ADVANCES IN DRILL BIT technolo-gy have added a seemingly endless arrayof features to improve bit performance.

There is little standardization between bitdesigns, so drilling engineers and supervi-sors are faced with difficult choices whenselecting drill bits.

The development of a systematic methodof PDC bit selection was outlined in apaper at the IADC World Drilling 2000conference in June by Jim O�Hare andOsarumwense OA Aigbekaen Jr ofKCA Drilling Ltd.

The system is not an �expert system,� buta simple methodology that can be readilyadapted by engineers to suit their condi-tions, said the authors.

To use the system, a basic geologicalmodel is developed for each hole section.This geological model can be adapted toany area by specifying the main rocktypes and their percentages in the sectionto be drilled.

Individual well profiles are specified bythe percentages of build, drop and hold-ing tangent, and dogleg severity.

Combining the geological model and wellprofile enables a set of �ideal� bit charac-

teristics to be generated. This ideal bitdesign is compared with the drill bits pro-posed by vendors that are ranked byindices for design, performance and eco-nomics.

The Design Index takes into account bitcharacteristics such as the bit profile,number of blades and cutters, cutter size,junk slot area and backrake.

The bit that provides the closest match tothe �ideal� design is selected.

The methodology has been geared tofixed cutter PDC bits but is being expand-ed to include roller cone bits. Althoughthe system was originally developed forextended reach and horizontal wells, itcan be applied to any type of well.

The bit selection system has been pilotedon several Northern North Sea installa-tions and performance increases havebeen measured.

H O W T H E S Y S T E M W O R K S

To build a basic geological model, theselection system described by the authorscalculates the formation strength which isderived from the porosity, matrix rocksonic travel time, pore fluid sonic traveltime, particle grain size factor based onWentworth�s classification of rocks (abra-siveness) and the true vertical depthfootage (degree of compaction).

These parameters are all related to theformation.

The value for the formation strength isused to predict a PDC cutter count andcutter size for the section to be drilled.

The other bit design fea-tures (blade count, gaugelength, junk slot area,profile index, gauge tomain cutter ratio andbackrake) are builtaround these parame-ters.

In summary:

• The number of cut-ters is derived from theformation strength;

• The cutter size isbased on the formationdrillability;

• The blade count is based on the num-ber of cutters and the steerabilityrequirements;

• The junk slot area is calculated fromthe hole cleaning difficulty index;

• The combined profile index is deter-mined from the well profile i.e. % steer-ing, % holding tangent and maximumbuild and turn required (°/100ft);

• The bit profile is the relation betweenthe depth of the cone and the length ofthe taper, which characterizes the bit’sdirectional responsiveness;

• The GM ratio is derived from thesteerability requirements (% build, turn,drop). It is the ratio of the number ofgauge cutters to face cutters, which is ameasure of the side cutting action of thebit;

• The backrake angle is also derivedfrom the steerability requirements.

P E R F O R M A N C E

When the vendors� bits have been evalu-ated and ranked on design they are thenevaluated on performance.

The Performance Index compares the off-set performance of the proposed bits tothe performance of a benchmark bit. Thebenchmark bit is considered to be the bitwith the best performance in the forma-tion or comparable sequence.

The performance parameters taken intoaccount were ROP, footage drilled anddull grading.

These parameters were evaluated takinginto account the operating conditionsWOB (weight on bit), RPM (rotations perminute) and HSI (hydraulic horsepowerper square inch).

According to the authors, the operatingconditions were included because the trueperformance of a bit may not have beenrealized simply because the operatingconditions were different.

This can often be directly related to rigcapacity.

The Economic Index evaluates the costeffectiveness of the proposed bits.

A chain of design equations was devel-oped and combined in a spreadsheet toform the Design Index.

S T U D Y C O N C L U S I O N S

As a result of this study and dialogueswith bit manufacturers, the authorsreached the following conclusions.

For rotating assemblies the walk rate(change in azimuth) is most stronglyaffected by the bit design and the buildrate (change in inclination) is most

40 D R I L L I N G C O N T R A C T O R September/October 2000

Design Index provides systematic PDC bit selection

Figure 1: ROP results using design index

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Well A Well 1 Well B Well 2 Well C Well 3

Ft/hr

CurrentPrevious

strongly affected by the bottom holeassembly.

PDC bits which have a long gauge and/orlong outer profile (IADC bit profile codes1, 2 and 3) exhibit a tendency to walk tothe left.

As the gauge and profile shortens, the ten-dency to walk left reduces and may resultin right-hand walk with very short pro-files and gauges.

Deep coned PDC bits (IADC bit profiletypes 1, 4, and 7) tend to be directionallystable.

Single cone bits (IADC bit profile types 6and 9) tend to be directionally isotropic(responsive in any direction).

Spiral gauge pads act to smooth thetorque response of a bit, but do notreduce the torque.

Smooth torque response results in reliabletool face settings and improves the holequality.

The average torque is the same for bothspiral and straight gauge pads with thesame cutting structure.

The bit�s contribution to the averagetorque value is controlled by the length ofthe cutting profile, particularly the lengthof the cutting profile with a radius greaterthan one half the gauge radius. Bit torquetherefore increases with the length of thecutting profile.

The average torque value is lowest withbit profiles tending towards IADC bit pro-file type 9 and increases with bit profilestending towards IADC bit profile type 1.

Cutter diameter does not affect torque (atconstant ROP).

According to the authors, these guidelinescan be used for bit selection based on Pro-file Codes:

• Select the gauge andprofile length to obtainthe walk tendenciesrequired by the directionplan in rotary mode or forrotary assemblies. Alonger gauge and profilewill increase the tenden-cy to walk left;

• Apply deep coned PDCbits (IADC bit profiletypes 1, 4 and 7) withfully stabilized assem-blies to maintain angle

and direction in tangent sections;

• Select single (shallow) cone bits(IADC bit profile types 6 and 9) for direc-tional drilling in soft formations with amotor;

• Do not select single conebits (IADC bit profile types 6and 9) for pendulum or unsta-bilized assemblies, as theseprofiles tend to build angle;

• Select the shortest overalllength and a rounded cuttingstructure for use with a benthousing mud motor;

• Use spiral gage pads fordirectional motor work;

• Select IADC profile codes 9, 8 or 6 tominimize the average torque value;

• Select cutter size based on formationabrasiveness and strength. as opposedto directional drilling requirements.

Figure 2 shows the respective indices forthe IADC profile codes corresponding tothese statements.

These indices�Bi, Hi and Wi�are ameasure of the bit�s tendency to performthese actions. The values range from 1(least tendency) to 9 (most tendency).

N O R T H S E A R E S U L T S

In one North Sea case study comparingtwo 8 ½-in. sections, the two sectionswere drilled in different wells on the sameplatform. The wells had similar profilesand formation tops.

Both wells were predominantly tangentsections and the formation was readilydrillable. Bits with different design speci-fications were run in each well.

Bit A was initially recommended, basedon the success of a previous section

drilled on the same platform. The per-formance of Bit A was used as a bench-mark.

Bit B was then chosen using the DesignIndex methodology. The Design Indexmethod suggested that a more aggressivebit and a deeper cone profile wouldincrease the ROP and improve the bit�sability to hold tangent.

Bit B was chosen over Bit A, which hadbeen the best run on that section to date.

The run with Bit B showed an increase ofapproximately 10% in average ROP and6% less steering than planned wasrequired as the bit held tangent better.

The design table for Bit A and Bit B isshown in Figure 3.

In another case, two successive 12 1/4-in.sections drilled from another North Seaplatform were compared. These wells hadsimilar profiles and formation tops.

The Design Index methodology was usedto select the bit for the second well.

The bit selected using the system morethan doubled the average ROP andreduced the cost/ft by approximately50%.

C O N C L U S I O N S

The Design Index provides engineers away to classify and select bits, and anobjective method of comparing their per-formance.

This systematic approach increases thefocus on bit selection and drilling per-formance, and proposes bit attributes tosuit individual well conditions.

The system has demonstrated that signifi-cant performance and cost benefits can beobtained over �best runs to date�.

In addition, the Design Index methodolo-gy can be used to further improve bitdesigns. n

42 D R I L L I N G C O N T R A C T O R September/October 2000

Figure 2: Profile code guideProfile Build Hold Walk (left)Code (Bi) (Hi) (Wi) 1 1 9 9 2 4 6 8 3 7 3 7 4 2 8 6 5 5 5 5 6 8 2 4 7 3 7 3 8 6 4 2 9 9 1 1

Figure 3: North Sea resultsFeatures Bit A Bit B Size 13 13 Cutter count 58 47 Blade count 8 7 Gauge length 3 3 Junk slot area 8.2 10.4 Profile code 6 5 Gauge/main 0.41 0.57 cutter ratio Backrake 19 22