Page 219 - Practical Well Planning and Drilling Manual

Section 2 revised 11/00/bc 1/17/01 12:04 PM Page 195

2.4.6
Drill Bit Selection, Parameters, and Hydraulics [ ]

next run by a change of practices, BHA configuration, or correctly set
up shock sub?
If the bit came out undergauge, did this cost time on the next bit
in to ream to bottom? Would the cost of using premium gauge protec-
tion (such as diamond-coated heel teeth) be repaid in better drilling
performance and less reaming?
Were optimum hydraulics used? If not, is this likely to have caused
a lower ROP? Are there any constraints on optimizing hydraulics (such
as having to use larger nozzles for possible LCM)?
Economics is the bottom line to the decision. Which bit will drill
the most cost-effectively? PDC bits in larger hole sizes tend not to be
economic on low-cost rigs, but this changes if: the hole sizes decrease
(there is less extra PDC cost and a higher chance of losing cones off tri-
cone bits), the hole deepens (trip time becomes more significant), or
the rig day rate increases. As wells are drilled slimmer than in the past
and as PDC bits improve in their cost and performance, PDC options
should be examined where a potential application exists.
By examining all aspects of the bit runs and gradings and by con-
sidering all restrictions imposed by the BHA, the drilling engineer
should be able to see what bit features may be changed to obtain a bet-
ter run next time.
Particular bit features and how they relate to bit selection.
Certain downhole conditions can include or preclude particular bit fea-
tures at the well planning stage (see Table 2-1). Later in Section 3 when
practical operations are discussed, dull bit features are used to identify
possible downhole conditions that may lead to a modified bit selection.
Using IADC codes to identify a general class of suitable bit.
IADC tricone bit classification. Each bit manufacturer, having their
own way of naming their bits, made identifying which particular tri-
cone bits to use for different formations more difficult. The IADC rec-
ognized this problem some time ago and devised a code system with
three digits for identifying principal bit features. This is a useful com-
parison of different makers’ bits since the IADC code is usually given
as well as the bit name.
The first code digit is formation hardness series and can be 1 to 8.
Low numbers relate to softer formations; 1 to 3 are for mill tooth bits
and 4 to 8 are for TCI bits.

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