS-4 TDS-5Motor TypeGE752 Shunt 195 Hi 205 Low 130 155GE752 HiTorqShunt 165 Hi 175 Low 110 130GE752 Series 185 Hi 195 Low 125 150GE752 HiToqSeries 150 Hi 160 Low 100 125EMD M89VTS Series 170 Hi 180 Low 115 135Identify 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/LbsExplain 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 rigspecific procedures. An example follows: Sequence pipe handler raises 2" with torque tube engaging splines on upperIBOP valve, it then receives sequenced pressure to clamp the clamping piston on the box end connection. After theclamping 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 thedrillers console.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 allowsfurther raising of the torque wrench to space out the clamping piston onto the saver sub. This allows the break out andmake up of saver sub as required. The removal of the second stop on the lifting mechanism allows the lower IBOP valveto be broken out or made up as required.79.81.80.82.78.Assistant Driller Task List Evaluation GuidePage: 2.15 Rev. 02: January 2005Demonstrate the operation of the linktilt mechanism.Observe participants functioning the linktilt assembly to the intermediate stop mechanism for assisting the derrickhand inracking or running operations and the intermediate stop release lever to allow pick up of pipe from the mousehole.Demonstrate the actuation of the IBOP valves.Observe participants functioning the upper IBOP valve using control handle on drillers console and the lower IBOP valvethru the torque tube opening activated using the hex key.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, oncesingle clears the floor deactivate linktilt to allow single to come to wellbore. Stab the connection at the floor and lower thetop drive allowing the added single to enter the stabbing guide. Make up top drive to single using spin function and torqueusing motor use a backup tong to react to torque. IBOP valve to be opened ready to resume pumping operations and thetop drive brake set to Auto mode ready for drilling ahead.Demonstrate making and breaking a stand connection with the top drive using the pipe handler on at least 5occasions.Observe participants having a think drill meeting with all parties involved in operation. They should confirm the derrickhandhas his safety harness fitted prior to raising travelling blocks. The participants should demonstrate making a connectionby ensuring all torque is removed from drill string prior to setting slips, elevators opened for derrickhand when standdrilled down, string weight set in slips and compensator closed. Mud pumps shut down and IBOP closed after pressurereduces. Break out of the saver sub from the drill pipe using the torque wrench in the pipe handler. Spin out the connectionusing the drilling motor in reverse. Lift the top drive clear of the drill pipe and activate the linktilt mechanism whiletravelling aloft to assist the derrickhand with latching stand of pipe. Extend RBS and adjust height, clamp RBS tong onelevated box of drill string. Once elevators are confirmed latched, the stand can be picked clear of deck and stabbed intoelevated box connection using RBS stabbing head. Lower the top drive into upper end of stand using derrick camera asan aid. Make up top drive to stand using spin function and torque using motor use RBS clamp to react to torque. IBOPvalve to be opened ready to resume pumping operations and the top drive brake set to Auto mode ready for drillingahead. Release RBS clamp and retract RBS system. The full string weight can be taken and compensator positionedready for tagging bottom.Explain the counterbalance system on the top drive.Participants should explain that the counterbalance system prevents damage to the tool joint threads while making orbreaking connections with the top drive by a preventative cushioned stroke similar to that provided by a hook. Thissystem is required because a hook may not be present in the drill string or, if it is present, the spring will already becollapsed due to the weight of the top drive system suspended from it. This would produce undesirable forces on the tooljoint when stabbing the connection.Generally, the system consists of two hydraulic cylinders and attached hardware, two hydraulic accumulators, and ahydraulic manifold with related plumbing. It is designed for 2000psi of hydraulic pressure maximum. The hydraulic cylindersare connected between the top drive unit and the elevator bail ears of the hook, or directly to the block. These cylindersare connected to the hydraulic accumulators located inside the motor frame of the guide dolly assembly. The accumulatorsare precharged with nitrogen (900psi) and maintained at a specific pressure setting by the counterbalance manifoldlocated on the guide dolly. This manifold is also the source of all hydraulic power to the accessories and includes thevalve that operates the torque wrench portion of the Pipe Handler. When properly adjusted all but 825lbs of the top driveweight is taken by the hydraulic cylinders directly to the hook or block, with the weight being transferred through theswivel bail while the top drive system is disconnected from the drill string. With the hydraulic power unit Off, a pilotedcheck valve isolates the counterbalance circuit. As the top drive saver sub is stabbed into the string, the cylinders retractand the swivel bail moves out of contact with the hook. Hydraulic oil under pressure fills the rod end of the cylinders asthey stroke, keeping the weight of the system off the threads. Because the accumulator pressure will decrease slightly asthe oil is drawn out of them, some weight will be transferred to the threads. This force can range from 6,000 to 10,000lbsdepending on overall system weight and the amount the counterbalance cylinders are retracted. If the oil pressure in theaccumulators drops below acceptable levels due to leakage or other reasons, the circuitry in the counterbalance manifoldwill correct this situation automatically any time the hydraulic power unit is switched On.83.85.84.86.87.Assistant Driller Task List Evaluation GuidePage: 2.16 Rev. 02: January 2004Explain 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 directlyto the bottom of the gear case, and a rotating swivel block which the torque arrestors and pipe handler hanger shaft aremounted on. The hydraulic and air lines for the various pipe handler functions (link tilt, torque wrench etc) connectbetween their respective solenoid valves and the stationary flange. The fluids travel from the flange to the swivel blockusing sealed rotating passages (commonly referred to as a fluid slip ring). The standard seven-port head assembly hastwo hydraulic passages, three pneumatic passages, and two spare passages capable of transferring other pneumatic orhydraulic fluid (all are rated at 2000psi). Additional hoses are used to connect the ports in the swivel block to thecorresponding devices (link tilt etc). The swivel block can, therefore, rotate relative to the flange without twisting ordamaging any hoses. The unit can rotate freely or be locked into any of the 24 index positions and will automaticallyreturn to the pre-selected position, just like a standard rotary hook.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 requirementsand customer preference. These systems include:1. Local Blower basic motor cooling system designed to provide local cooling air to the drilling motor, it receivesair from 20 feet above the rig floor at the lowest point of the motors travel. A heavy construction pressure bloweris mounted to the motor. The blower is directly driven by a 15hp explosion proof electrical motor which is connectedto the blower with a rigid duct. This design provides highly reliable service with positive ventilation through itsnormal inlet and spark arrestor protected outlets. It provides a safe, visibly verifiable system that will preventexplosion 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 heightmust be raised. In order to accomplish this, an extended intake may be specified. This system consists of astandard type local blower with ducting to allow the intake to be mounted on the hook or travelling block with aflexible hose running down to the motor. This raises the minimum intake height to approximately 30 feet abovethe rig floor.3. Derrick Mounted Remote Blower for applications that cannot be assured of safe cooling air, such as enclosedderricks, an alternative system using an 8 inch diameter flexible duct is fitted. The systems operation is identicalto the standard system except the blower motor is a 30hp motor that is mounted at the monkey board level andreceives cooling air from outside the derrick walls. The extra horsepower is required to force the air through theduct,whichisaheavyconstructionbulktransferhoseofthetypeusedbetweenoffshoresupplyboatsandplatforms.Closed Loop some regulatory agencies define severely restrictive hazardous areas and consequently require a closedloop cooling system that recirculates cooling air over water cooled heat exchangers. The closed loop system consists oftwo tube type heat exchangers connected to twin blowers driven by a double-ended AC motor. Ducting passes air out themotor exhaust port to the heat exchangers and back to the blower inlets. The heat exchangers are built from cupro-nickeltubes and headers are proof tested to 250 psi.89.88.Assistant Driller Task List Evaluation GuidePage: 2.17 Rev. 02: January 2005Explain 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 torqueusing variac on drillers console, closing and locking drill string compensator. Participant must be able to tell maximumoverpull allowed to break string free with given tubulars in the hole.Explain and demonstrate the loadpath components inspection.Participants should reference EMPAC tasks for periodic lubrication and inspection of loadpath components. Referenceshould 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.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 haveown system) and aligns the top drive saver sub with the drill pipe when making a connection. It also reduces potentialside loading on the swivel stem by maintaining a vertical orientation for the main shaft, while allowing the motor andhousing assembly to float slightly about its trunnions with a preload in both directions. This is necessary because themotor housing assembly tends to pivot away from the rails due to its 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 slipsfor alignment with top drive saver sub, adjustment of cylinder rod by of a turn will move saver sub by approximately .The shipping bracket should only be removed after the main shaft has been stabbed into the motor housing. If the bracketis removed before hydraulic system is turned on, the motor housing will tend to rotate on its trunnions.Explain potential dropped objects and secondary retention system.Participants should reference EMPAC task for top drive inspection and reference Varco or other product manufacturerswebsite for secondary retention system. Example: (www.varco.com) Quicklinks, Products & Services, Secondary Retention.90.91.92.93.Workbook Questions and AnswersSection 3Workbook Question & AnswersAssistant Driller OJT ModulePage: 3.1Rev. 02: January 2005Workbook Questions and AnswersAssistant Driller OJ T 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 shouldreview the corresponding books, DVD-ROMS, and/or CD-ROMs. The supervisor should coach the participant on any weakpoints to ensure that material is understood.The following workbooks are provided in this section:Workbook Page Numbers1. Applied Mathematics 02042. Practical Well Control 05063. Kick Data and Gauges 07124. Drilling Line Care and Maintenance 13165. Drilling a Straight Hole 17226. Rig Hydraulics 23277. Drilling Muds 28338. Casing 34399. Cementing 4043Assistant Driller OJT ModulePage: 3.2 Rev. 02: January 20051. What is the capacity of a 121/4-inch hole in barrels per foot?A. 0.1222 bbl/ftB. 0.1326 bbl/ftC. 0.1457 bbl /ftD. 0.1547 bbl/ft2. What is the annular capacity of a 171/2 inch hole with 5-inch drill pipe inside?A. 0.2732 bbl /ftB. 0.1968 bbl/ftC. 0.1743 bbl/ftD. 0.0895 bbl/ft3. What is the volume in barrels of a rectangular mud tank with the followingdimensions?Width =61/2 ft, Length =181/4 ft, Height =10 ftA. 211 bblB. 316 bblC. 663 bblD. 1,048 bbl4. What is the volume of a rectangular mud tank with the following dimensions?Width =3.5 m, Length =7.8 m, Height =4.3 mA. 117 m3B. 738 bblC. both A and BD. none of the above5. What volume in barrels can the tank hold before fluid passes through the overflow pipe?A. 320 bblB. 230 bblC. 110 bblD. none of the above12.25 in.5 in. 17.5 in.Applied Mathematics - Workbook Answers10 ft24 ft7.5 ft10 ft4.3 m3.5 m7.8 m10 ft6.5 ft18.25 ftAssistant Driller OJT ModulePage: 3.3Rev. 02: January 20056. What is the area of an oval tank cover in square feet, with the following dimensions?Minor Axis =4 ft, Major axis =81/2 ftA. 106.8 ft2B. 75.4 ft2C. 49.3 ft2D. 26.7 ft27. Using the dimensions in question number 6, calculate the volume in barrels, of an oval tank 271/2 feet high?A. 254 bblB. 162 bblC. 131 bblD. 85 bbl8. What is the volume increase in barrels when raising the mud weight from 9.4 ppg to 10.6 ppg in a 1,400 barrelsystem?A. 256 bblB. 71 bblC. 110 bblD. 76 bbl9. 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 mudsystem?A. 2,000 bblB. 1,500 bblC. 1,000 bblD. 500 bbl8.5 ft4 ftApplied Mathematics - Workbook AnswersAssistant Driller OJT ModulePage: 3.4 Rev. 02: January 2005Use the di agram i nformati on to answer questi ons 10 through 14.10. What is the hydrostatic pressure at TD?A. 2,261 psiB. 2,661 psiC. 2,785 psiD. 5,357 psi11. What is the string capacity in barrels?A. 161 bblsB. 121 bblsC. 101 bblsD. 81 bbl s12. What is the annular volume in litres?A. 11,789 litresB. 98,864 litresC. 102,030 litresD. 198,468 litres13. What is the annular volume in barrels with no string?A. 780 bblsB. 745 bblsC. 130 bblsD. 957 bbls14. What is the height of the influx with a 20-barrel pit gain?A. 392 ftB. 239 ftC. 223 ftD. 199 ft5118 ft5 in. drill pipeID 4 in.239 ft8 in. drill collarID 2!/2 in.12!/4 in. hole with 10 ppg mudApplied Mathematics - Workbook Answers1/41/2Assistant Driller OJT ModulePage: 3.5Rev. 02: January 20051. 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 gi ven depth by the wei ght of the sedi ments, or rocks, and the wei ghtof the fl ui ds that fi l lthe pore spaces i n 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 l oss i n the annul us.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 holewet with no fill up. Using the following data, calculate the reduction in bottomhole pressure.DP. Metal Displacement = .00764 bbls/ftDP. Capacity = .01776 bbls/ftCasing Capacity = .0758 bbls/ftMud Weight = 10 ppgA. 48 psiB. 483 psiC. 600 psiD. 683 psi4. 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 holedry with no fill up. Using the following data, calculate the reduction in bottomhole pressure.DP. Metal Displacement = .00764 bbls/ftDP. Capacity = .01776 bbls/ftCasing Capacity = .0758 bbls/ftMud Weight = 12 ppgA. 650 psiB. 6 psiC. 65 psiD. 130 psi5. Select the two things that are needed to accurately determine initial circulating pressure.A. Drilling pump pressure and mud weightB. Shut-in drill pipe pressure and mud weightC. Slow circulating rate pressure and final circulating pressureD. Sl ow ci rcul ati ng rate pressure and shut-i n dri l lpi pe pressure6. Select the three things that are needed to accurately determine final circulating pressure.A. Drilling pump pressure, drilling mud weight, and kill mud weightB. Shut-in drill pipe pressure, drilling mud weight, and kill mud weightC. Slow circulating rate pressure, drilling mud weight, and kill mud weightD. Slow circulating rate pressure, drilling mud weight, and final circulating pressure7. The driller's method of well control normally requires how many circulations to kill a well?A. One circulationB. Two ci rcul ati onsC. Three circulationsD. Four circulationsPractical Well Control - Workbook AnswersAssistant Driller OJT ModulePage: 3.6 Rev. 02: January 20058. 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 hi gher surface pressure than the wai t-and-wei ght 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 bottomholepressure 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 tokill-rate speed.C. keep SICP constant at the ori gi nalshut-i n val ue by openi ng the choke and bri ngi ng the pump upto ki l l -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 prechargeis approximately ______A. 9 gallons.B. 7 gallons.C. 5 gal l ons.D. 3 gallons.Practical Well Control - Workbook AnswersAssistant Driller OJT ModulePage: 3.7Rev. 02: January 2005WELL DATAWell Depth 10,000 ft TVD11,500 ft MDBit size 8.5 in.Drill Pipe 5 in. OD.19.5 lbs/ftCapacity =0.01776 bbls/ftDrill Collars 61/2in.x213/16 in. x750 ftCapacity =0.00768 bbls/ftCasing 95/8 in.,47 lb/ft. P110 8.681 in. ID100%Internal yield= 10,900 psiSet at 7,000 ft TVDMud weight in use 12 ppgPumps National triplex 12-P-160With 61/2in.LinersCapacity =0.117 bbls/stkPUMP PRESSUREWhile Drilling 2,500 psi at 80 spm (APL =260 psi)Slow Pump Rate 250 psi at 30 spm (APL =75 psi)ANNULAR VOLUMESDrill pipe - Casing = 0.0505 bbls/ftDrill pipe - Open hole = 0.0459 bbls/ftDrill collars - Open hole = 0.0292 bbls/ftWELL CONTROL DATASIDPP = 520 psiSICP = 720 psiGAIN = 12 bblsFRACTURE GRADIENT AT SHOE = .91psi/ftKick Data and Gauges - Workbook AnswersAssistant Driller OJT ModulePage: 3.8 Rev. 02: January 20051. What is the total capacity of the drill string?A. 150 bblsB. 160 bblsC. 197 bblsD. 180 bbls2. Calculate the total annular capacity with the pipe on bottom.A. 482.2 bblsB. 457.5 bblsC. 547.5 bbl sD. 627.6 bbls3. What is the surface to bit time with the pump running at 80 spm?A. 21 mi nsB. 25 minsC. 32 minsD. 39 mins4. Calculate bit to surface time (bottoms up) at 80 spm.A. 58.5 mi nsB. 49.7 minsC. 60.3 minsD. 51.5 mins5. What kill mud is required to balance formation pressure?A. 13.4 ppgB. 13.0 ppgC. 12.4 ppgD. 16.4 ppg6. 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. approxi matel y 270 psi .8. After reaching FCP it is decided to increase the pump speed to 40 spm. What would happen to BHP if the drillpipe pressure is held constant at the original FCP value?A. Increase by about 210 psiB. Decrease by about 210 psiC. Remain constant because drill pipe pressure was not changedD. Increase by about 500 psi9. What is the hydrostatic pressure at the bottom of the hole before the kick?A. 5,800 psiB. 6,800 psiC. 7,800 psiD. 6,240 psiKick Data and Gauges - Workbook AnswersAssistant Driller OJT ModulePage: 3.9Rev. 02: January 200510. What is the ECD on bottom while drilling?A. 15.0 ppgB. 12.5 ppgC. 12.0 ppgD. 13.5 ppg11. At 80 spm what is the annular velocity around the drill collars?A. 412 ft/minB. 210 ft/minC. 506 ft/minD. 321 ft/mi n12. What is the maximum allowable mud weight?A. 17.5 ppgB. 16.5 ppgC. 18.0 ppgD. 19.0 ppg13. What is the approximate length of the influx?A. 1,027 ftB. 850 ftC. 653 ftD. 410 ft14. 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 strokesB. 1,368 strokesC. 1,680 strokesD. 1,538 strokes16. How many strokes will it require to go from bit to shoe?A. 5,364 strokesB. 4,122 strokesC. 1,658 strokesD. 874 strokes17. How long will it take to go from bit to shoe at a pump speed of 30 spm?A. About 214 minsB. About 29 minsC. About 157 minsD. About 55 mi ns18. At 30 spm what is shoe to surface travel time?A. About 101 mi nsB. About 34 minsC. About 214 minsD. About 76 minsKick Data and Gauges - Workbook AnswersAssistant Driller OJT ModulePage: 3.10 Rev. 02: January 200519. If the casing shoe is tested with 12 ppg mud in the hole, how much pressure is applied at the surface to give afracture gradient of .91 psi/ft?A. 1,250 psiB. 1,500 psiC. 2,000 psiD. 1,950 psi20. What would be the new MAASP once the well has been killed?A. 685 psiB. 1,638 psiC. 700 psiD. 585 psi21. At 30 spm how long will it take to pump kill mud to the bit?A. 157 minsB. 214 minsC. 56 mi nsD. 76 mins22. If a 100 psi safety margin is included in the kill mud weight, what would the new kill weight be?A. 15.5 ppgB. 16.0 ppgC. 15.4 ppgD. 13.2 ppg23. What would be the approximate pressure step down from ICP to FCP in psi/100 strokes?A. 30 psi/100 stksB. 46 psi/100 stksC. 50 psi/100 stksD. 66 psi/100 stks24. 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. Nothi ng, everythi ng l ooks okay.Kick Data and Gauges - Workbook Answers01900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSIPUMP SPEEDTOTAL STROKESDRILLPIPE PRESSURE CASING PRESSUREOPEN CLOSECHOKEPOSITION01900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSI770 7203060Assistant Driller OJT ModulePage: 3.11Rev. 02: January 200525. The operation has been going for 10 minutes. What should you do?A. Open the choke a little.B. Close the choke a little.C. Increase the pump speed.D. Decrease the pump speed.E. Nothi ng, everythi ng l ooks okay.26. The pit levels are reported to be increasing slightly. What are you going to do now?A. Open the choke a little.B. Cl ose the choke a l i ttl e.C. Increase the pump speed.D. Decrease the pump speed.E. Nothing, everything looks okay.27. 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.D. Decrease the pump speed.E. Nothi ng, everythi ng l ooks okay.Kick Data and Gauges - Workbook Answers01900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSIPUMP SPEEDTOTAL STROKESDRILLPIPE PRESSURE CASING PRESSUREOPEN CLOSECHOKEPOSITION01900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSI770 7503030001900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSIPUMP SPEEDTOTAL STROKESDRILLPIPE PRESSURE CASING PRESSUREOPEN CLOSECHOKEPOSITION01900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSI750 85030100001900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSIPUMP SPEEDTOTAL STROKESDRILLPIPE PRESSURE CASING PRESSUREOPEN CLOSECHOKEPOSITION01900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSI770 950303000Assistant Driller OJT ModulePage: 3.12 Rev. 02: January 200528. 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.C. Increase the pump speed.D. Decrease the pump speed.E. Good, everythi ng l ooks okay.Kick Data and Gauges - Workbook Answers01900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSIPUMP SPEEDTOTAL STROKESDRILLPIPE PRESSURE CASING PRESSUREOPEN CLOSECHOKEPOSITION01900 1001800 200300 1700400 1600500 1500600 1400700 1300800 1200900 11001000PSI770 520304750Assistant Driller OJT ModulePage: 3.13Rev. 02: January 2005Part I1. Sharp corners, bad drum winding, loops in the line, or operating over small diameter sheaves will cause whattype of damage?A. Crossover wearB. Drum crushC. DoglegsD. Tension breaks2. How does drum crush occur?A. Extreme pressure i s brought down on the wi re by an addi ti onalwrap 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 anchorB. At the top of the crown block sheavesC. At the bottom of the travelling block sheavesD. At the new l ayer posi ti on on the drawworks4. What is a ton-mile?A. The weight of the drill string multiplied by the depth of the holeB. The work needed to move one ton over a one-mi l e di stanceC. The maximum drawworks capacityD. The depth of the hole divided by the weight of the string5. What always takes precedence over ton-miles when it comes to drilling line replacement?A. Vi suali nspecti onB. Depth of trip to be performedC. Weight of assembly to be trippedD. How long until the end of the shift6. What does 6 x 19 IWRC mean?A. The number of wires allowed to be damaged over a given lengthB. 6 strands, at 19 wi res per strand, wrapped around an i ndependent wi re rope coreC. 19 strands, at 6 wires per strand, wrapped around an independent wire rope coreD. 19 strands of size 6 wire, wrapped around an independent wire rope core7. Why do we cut the line rather than spooling more and more onto the drawworks?A. To prevent spooling problemsB. To avoid damage to the line of other wrapsC. To avoid accumulating too much line on the drawworksD. al lof the above8. 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 BD. none of the above9. Maintenance of what equipment has a direct bearing on the condition of a drilling line?A. Crown bl ock, travel l i ng bl ock, drawworks, Crown-O-Mati c, deadl i ne stabi l i zer, deadl i ne anchor,wi rel i ne turnbacksB. Crown block, travelling block, drawworks, Crown-O-Matic, deadline stabilizer, wireline turnbacksC. Crown block, travelling block, drawworks, deadline anchor, wireline turnbacksD. Crown block, travelling block, Crown-O-Matic, deadline stabilizer, deadline anchorDrilling Line Care and Maintenance - Workbook AnswersAssistant Driller OJT ModulePage: 3.14 Rev. 02: January 200510. How should wireline clips be attached to a line?A. Wi th the U-bol ts over the dead end of the l i neB. With the U-bolts over the live end of the lineC. With the base of the clip against the dead end of the lineD. both B and CPart II11. What needs to be reset after string-up or cutoff?A. The drillers brakeB. The drawworks auxiliary brakeC. The Crown-O-Mati cD. none of the above12. How much gap should the load cell sensator have without a load on the hook?A.5/ 8i n.B.3/8in.C.4/16in.D. none of the above13. How often should the crown block sheaves be greased?A. Every 8 hoursB. After tripping onlyC. After 200 ton-milesD. Daily14. What is likely to be the effect of a damaged sheave?A. Stuck pipeB. Slow rate of penetrationC. Higher rotary torqueD. Damaged or broken dri l l i ng l i ne15. What should be inspected on the drawworks?A. Damaged groovingB. Wear platesC. Wireline turnbacksD. al lof the above16. What should be attached to the derrick above the drawworks to prevent fastline flopping?A. A wi rel i ne gui deB. A deadline stabilizerC. A deadline anchorD. A turnback roller17. Brass inserts can be replaced in what piece of equipment?A. A wireline guideB. A deadline stabilizerC. A deadl i ne anchorD. A turnback roller18. How many wraps of line should be put on the drawworks with the travelling block at the lower pick up point?A. 18B. 16C. 12D. 8Drilling Line Care and Maintenance - Workbook AnswersAssistant Driller OJT ModulePage: 3.15Rev. 02: January 2005PartIII19. What is the standard operating safety factor for drilling line?A. SevenB. SixC. FiveD. Four20. Where are the critical points of wear on the drilling line?A. At the top of the crown block sheaves on pickup pointsB. At the bottom of the travelling block sheaves on pickup pointsC. At crossover points on drawworks and at the deadline anchorD. al lof the above21. 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. al lof the above22. When should visual inspection of drilling line take precedence over ton-mile goals?A. AlwaysB. After jarring operationsC. Prior to running a heavy casing stringD. During an end of well inspection23. What does the wire rope service curve explain?A. The required safety factorB. The number of days between slip and cutC. The rel ati onshi p between safety factor and ton-mi l e goal sD. How much line to be cut off after slippingPart IVRefer to the ton-mi l es tabl es i n the IADC Dri l l i ng Manualto answer questi ons 2426.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 ppg24. What is the excess weight allowance?A. 45,900 lbsB. 35,900 lbsC. 25,900 lbsD. 15,900 lbs25. How many ton-miles were incurred tripping?A. 600B. 547C. 494D. 46426. The trip before this involved 444 ton-miles tripping. How many ton-miles were used in drilling between trips?A. 468B. 309C. 150D. 60Drilling Line Care and Maintenance - Workbook AnswersAssistant Driller OJT ModulePage: 3.16 Rev. 02: January 2005TON-MILES FORMULA Calculator MethodRefer to the IADC Drilling Manual: Ton-Mile Calculations Section and use the calculation below to answer questions2729.Tr= D(Ls+D ) Wm+ D(M +1/2 C)10,560,000 2,640,000You 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 ppg27. What is the excess weight allowance?A. 60,000 lbsB. 50,000 lbsC. 40,000 lbsD. 30,000 lbs28. How many ton-miles were incurred while tripping?A. 537B. 493C. 411D. 38629. The trip before this involved 245 ton-miles. How many ton-miles were used in drilling between trips?A. 876B. 744C. 498D. 423Drilling Line Care and Maintenance - Workbook AnswersAssistant Driller OJT ModulePage: 3.17Rev. 02: January 2005Section: Hole Angle Change and Causes of Hole Deviation1. Straight-hole drilling should result in ______A. a perfectly straight hole.B. a troubl e-free hol e wi th no sharp edges or changes i n di recti on.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 aconstant inclination from the vertical of 630'.A. True verti caldepth = 4,968 ft; hori zontaldri ft = 566 ftB. True vertical depth =5,000 ft; horizontal drift =0 ftC. True vertical depth =99.36 ft; horizontal drift =11.32 ftD. True vertical depth =993.6 ft; horizontal drift =113.2 ft3. Doglegs are likely to develop when ______A. the rate of hol e angl e change i s greater than 3 per 100 feet of hol e.B. the total hole angle change is greater than 3.C. wei ght on bi t i s suddenl y and drasti cal l y 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 SurveyVertical angle: 8 15' Vertical angle: 2 45'(8 1/4) (2 3/4)Direction: S 34 E Direction: S 9 EDepth: 6,400 feet Depth: 6,475 feetA. Dogl eg severi ty = 7.82/100'B. Dogleg severity =6.12/100'C. Dogleg severity =5.87/100'D. Dogleg severity =7.825. 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. i n the top part of the hol e.6. Which of the following factors will increase the amount of fatigue damage to drill pipe?A. Corrosi ve dri l l i ng fl ui dsB. Low tensile load in the pipe at a doglegC. A severe dogl egD. none of the above7. Hole deviation is likely to occur in ______A. l ami nar formati ons wi th di ps up to 45.B. uniform formations with dips up to 25.C. formati ons wi th al ternati ng hard and soft l ayers.D. l ami nar formati ons wi th di ps 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. cl i mb updi p.Drilling a Straight Hole - Workbook AnswersAssistant Driller OJT ModulePage: 3.18 Rev. 02: January 20059. 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. l ess wei ght i s requi red.B. more weight is required.C. the dri l lstem wi l lbend l ess i n soft formati ons than i n 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. Dul lbi tsB. Low bit weightC. Mnimum clearance between the drill collars and the wall of the holeD. Undersi zed dri l lcol l ars14. A spiraled and undersized hole can result from ______A. low penetration rates in soft formations.B. a limber and unstabilized BHA.C. abrupt reduction of bit weight.D. exceeding the total hole angle change limit.Section: Controlling Hole Deviation15. When formation characteristics cause the wellbore to drift upstructure, the surface location can be offset. Thisdrifting has the result that ______A. the surface location will be moved downstructure and the natural tendency of the formation willguide 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 gravi ty pul l i ng on an unsupported l ength of dri l lcol l ar.B. equivalent to the equilibrium condition.C. never greater than the formation reaction.D. i ncreased by a hi gh poi nt of tangency.ABCDrilling a Straight Hole - Workbook AnswersAssistant Driller OJT ModulePage: 3.19Rev. 02: January 200518. 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 drillingconditions:Hole size: 81/8 in. Hole angle: 4Hole class: R Drill collar size: 7 in.Formation dip: 15A. The dri l l er can run 39,162 l bs on the bi t wi th the 7-i n. dri l lcol l ars and mai ntai n hol e angl e.B. Bi t wei ght can be i ncreased to 68,500 l bs i f 7 1/2-i n. dri l lcol l ars are used and a stabi l i zer runat 60 ft above the bi t wi thout changi ng hol e angl e.C. Hol e angl e can be reduced to 2 by reduci ng bi t wei ght by 7,362 l bs and addi ng a stabi l i zer 80 ftabove the bi t.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. TrueB. False23. The best stabilizer arrangement in a pendulum assembly is composed of ______A. pl acement of a second stabi l i zer 30 feet above the ful crum stabi l i zer.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. poi nt D.25. The term "gun barrel approach" is sometimes used to refer to a ______A. perfectl y strai ght hol e.B. pendulum assembly.C. packed-hol e assembl y.D. fulcrum stabilizer.Drilling a Straight Hole - Workbook AnswersADCBAssistant Driller OJT ModulePage: 3.20 Rev. 02: January 200526. 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 wouldbe most suitable for ______A. mild crooked-hole conditions.B. moderate crooked-hole conditions.C. severe crooked-hole conditions.D. none of the above30. 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 orpacked pendulum BHA.A. TrueB. False32. 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 Tools34. 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.Drilling a Straight Hole - Workbook AnswersAssistant Driller OJT ModulePage: 3.21Rev. 02: January 200535. How much does a standard-length drill collar weigh if it has a 51/2-inch OD and 21/4-inch ID?A. 67 lbsB. 2,010 l bsC. 6,700 lbsD. 201.0 lbs36. What total weight of drill collars in air is required with the following drilling conditions?Bit weight required: 68,500 lbsSafety factor: 15%Drilling mud density: 12.2 ppgVertical hole: 0 inclinationA. 6,457 lbsB. 68,500 lbsC. 78,775 lbsD. 96,775 lbs37. How many 71/4-inch OD x 21/4-inch ID standard-length drill collars will be needed with the following drillingconditions?Bit weight required: 32,440 lbsDrilling mud density: 9.8 ppgSafety factor: 15%A. 14B. 12C. 8D. 738. If seven standard-length 6-inch OD x 213/16-inch ID drill collars are used, how many standard-length71/2-inch OD x 213/16-inch ID collars will be needed with the following conditions?Bit weight required: 46,129 lbsDrilling mud density: 12 ppgSafety factor: 17%A. 24B. 14C. 13D. 739. The point at which the drill collar string changes from compression to tension is called the _____A. neutralpoi nt.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 collarsavailable should be used because drill collars cannot be too large in crooked-hole country.A. TrueB. False41. 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 possi