Page 223 - Practical Well Planning and Drilling Manual

Section 2 revised 11/00/bc 1/17/01 12:04 PM Page 199

2.4.6
Drill Bit Selection, Parameters, and Hydraulics [ ]

Third digit: size (PDC) or type (diamond)

PDC Surface set
1 >24 mm diameter Natural diamonds
2 14-24 mm diameter Thermally set polycrystalline (TSP)
3 8-14 mm diameter Mixed (e.g., natural and TSP)
4 <8 mm diameter Impregnated diamond

Fourth digit: body profile

1 Flat face surface set or “fishtail” type PDC
2 Almost flat profile
3 Medium length profile (e.g., round or short parabolic)
4 Long profile (e.g., long flanked turbine bit)

Mud motors, steerable systems, and turbines. When planning to
run a downhole motor, the following other considerations apply:

1. If the string is rotated while drilling with a motor, will the maxi-
mum bit RPM be exceeded?
2. Will the flow through the motor clean the hole at the envisaged
flow rates?
3. Are there any limitations on the bit pressure drop imposed by
the motor?
4. Is the proposed bit suitable to use on the type of motor to be used?
5. Can LCM be pumped through the motor and, if not, should a cir-
culating sub be run above? Is LCM needed while drilling with the
motor?
6. What sizes of liners are needed in the pump for the necessary flow
rates and pressures?
7. Are there any problems with the mud properties (e.g., chemical
compatibility with seals, sand content, etc.)? Check with the
motor supplier.

What is the plan for before and after the motor run? For instance,
if running in for straight hole turbodrilling with a PDC bit, the previ-
ous assembly should be fairly stiff to avoid reaming in with the turbine.
Any junk in the hole would require a junk run first, or if a steerable
system run is going to terminate at casing point, then a wiper trip with
a rotary assembly should be made to ream to bottom and reduce the
chance of mechanically stuck casing by reducing doglegs and ledges.

199