ROTARY DRILLING BITS This Chapter Covers The Following Items

ROTARY DRILLING BITSThis chapter covers the following items¾ Roller cone bits¾ The three cone bits Principle features Design factors Rock bit classifications¾ Poly diamond compact (PDC) bits¾ Diamond bits¾ Bit selection¾ Bit dullness¾ Well bit record and geological informationIntroduction¾ Drilling bit represents the heart of drill string¾ Proper selection is required¾ It crushes the rock under the action of WOB and RPM¾ Chippings are flushed away with mud¾ The process results in a drill holeRoller cone bits¾ Employs cones rotates about their own axis¾ Used in mining and civil engineering¾ First used in 1920¾ Cones can be milled teeth cut from the body or tungsten carbidebuttons interested into the cones¾ There are three types: Two cone bit, milled tooth used for soft formation Three cone bit most widely used, milled or insert Four cone bit, milled tooth used for drilling large diameter26 in (660.4 mm)Three cone bit principle features¾ Three cutting cones, each fitted on a leg with suitable bearing¾ Legs are welded together to form the cylindrical section1

¾ Section is threaded to make bin¾ Each leg provided with an openings that can be reduced with anozzle to give high jetting fluid velocity¾ Factors influencing the design are: type and hardness offormation and size of drilled hole¾ Formation hardness dictated the manufacture materials¾ High content of nickel steel with molybdenum is usedDesign factors¾ Bit design depend on formation properties and hole size¾ Legs are same but cutters are different¾ Three logs should be equally loaded¾ The main design factors are Journal bearing, amount of offset,teeth, bearing and relationship between teeth and bearingJournal bearing¾ The bearing load carrying surface¾ Journal angle is the angle formed by a line perpendicular to theaxis of the journal and the axis of the bit¾ Magnitude affect the size of the cone¾ Increase in angle decrease cone size¾ The smaller the angle the greater the gouging and scrapingaction¾ Optimum journal angle for soft and hard rock bits are 33 and 36Cone offset¾ The degree of offset is defined as the horizontal distancebetween the axis of the bit and a vertical plane through the axisof the journal¾ It forces the cone to rotate around the axis of the bit¾ The cone slips as it rotates causing tearing and gouging action¾ Amount of offset directly relates to the strength of drilled rock¾ Large offset used for soft formation¾ Hard brittle rock need no offset¾ Medium hard rock need up to 2 offsetTeeth¾ Length and geometry relate the rock strength¾ Size of the cone and bearing structure affect the teeth2

¾ Teeth design criteria are:Spacing and interfitting of teeth governed by tooth strength,depth and included angleShape and length, dictated by formation characteristicsTypes of teeth, milled or inserted¾ Log slider and widely spaced teeth used for soft rock¾ Long teeth allow results in breaking greater volume¾ Wide spacing allows easy removal of drilled cuttings¾ The included angle for soft rock from 39 to 42¾ Medium hard would have a moderate number of teeth and 43 to45 included angle¾ Hard rocks need 45 to 50 included angle¾ Milled teeth are faced with hardening metal to reduce wear¾ Milled tooth bits are suitable for soft formation¾ Insert are used for hard formation¾ There are several types of insert to suit the hardness¾ Chisel-shaped for soft rock¾ Round or spherical for medium and hard rocksBearings¾ Functions: Support radial load Support thrust or axial loads Secure the cone on the leg¾ Supporting loads is achieved by outer and nose bearing¾ Ball and friction bearings secure the cone on the leg¾ Two different bearing are available: antifriction and friction¾ Antifriction bearings or roller are two types: Roller-ball-roller(RBR), and roller-ball-friction¾ RBR, nose roller; intermediate ball; and outer roller¾ The ball secure the cone¾ Size influenced by journal angle and cone size¾ RBR suffers from spalling of the races of the pin¾ RBR bit have short life¾ Normally used with bit with diameter greater than 12.25 in withadequate space and in situation where high rotary speed isrequired3

Roller-ball-friction (RBF)¾ Friction type bearing at the nose¾ The inner ball and outer roller as the same as RBR¾ The friction consists of a special case-harden bushing pressedinto the nose of the cone¾ Introduced to overcome the shortcomings of RBR¾ Allow thicker cone section¾ Larger pin diameter¾ Common for bit sizes up to 12.25 inFriction bearing¾ Nose and outer bearing replaced by friction bearingBearing lubrication¾ Bearing classified as sealed or non sealed¾ Non sealed are lubricated by mud system through the face wherethe cone meets the journal¾ Sealed are lubricated by custom made system built within the legbody¾ Lubrication by mud is generally recommended¾ Sealed bearing consists of bearing, seal, reservoir and pressurecompensator¾ The seal is an O-ring type placed at the contact between the coneand the bearing lowermost point¾ The reservoir provides lubricants (special grease) to the bearingthrough a passageway in the leg¾ Pressure compensator has a flexible diaphragm operates within ametal protector¾ Maintains equal pressure inside and outside bearings¾ Equipped with a pressure relief valve¾ It protect the bearing seal when heat cause breakdown of greaseinto gaseous componentsRock bit classifications¾ IADC prepared a comparison chart, in 1972¾ Each bit is design by three code system4

¾ First code classifies the cutting structure, 1-3 for teeth soft,medium and hard, 5-8 for insert, soft medium hard semiabrasive, extremely hard and abrasive, 4 for future¾ Soft rock require long, slim and widely spaced teeth¾ Medium requires short and less widely teeth¾ Hard requires very short and closely spaced teeth¾ Code 2 relates to formation hardness with division from 1to 4from softest to hardest¾ Code 3 for mechanical features of the bit, sealed non-sealed etc¾ Major bit companies are Hughes, Security, Reed, and Smith¾ Each company give there tables with IADC specificationsPolycrystalline Diamond Compact (PDC) bits¾ A new generation of old drag, fishtail bit¾ Have no moving parts or bearings¾ Break the rock in shear and no compression (ploughing /grindingaction) as in diamond bits¾ Breaking in shear need less energy than in compression¾ Less weight in bit, less wear and tear on rig and drill string¾ Applied for soft to medium hard rock¾ Employs large number of cutting called a drill blank¾ The blank is made by bonding a layer of polydiamondcrystalline (man made diamond) to a cemented tungsten carbidesubstrate in high pressure high temperature process¾ The blanks are bonded to a specially shaped tungsten carbidestuds and then attached to the bit¾ During drilling the compact provides a continuous sharp cuttingedge¾ PDC design influenced by nine factors: body materials, bitprofile, gauge protection, cutter shape, number of cutters, cuttershape, cutter exposure, cutter orientation, and hydraulics¾ Bit body materials: two are available; heat-treated alloy steelused in roller cone bits and tungsten carbide matrix used innatural diamond¾ Steel body is less durable and less resistance to erosion¾ Tungsten carbide manufactured as natural diamond¾ Allow more complex profile¾ Bond between crystals and body destroyed at 750 C5

¾ Bit profile affects cleaning and stability of the hole and gaugeprotection¾ Two are common: double cone allows more cutters, shallowcone affords less area of cleaning¾ Gauge protection: in steel body, tungsten carbide inserts placednear the edge: matrix body bit utilizes natural diamond for gaugeprotection.¾ Nowadays compact is fixed for gauge protection¾ Cutter shape: three basic shapes; standard cylindrical, chisel orparabolic, and convex¾ Cutter concentration: field experience and fracture mechanicsmodels used to locate cutters for maximum cutting andminimum wear and torque¾ Cutter exposure: its increases gives higher penetration rate¾ Cutter orientation: described by back and side rake angle¾ Back rake between 0 and 25¾ Penetration rate decreases with back rake increase, but resistanceto cutting edge damage increases¾ Side rake assist hole cleaning by directing cutting towards theannulus¾ Hydraulics: PDC bits require optimum hydraulic for holecleaning¾ More than three nozzles are mounted in the bit¾ Nozzles may not be round and determined by total flow area(TFA)¾ TFA determines the size of nozzles according to manufacturers’chart¾ PDC bits are also used in coringDiamond bits¾ The cutting elements are large number of small-sized diamondsgeometrically distributed across a tungsten carbide body¾ No moving parts¾ Used for hard and abrasive rocks when long bit run is required¾ Used in deep and offshore wells where rig cost is very high¾ Used for drilling and coring¾ Diamond is the hardest metal with the highest thermalconductivity6

¾ Heat dissipated quickly from the cutting parts protectingdiamond loss¾ Size of diamond determine the type of rock¾ Large diamond for soft rocks and small-sized for hard¾ Majority of diamond bits used for coringBit selection¾ Four methods are available: cost per foot, specific energy, bitdullness, and offset wells bit recordCost per foot¾ The following equation is used:¾C B (T t )R /ftFBTtRF bit cost trip time, hrs drilling time, hrs rig cost /hr footage drilled , ft¾¾¾¾¾¾Equation controlled by five variableThese factors have uncertainties in calculationsCost per foot is plotted against timeCost decreases with time and start to increase againLowest cost is used to pull bit out of holeBecause of uncertainties, pulling out of bit on the evidence ofone value may prove to be premature¾ C and IC should be appliedSpecific energy (SE)¾ Energy required to remove unit volume (SE)¾ Derived as:E W .2π R.N¾WNin.lb weight on bit, lb rotary speed, rpm7

R¾V (π R2).PR¾ SE¾¾ bit radius E/VSE 20W .N .tD.FSE 2.35 W .ND.PRPR¾in3in.lb/in3Mj/m3 penetration rateSE 20W .N .tD.Fin.lb/in3¾ For constant W and N and rock properties, high SE indicate lowbit performanceBit dullness¾ Degree of dullness can be used for proper selection¾ Described by tooth and bearing¾ Reported in 1/8¾ Coded in a form T1 to T8 and B1 to B8¾ T1 indicated 1/8 of teeth has gone¾ B8 indicates that bearing life has gone¾ With grading and coding bit can be properly selected¾ Bit diameter shows in gauge or out of gauge hole¾ Other grading records broken teeth, lost cones, eroded cones, .Etc.Well bit record and geological information¾ Offset wells and geological information can provide usefulguides for the selection¾ Sonic logs can be used to provide an estimate of rock strength8

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The following diagrams are the three types of claw cutters.10

1.Different width and deepness straight claws cutters(MC)*Different shapes of claws cutter (TC)*11

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¾ Roller cone bits ¾ The three cone bits Principle features Design factors Rock bit classifications ¾ Poly diamond compact (PDC) bits ¾ Diamond bits ¾ Bit selection ¾ Bit dullness ¾ Well bit record and geological information Intr