Drill Bit Selection Criteria

A common criterion for drill bit selection is 'BALANCED WEAR*. Balanced wear is the method of bit selection in which the teeth, bearings, and gauge, wear-out at exactly the same time. It is easy, but does not necessarily give minimum cost.

Some of the problems in selecting drill bits with the 'MINIMUM COST' method are:

  1. bit selection can only be based on drilling experience;
  2. lowest cost is usually interpreted as lowest cost per foot which is not necessarily true;
  3. cost comparisons between bits must be made with each bit operating at its optimal weight and speed and optimal life;
  4. all other factors must be reasonably similar.

A popular equation for cost comparisons is the total cost per foot equation. The costs used in the equation are dictated by drilling rig operations and fall into four categories: bit, trip time, rotating time, and down time accountable to the drill bit. Rotation time is the time consumed while the bit is rotating on bottom with full weight on the formation. Down time is the time consumed other than rotating or trip times. For example, suppose a bit has such a short life that adequate mud treatment can not be accomplished while drilling and that the mud must be treated after the bit is worn out and before a trip is made. Then the time spent treating the mud must be charged to down time. Trip time is the time consumed while running and pulling the drill string for the purpose of replacing the bit. Time for connections is down time.

The total cost of operating and replacing a bit is the sum of the costs: bit, trip, rotation, and down time. If the hourly cost rate of a rig is comparable for all bits being compared; then, the average operating cost for a particular bit per foot is r _ Bit 4- Opr * Trip T + Opr * Rot T + Opr * Down T ~~ Bit Footage

If the bit were operated to its optimal life at its optimum weight and speed, then the cost would be the lowest cost per foot for the bit. Optimal life occurs if the bit is terminated by bearing failure, total tooth wear, or the reduction of its drilling rate to an uneconomical one. Formation changes often mask the latter optimal life and care must be exercised.

The bit performance analyzed in the following example illustrates these ideas. The bit's optimal life corresponds with the minimum value of cost per foot on the plot. Continued drilling will result in increased cost although the teeth and bearings are not totally worn. Contrary to popular beliefs, the simultaneous wear out of bit teeth and bearings is not optimal, nor are the maximizations of rotation time or bit footage optimal.


A long steel tooth bit with unsealed roller bearings and a tungsten carbide insert bit with sealed and lubricated bearings have produced the following performance data.




Bit Cost




6:18 hrs/min

6:32 hrs/min

Rotation Time

10:01 hrs/min

58:42 hrs/min

Down Time



Bit Footage

180 ft

880.5 ft

Rig Cost Rate

375 $/hr


Cost Per Foot



Fraction Tooth Wear


Not Applicable

Fraction Bearing Wear



Average Drilling Rate

18 ft/hr

15 ft/hr

Bit Size

7-7/8 in.

7-7/8 in.

Bit Weight

30,000 lbs

40,000 lbs

Rotary Speed

85 rpm

60 rpm

277.88 + 375*6.3 + 375*10.02 + 375*0 1 Osteel - 10 02*18 =

Values in the table indicate that the insert tooth bit (1) was on bottom for a longer period, (2) drilled more footage, and (3) produced a lower cost per foot. The plot shows that had the steel tooth bit been pulled at its optimal life (6 hours and 34

minutes) it would have had a lower cost per foot: $34.05/ft versus $35.47/ft. The section of the wellbore (880.5 feet) would have cost $369.81 less at optimal life.

Either bit may have drilled at a lower cost had they been operated at their optimal weights and speeds.

No direct method for determining the optimal weight and speed is available for the insert bit with journal bearings; however, analyses of several insert bit performances at various weights and speeds near the manufacturer's recommended values usually delineates the optimal values.


Trip times may be taken from the IADC tour sheet or if greater precision is desired they may be taken from the Geolograph unit or some other device.

The tour sheet will usually be sufficient and much faster.

A chart versus depth must be constructed for each rig for ultimate analyses. Such a chart is shown in the sketch.


A bit is run at a depth of 8,000 feet and pulled at a depth of 8,500 feet. How many hours is the trip time for this bit?

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    What is the main criteria for bit selection?
    3 years ago
  • Jonathan Henderson
    What would bit selection based on for drilling a well?
    3 years ago
  • annabelle
    How are drilling bits selected?
    2 years ago
    How does offset well logging effect drilling bit selection?
    1 year ago

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