Turbine Motor for Coiled tubing Applications

7/30/2019 Turbine Motor for Coiled tubing Applications

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Turbodrilling in the Hot-Hole EnvironmentPat Herbert, Sii Dyna-Drill

SummaryHistorically, geothennal and other types of hot-holedrilling have presented what seemed to be insunnountable barriers to efficient and extended use of downholedrilling motors, particularly those containing elastomericbearing or motor components. Typical temperatures of350 to 700F (177 to 371C) damage the elastomers andcreate other operating problems, reducing the life of themotors and their ability to drill efficiently. Recent innovations in turbodrill design have opened heretoforeunrealized potentials and have allowed, for the first time,extended downhole drilling time in hot-hole conditions.The unique feature of this turbodrill is the lack of anyelastomers or other temperature-sensitive materials. Itscapabilities are matched closely to the requirements ofdrilling in elevated-temperature environments. The bearing assembly can withstand conditions encountered intypical geothennal fonnations and provides the performance necessary to stay in the hole. The result is increased rate of penetration (ROP) and more economicaldrilling.IntroductionTypical hot wells drilled in the U.S. present fonnidabletechnical difficulties in the effective use of such standardtools as downhole motors, bits, and surveying instruments that are used every day in the petroleum drilling industry. The foremost obstacle to the downhole lifeof these tools is elevated-temperature environments. Allpositive-displacement motors and turbodrills currentlyused contain elastomeric components that cannot survivein the temperature ranges of 350 to 700F (177 to371C). This disadvantage provided the impetus fordevelopment of a new generation of turbodrills capableof perfonning under these conditions. Turbodrills havebeen developed that can withstand high operating0149-2136/8210010-9936$00.25Copyright 1982 Society of Petroleum Engineers of AIME

OCTOBER 1982

temperatures while providing output power needed todrill the most commonly encountered fonnations (e.g.,graywackes, granite, siltstone, and claystone), which,by their lithology, present difficult drilling conditions.These conditions also play havoc on traditional fonnsof drilling equipment, adding importance to the development of downhole motors. Standard rotary assembliesused for drilling geothennal and hot petroleum wells donot realize the same life as their counterparts in mostother nonnal drilling operations. This is true for two major reasons: (1) doglegs or sharp bends in the hole accelerate wear on the rotating assembly because of wallfriction with these hard fonnations, and (2) the higherstresses, both bending and thennal, reduce the fatiguelife of the material. Therefore, all drilling must be doneby placing all available rotational power at the bit withdownhole motors for economy. Another important factorto consider is escalating costs associated with drilling,making the potential savings available with downholemotors a major factor in the increased use of these tools.

Design FeaturesA turbodrill consists of a multistage motor, each stagecomprising a rotor and stator. The stator, the stationarypart of the motor, is attached rigidly to the housing. Therotor is attached rigidly to the main shaft and makes up arotating assembly (Fig. 1). The complete motorassembly is a multitude of stages stacked one upon theother in sufficient number (usually more than 100) todevelop the power dictated by the blade profile design.The turbodrill develops this power by directing thehydraulic flow of drilling fluid passing through the statorto the rotor blades, causing rotation. Fig. 2 shows atypical blade configuration of 1V2 stages and the flow ofdrilling fluid through the motor. Visualizing the impactof the fluid on the individual blade segments reveals howthe flow is deflected. The input flow will split into com-

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Housing

Fig. l-Typical motor assembly.

INPUT FLOW

~5'-m iR J[] IT - ~ ~ , : ' : ; ~ : Of5 \\n _

I"-Entrance Angle

-e=Exit Angle

Fig. 2-Energy transfer.

P\DW RAft Q. SOC) . . . . . ,WoIIT'I.II,

110 .0

.....1100 to

Fig. 3-Typical performance curve.2370

ponents that will produce thrust, rotation, and torque.The splitting of this fluid is controlled by the entranceand exit angles of the blade profile, which can bemanipulated to develop any power output required. Theflow is divided according to a velocity triangle (notshown) dictated by the blade profile, and, when thistriangle is optimized, the output power is optimized.The operating characteristics of the turbodrill vary inrelation to the flow rate of drilling fluid by the followingformulas. *(ql)

WI=--W,qA n _ (ql) 2 A""'I--- u.p,qT1 = (qJ} 2 T,q

F (qJ} 2 FTj = -- T,q

where W is the turbine speed, q is the input flow, .:lp isthe motor pressure drop, T is the output torque, PHis theoutput power, and F T is the axial thrust.In reference to the power and thrust equations, it isevident that the turbodrill is a flow machine, as opposedto positive-displacement motors, which are pressuremachines. Typically, for the same flow rates, the turbodrill will develop the same output horsepower as acomparably sized positive-displacement motor but willrequire a higher pressure drop. The power output of theturbodrill is highly dependent on the amount of fluidpassing over the blades. The motor should not consumeso much fluid that, to run at its optimal output level, itwould exceed pressure limitations of current mudsystems. Matching design to field requirements can beensured by controlling the blade design so that when thegeneral desired output requirements are established, ablade profile is achieved that provides the ideal motorassembly for those characteristics sought.A unique feature of the stacked-stage design is thecapability to add or to remove stages of the motor to staywithin a prescribed hydraulics program that is worked upon each new well to be drilled. Hydraulic calculationsare performed on this proposed drilling assembly to account for all losses in the interval to be drilled. The remaining system pressure is compared with that which theturbodrill will require, based on the selected bit and formation. With this information, if necessary, the turbodrill can be tuned to provide optimal power by addingor removing motor stages. Any undue strain on the mudsystem will be avoided, and a more efficient and productive drilling system will be provided for the mosteconomical drilling of the well.

The performance of turbodrills varies only slightly with mud weights and plasticviscosity; their limitations relate to overall system pressure capabilities.JOURNAL OF PETROLEUM TECHNOLOGY


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Fig. 3 depicts a typical perfonnance curve of a turbodrill designed for long-interval drilling. The curve is aresult of perfonnance tests with water, and the data areconsidered baseline for use with the fonnulas in Fig. 2when perfonnances for changing conditions are computed. Note that the horsepower curve is bell-shapedover the range of revolutions per minute (rpm) at thisconstant flow rate. The horsepower is maximized at thepeak of this curve, and this occurs at the nominal speed.The horsepower curve is bounded by two rpm values: thelowest is the "stall" speed and the highest is the"runaway" speed. The output torque rises to a maximum value at the stall speed from zero at the runawayspeed. Torque is one of the components of the velocitytriangle whose magnitude depends on blade geometry.Therefore, we can alter this geometry to developmachines that will provide high-torque/low-speed orlow-torque/high-speed characteristics. Most designs fallcomfortably in a range between those extremes to coverthe largest number of applications possible. The pressuredrop is nearly constant at all speeds because the fluidpassing through each motor stage is entirely turbulent.This turbulence also leaves the pressure drop and hencethe output power unaffected by the plastic viscosity ofthe drilling fluid used for power development.The turbine motor section is attached to the bearingassembly, which can be of any proprietary designcapable of withstanding thrust loads of the turbine motorthat are caused by pressure forces acting on the rotorblades and by drilling loads imposed by the fonnationsencountered. Fig. 4 shows such an arrangement.These thrust loads are of a bidirectional nature; therotor section of the motor creates a downthrust, and thefonnation, with the application of bit weight, creates anupthrust. In the overall bearing design, careful consideration must be given to the type of drilling to bedone. This bearing-loading arrangement is shown in Fig.5. For optimal bearing life, the two forces can be balanced and theoretically can provide a zero bearing !oad.Balancing the tool in this manner not only provides extended bearing-assembly life but also ensures correcthydraulic spacing in the blade stages to provide increased efficiency and to preclude any loss of bladeheight from rubbing wear. This ideal can be approachedthrough an accurate hydraulics program, and all effortsshould be directed toward this end. Yet in actual practiceit has been shown that there is either an excess offbottom or an excess on-bottom thrust load. In addition towhat might be called static loads, the use of conventionalthree-cone bits can introduce dynamic loads with frequencies on the order of three times the rotative speedand amplitudes, approaching two to three times theweight on bit (WOB). Irrespective of these loads, inmost cases the amount of weight required to maximizeROP places the tool outside the optimal load range. Veryhigh radial loads are also quite common and constitute acritical factor in design considerations. It is thereforevery important to have a bearing system capable ofwithstanding these loads during operations in a mud environment with high temperatures. The assembly in Fig.4 is of the type required for these conditions.Another important consideration is the provision formaximum hydraulic horsepower to the bit. To cover allbit hydraulic requirements, the flow-restrictingOCTOBER 1982

Fig. 4-Mud-lubricated bearing assembly.

Fig. 5-Schematic of bearing loading.2371


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capabilities of the bearing assembly must fall within therange of 150 to 1,000 psi (1.03 to 6.89 MPa) but mustnot affect tool perfonnance or life adversely. Thisamount of restriction allows diversion of 95 % of thedrilling fluid for circulation through the bit nozzles or thetotal flow area of the diamond bit. Restriction capacity isachieved with seals or proprietary orifice designs such asthose used in mud-lubricated systems. The knowledgegained from second-generation positive-displacementmotors used for long-interval drilling has provided amud-lubricated bearing assembly design that meets orexceeds all the requirements mentioned previously. Thefunction of seals in the bearing assembly must be designed to meet the same criteria. To date, no seal hasbeen developed that will guarantee consistent performance and reliability of the magnitude necessary forhigh-speed mud-driven motors to compete economicallywith rotary in geothennal and hot-hole drilling.

The successful application of turbodrills requires controlled rotational speed. I f left alone (i.e., off-bottom,full circulation), turbodrills tend to reach the runawayspeed. This is usually on the order of two times the optimal or nominal perfonnance speed. Speeds of thismagnitude are highly detrimental to the motor and bearing assemblies. Maintaining speed at or near the optimallevel for maximizing ROP and for deriving all the outputpower capabilities of the motor is essential for successfuluse of turbodrills. To control speeds it is necessary firstto detennine the magnitude of speed at the surface andthereby to optimize penetration and bit perfonnance according to the prescribed drilling program. Tachometersof various designs are available and have been tested infield applications. It would not be appropriate to comment on advantages or disadvantages of one design overanother, but we emphasize that their use in turbodrillingis very important. Succinct and easily managed surfacereadout equipment for the tachometer is of equal importance and ensures a high degree of control over the turbodrill. As with other motors, speed may be controlledwith the application of additional WOB or by alterationsin the volume flow of drilling fluid. In any case, knowing the speed of the motor pennits good control over thesuccess of any turbodrill application.Turbodrill UseTurbodrills have been developed and made availableboth for directional and for long-interval applications.The run data presented here are from wells (1) where useof the tool was planned and (2) where the tool was considered a last resort after drilling difficllities were encountered. Depending on the need, taropdrills can be runwith all the drilling tools needed for directional drilling

TABLE1-TURBODRILLING PARAMETERS,EXAMPLE 1LocationHole size, in. (cm)FormationMud weight, Ibm/gal (kg/m 3 )Hole temperature, OF (0C)Depth in, It (m)Bent sub, degrees2372

Geysers geothermal field,northern California12% (31.11)graywacke, greenstone9.0 (1078)380 (193)2,800 (853)

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with positive-displacement motors (bent subs, steeringtools, etc.). For flexibility in the drilling program, turbodrills lend themselves well to the use of clamp-on-typestabilizers to control direction and bit trajectory. Allother drill string components can be used virtually unchanged from a standard rotary assembly.Turbodrills are designed for optimal use with naturalor synthetic polycrystalline diamond (PCD) bits, sincethe higher rotational speeds associated with turbodrillingare highly detrimental to standard rock bits. As with allbits and drilling systems, these statements requirequalification. Not all perfonnances can be generalizedwith regard to turbodrill/bit combinations, and muchmore infonnation, experience, and tool developmentmust be realized to establish consistent perfonnance.In the North Sea, substantial progress has been madein petroleum drilling with PCD bit/turbodrill systems,especially in Cretaceous/Jurassic fonnations with use ofoil-base muds. In these sections, high ROP's have beenachieved with very light drilling weights coupled withhigh drilling speeds. Geothennal fonnations are typically much more difficult to penetrate, and oil-base mudsare not used. The typical system used for these fonnations is water or light muds combined with heavy bitweights. These weights, however, usually are lessenedduring periods of directional drilling. However, it is wellwithin the realm of possibility to encounter oil-base drilling fluids when other hot petroleum wells are drilled.The importance of proper tool maintenance should notbe overlooked. Quite often this subject is not given ample discussion. Turbodrills are more complicated thanpositive-displacement-type drilling motors, and thismust be a major consideration during the design phase.These tools require careful assembly and disassemblyprocedures to protect the expensive motor assemblycomponents from unnecessary and premature damage;this protection is critical to the successful application ofthe tool in the field.

Turbodrills should not be run in the hole withoutscreens in the mudline. Even in the cleanest of systems,debris of one fonn or another can enter the mudline andcan cause a tool failure. The rotors and stators making upthe motor assembly cannot tolerate junk of any kind,even some types of lost circulation materials. Carefulconsideration must be given to this requirement, again toensure that the turbodrill will perfonn as expected.Once the system has been prepared and the turbodrillis ready to go into the hole, the turbodrill should betested on the rig floor. (One advantage of turbo drills withball-bearing assemblies is that they can rotate freely witha small volume of fluid. Testing will not require undueeffort or time from the operator.) By circulating the drilling fluid through the motor, the operator is assured thatthe motor has been serviced properly and that there areno problems to hinder operations.

Applications-DirectionalThe turbodrills used in the following applications were5-in. (l2.7-cm) and 7-in. (17.78-cm) OD, with 100 and120 stages. The bearing assembly is a mud-lubricatedball-bearing type, with a flow restriction capability of1,0OO-psi (6.89-MPa) bit-pressure drop.

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Example 1Data for Example 1 are given in Table 1. Rotary penetration with three-cone rock bits had been 6 to 61f2 ft/hr(1.83 to 1.98 m/h) before the turbodrill was run in thehole. The turbodrill, with the same bits, increasedpenetration to an average of 22 ft/hr (6.7 m/h). Typicalbit weights were on the order of 10,000 to 12,000 Ibm(4536 to 5443 kg), with a maximum of 17,000 Ibm(7711 kg). The directional drilling job was completed in131 ft (40 m), and the only limitation on staying in thehole was rapid wear of the rock bits, which averaged 4 to5 hours' life. A job of this type illustrates that using rockbits on the tool is not recommended, because the motoris too fast for typical three-cone bit designs. The resultsare early failures, especially to the gauge of the bit.Example 2This run was similar to Example 1 (see Table 1), but thedepth in was 2,300 ft (701 m). The same tool used forExample 1 was shipped directly to this location withoutany intervening shop maintenance. Penetration was increased to 20 ft/hr (6.09 m/h) from the 5 to 6 ft/hr (1.52to 1.83 m/h) achieved with rotary.Example 3Data for Example 3 are given in Table 2. Rotary drillinghad deviated the hole very close to the property line,2,000 ft (609 m) from the target depth of 11,000 ft (3353m). Hole temperature was 520F (271C) at 9,000 ft(2743 m) and 575F (302C) at 10,200 ft (3109 m). Theformation was medium-hard siltstone. Because of severedoglegs, keyseats, and other factors, the drill string wassticking. This happened twice with the turbodrill in thehole, so that 200,000- to 300,000-lbf (889 644- to1X 10 6-N) jarring forces were sustained by the tool 12times. Rock bits initially were run on this tool with avery high failure rate resulting from the 800- to1,000-rpm turbodrill operating speed. Continual loss ofgauge required reaming to bottom on each subsequentrun. Normally this was done at light bit weights and fullhydraulics, which placed the turbodrills in an unbalancedhydraulic thrust condition for extended periods. In mostcases it was difficult to apply enough weight to balancethe bearings because of the critical nature of controllingdeviation. Because of this severe directional requirement, bit weights were on the order of 4,000 to 6,000Ibm (1814 kg) on rock bits; 10,000 to 15,000 Ibm (4536to 6804 kg) on diamond bits; and 14,000 to 16,000 Ibm(6350 to 7257 kg) on a PCD bit.A 2 bent sub above the tool created a tight fit for a7-in. (17.78-cm) OD turbodrill in an 81f2-in. (21.6-cm)hole. As a result, very high side loads were placed on the

radial bearings, which the tool handled with no problems. ROP's with the rock bits were 8 to 14 ft/hr (2.4 to4.3 m/h) when light weights were run.The rate of change in turning the hole was inadequate,so a PCD bit was run. (This run was preceded by that ofa rock bit that, when pulled, showed a loss of 11,4 in.(3.17 cm) off the gauge, leaving the balls and roller bearings in the hole. After most of the junk in the hole wasrecovered, the PCD bit was run in with the turbodrill.)This combination was very aggressive and succeeded inturning the hole 6 in 37 ft (11.2 m). At this point thepenetration ceased, and later inspection showed that thebit was completely worn. After the PCD bit was pulled,the follow-through drilling with a turbodrill/diamondsidetrack bit combination showed significant hole direction change. (When the sidetrack bit went into the hole,it became stuck on a gap in the casing. The PCD bit isbelieved to have hit this abutment, which could haveknocked off a stud or two. This occurrence, coupled withthe remaining roller and ball-bearing junk in the hole,may explain the bit's short life.)The hole then was turbodrilled for 262 ft (79.8 m) at12 ft/hr (3.5 m/h); at that depth the program called for areturn to conventional drilling. After being drilled conventionally for 407 ft (124 m), the hole again went offcourse, and two more turbodrill runs were necessary.The turbodrills were used to within 800 ft (244 m) of thetarget depth, on course, and the hole was completed conventionally. This particular well dramatically demonstrates the use of downhole motors to save a well thatotherwise would have been abandoned. Standardpositive-displacement motors and existing turbodrillswith elastomeric components could not have survived inthis environment. A tool with hot-hole capabilitiesproved very useful.Example 4Data for Example 4 are given in Table 3. Conventionaldrilling had deviated the well off course, and the objective was to directionally drill back to the planned courseby using a turbodrill. Carbide-insert rock bits were beingused, and we ran these with the turbodrill, starting at7,845 ft (2391 m).The severity of doglegs in this hole rendered effectivebit-weight control difficult at best. In addition, the holewas 1/32 in. (0.079 cm) undergauge and the bit was 1/32in. (0.079 cm) overgauge. It was necessary to conditionthe hole to seat the bit adequately. Reaming in this manner places the tool in an unbalanced hydraulic conditionduring full-volume circulation. In this posture, the bearings must sustain the full hydraulic thrust of the motorassembly coupled with high speeds-the worst possible

TABLE2 -TURBODRILLING PARAMETERS,EXAMPLE 3

OCTOBER 1982

LocationHole size, in. (cm)FormationMud weight at "mill temperature," cooled,Ibm/gal (kg/m 3 )Hole temperature, OF (0C)Depth in, ft (m)Bent sub, degrees

East Brawley, Imperial County, CA8'/2 (21.6)sandy siltstone9.2 (1102)520 to 575 (271 to 301)9,000 (2743)2

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TABLE3-TURBODRILLING PARAMETERS,EXAMPLE 4LocationHole size, in. (cm)FormationMud weight (water), Ibm/gal (kg/m 3 )Hole temperature, of (0C)Depth in, ft (m)Bent sub, degrees

Los Alamos, Fenton Hill, NM12% (31.11)granite8.34 (999)280 to 300 (137 to 148)7,845 (2391)1112

TABLE 4 -TURBO DRILLING PARAMETERS,EXAMPLE 5LocationHole size, in. (cm)FormationMud weight, Ibm/gal (kg/m 3 )Hole temperature, of (0C)Depth in, It (m)Bent sub, degrees

Niland, Imperial County, CA12% (31 .11 )sandstone, siltstone, claystone9.9 (1186)400 to 520 (204 to 271)5,965 (1818)2

TABLE 5 -TURBODRILLING PARAMETERS,EXAMPLE 6LocationHole size, in. (cm)FormationMud' weight, Ibm/gal (kg/m 3 )Hole temperature, OF (0C)Depth in, ft (m)Bent sub, degrees'9 Black Magic (oil-base).

Brazos area, offshore Texas81/2 (21.6)sand shale (medium hard)18.1 (2169)350 (176)13,600 (4145)2

TABLE6-TURBODRILLING PARAMETERS,EXAMPLE 7LocationHole size, in. (cm)FormationMud' weight, Ibm/gal (kg/m 3 )Hole temperature, OF (0C)Depth in, It (m)Bent sub, degrees'Orilfaze oil-base).

Sabine Pass, Block No. 16,offshore Texas634 (17.1)shale/limestone17.3 (2073)250 (121)12,795 (3900)2

TABLE7-TURBODRILLING PARAMETERS,EXAMPLE 8LocationHole size, in. (cm)FormationMud' weight, Ibm/gal (kg/m 3)Hole temperature, OF (0C)Depth in, It (m)Bent sub, degrees'Orilfaze oil-base).

Elk City, OK12% (51 .11)middle marrow (gummy shale)17.6 (2108)260 (127)21,117(6436)o

TABLE8-TURBODRILLING PARAMETERS,EXAMPLE 9LocationHole size, in. (cm)FormationMud' weight, Ibm/gal (kg/m 3)Hole temperature, OF (0C)Depth in, ft (m)Bent sub, degrees'Orilfaze (oil-base).

Elk City, OK8112 (21.6)middle marrow (gummy shale)16.5 (978)250 (121)20,658 (6290)o

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opemting pammeters for the bearing assembly. With10,000 Ibm (4536 kg) of WOB, the tool ultimatelyachieved an ROP of 12 ft/hr (3.65 m/h); but because ofthe severity of the deviation and steering tool andwireline problems, only 10 to 12 ft (3.04 to 3.66 m) weredrilled.The problems, particularly with the steering tool,resulted from hot-hole conditions and prevented effective monitoring and use of any motor because the direction of the well was not discernible. Consequently, drilling personnel decided to call out another wireline company, to pull the turbodrill, and to use a positivedisplacement motor.Example 5Data for Example 5 are given in Table 4. Conventionalrotary drilling had deviated this well off course. Depth inwas 5,965 ft (1818 m). The turbodrill, run with milledtooth rock bits, performed extremely well. It wasnecessary to hold back on the bit weight to control deviation, and the turbodrill was drilling at 25 ft/hr (7.62 m/h)continuously. The directional driller encountered orienting problems that necessitated long soak times forsurvey and circulation. (A steering tool was not used atthe start of this job.) The turbodrill was used for 468 ft(142.6 m), with an avemge ROP of 12 ft/hr (3.65 m/h).This tool had been sent directly from the location in Example 4 without intervening maintenance since it had notbeen used to any great extent.Example 6Data for Example 6 are given in Table 5. This exampleindicates the usefulness of turbodrills in hot-hole oilfieldapplications otherthan geothermal. The objective of thisjob was to kick off a cement plug with 90 to 120 ft (27.4to 36.6 cm) of hole. The turbodrill was run with a diamond sidetracking bit. The kickoff required extensivedrilling with zero bit weight and full hydmulics. Themaximum weight used after the direction change was15,000 Ibm (6804 kg). Avemge ROP was 8 ft/hr (2.43m/h) for the kickoff, with a drilling rate of 30 ft/hr (9.14m/h). A total of 106 ft (32.3 m) were drilled, at whichpoint the hole was deviated back on course, and the bottomhole assembly was changed to rotary. The mud usedwas a very heavy oil-base fluid, and a motor withelastomeric components could not have survived in sucha high-temperature environment-especially in one continuous run.Example 7Data for Example 7 are given in Table 6. The intent ofthis run was to kick off the well in a new direction. Adistance of 1195 ft (364 m) was drilled at an avemgeROP of26 ft/hr (7.9 m/h), with occasional mtes of 50 to60 ft/hr (15.2 to 18.2 m/h) during the first phase. Approximately 1 month later it was necessary to re-enter thehole and to drill an extended stmight-hole interval. Anadditional 364 ft (l05 m) of hole were drilled at 6.3 ft/hr(1.92 m/h) with a PCD bit. Note the extremely heavy,oil-base mud (Table 6). Use of a positive-displacementmotor or turbodrill with elastomeric bearings would nothave been feasible in this application.OCTOBER 1982

Example 8Data for Example 8 are given in Table 7. Conventionaldrilling had caused a 2 1/2 0 deviation from vertical whenthree-cone rock bits such as Yll's, Y12's and Y13'swere used, with an ROPofO.96 to 1.3 ftlhr(0.29 to 0.40m/h). The turbodrill was run in the hole because of theoil-base mud and the bit was changed to diamond to control the deviation and increase penetration. Running with17,000 to 30,000 Ibm (7727 to 13 656 kg) of WOBresulted in an ROP of 1.68 ft/hr (0.51 m/h), and increasing WOB to 20,000 to 35,000 Ibm (9090 to 15 909 kg)produced an ROP of2.93 ft/hr (0.89 m/h). Hole sluffingproblems caused the turbodrill to become stuck. It wasjarred loose and then was pulled from the hole forinspection.Example 9Data for Example 9 are given in Table 8. Conventionaldrilling was deviating the well off course, and the ROPwas unacceptable at I ft/hr (0.30 m/h). The turbodrillwas requested because of the mud type and the change todiamond drilling. With a WOB of 11,000 to 20,000 Ibm(5000 to 9090 kg), ROP increased to 3.42 ft/hr (1.04m/h), with a peak of 6 ft/hr (1.82 m/h). This performance peak of 6 ft/hr (1.83 m/h) was maintained for 90continuous hours.DiscussionAs illustmted by some of the case histories, it is veryclear that rock bits suffer an accelerated decrease in lifewhen run on turbodrills of medium to high speeds. Themost predominant failure is loss of gauge on the bitbecause of high peripheral speeds, but cone bearingfailure can occur just as readily. This makes subsequentdrilling very tedious and demanding because the undersized hole requires reaming and conditioning.While diamond bits typically do not provide the aggressiveness exhibited by rock bits, they are capable ofwithstanding the high opemting speeds withoutdetrimental effects. Aggressiveness and high speedtolemnce are qualities resulting from the teaming of PCDbits and turbodrills, making this system very attractivefor both geothermal and petroleum drilling in soft andmedium-hard formations. It should not be understatedthat diamond bits with turbodrills is a formidable combination when used in appropriate applications-for example, hard formations with large WOB loading.ConclusionsThere are obstacles, and much more information must begathered, but the potential for cost-effective operation ofthese tools in hostile environments demands the effort.To date, turbodrills have been used after problems havebeen encountered, mther than being a planned part of thedrilling project. Planned use will occur when the industry is provided with enough of these tools. More turbodrilling experience on the part of drilling contmctorsthen will increase the confidence level and knowledge ofwhen and how to use these tools to their fullest potential.Another factor inhibiting full-scale implementation ofturbodrills in the lack of rig mUd-pump capacity to handle the higher pressure requirements of these tools. Quiteoften, especially in wells below 10,000 ft (3048 m), the

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surface-pump capabilities are the limiting factor in running not only turbodrills but positive-displacementmotors as well. It is imperative that mud pump companies develop high-pressure equipment. In addition,other drilling equipment manufacturers must follow suitin matching their products to the requirements of thesenew, higher-pressure systems.As we drill deeper and deeper and as costs escalate,the use of turbodrills and other downhole motors willbecome paramount in many drilling projects, even to thepoint of being the only alternative. Although these turbodrills have not been tested exhaustively, the successful

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runs so far show that there is much to be gained throughtheir expanded use in the industry.SI Metric Conversion Factors

gal x 3.785 412 E-03hp x 7.46* E-Ollbf-ft x 1:355 818 E+OOpsi x 6.894 757 E-03*Conversion factor is exact.

N'mMPaJPT

Original manuscript received in Society of Petroleum Engineers office Jan. 20. 1981.Paper accepted for publication Feb. 10, 1982. Revised manuscript received July 30,1982. Paper (SPE 9936) first presented at the 1981 SPE California Regional Meetingheld in Bakersfield March 25-26.

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