Page 218 - Practical Well Planning and Drilling Manual

Section 2 revised 11/00/bc 1/17/01 12:04 PM Page 194

[ ] Well Programming
2.4.6

PDCs do not give a good D exponent trend. When it is important to
recognize a pressure transition zone, it may be better to run a tricone bit.
PDC bits are usually not suitable for formations containing hard
chert or other nodules, though this is possible with some bits and care-
ful optimization of parameters. By using a large flowby area around the
cutter pegs, maximum flow rate, minimum RPM, and moderate WOB,
small hard nodules can sometimes be washed away before damage is
done to the cutters. The Hughes B11M or Eastman “Eggbeater” types
have demonstrated this.
Natural diamond bits. Natural diamond bits incorporate dia-
monds directly into the bit matrix. These bits work by abrading the for-
mation, producing very fine cuttings or “rock flour.” A diamond bit
will drill any hard formation, but at low ROP. Diamond bits, like PDCs,
need to have the cutters effectively cleaned and cooled for a full work-
ing life.
Due to their construction, diamond bits are available in a wide
variety of profiles and cutting actions. For sidetracking, bits with a
good side cutting action may be ordered. Parabolic shapes allow a
greater concentration of working cutters on bottom and tend to be
directionally stable.

2.4.6. Defining Recommended Bits

In order to define which is likely to be the best bit to use for each
part of the hole, a set of questions can be asked. The first question is
“what are the best two offset bits?” The second question is how can we
improve on the previous best bit run?”
Examine the two best runs. Look at the bit gradings as well as the
run details. Differences between the best two may “point the way”; if the
best bit was a slightly softer type than the second best, is it likely to help
if an even softer formation bit is used? It is clear that drilling supervi-
sors and engineers often choose bits that are too hard a type for the for-
mation being drilled and therefore end up sacrificing performance.
If the best bit was pulled at the end of its economic life, what
caused the bit to be pulled? For instance, if there were an excessive
number of broken teeth, was that caused by bad run practices, drill-
string vibration, or formation conditions? Can this be avoided on the

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