Page 433 - Practical Well Planning and Drilling Manual

Section 3 revised 11/00/bc 1/17/01 12:00 PM Page 409

3.6.2
Drill Bits [ ]

Try to ascertain what conditions may have caused the specific dull
conditions and evaluate what changes could be made to bit choice,
running procedures, drilling parameters, BHA, mud, etc., to reduce the
impact of these conditions. For example, a common mistake is to
assume that broken teeth equates to a bit that is too soft; there are other
more likely causes in most cases. Downhole shock or vibration, hard
nodules, or junk could all play a part. Running too hard a bit for the
formation is likely to compromise your overall bit performance. (Refer
to Table 3-5 in Section 3.6.6, “Post-Drilling Bit Analysis,” for informa-
tion on dull bit features.)

3.6.2. Drilling Parameters

Weight on bit. When drilling, weight is applied to the cutters so
that rock is penetrated. Up to certain limits the more weight applied
the faster the bit will drill. If too much weight is applied, the cutters
may become completely buried (known as bit flounder) and weight
will be taken by the cones or bit body. This will reduce ROP and rapid-
ly wear the cones. Increasing weight will also accelerate wear on bear-
ings and cutters.
Deviation is also affected by WOB. A rotary locked or build assem-
bly will have an increasing build tendency with greater weights; where
a rotary pendulum is in an established drop then increasing weight will
tend to increase drop, up to a point where further increasing the weight
may produce unpredictable results. In a vertical borehole with a flexi-
ble pendulum or build BHA, increasing weight will deflect the wellpath
from vertical.
In a motor-bent sub combination, increased weight will increase
side force at the bit, and therefore accelerate the rate of direction
change in the direction of toolface azimuth, up to the point where the
motor stalls.
When planning to change hole direction, the BHA selected may
dictate the approximate WOB to be used, which may affect bit choice.
Refer to offset records including the field operational notes and
hole section summaries to see what WOB works best in a particular
formation. Regular drill-off tests should be carried out.
Optimum WOB can be run when using locked assemblies. See
“BHA considerations related to bits” in Section 2.4.7.

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