I N NOVATI N G WH I LE DR I LLI N G
In lab testing, NOV examined the relationship between bit wear and HFTO. Configuration 1 (dull cutter) showed greater average
HFTO amplitude than Configuration 2 (new cutter), with the difference becoming more pronounced at lower RPMs.
Bit B, a new design, had 30 face cutters with the shape alter-
nating between chisel and full round. Further, the cutters were
laid out in a star spiral order, with the shape alternating between
chisel and full round. The alternating shape and star layout was
chosen to improve the ratio of shear length to shear area.
There were 10 secondary cutters in Bit B made from the same
material as a diamond impregnated cutter. These secondary cut-
ters were placed in a tracking location. The back rake angles of
the face cutters varied from 15° in the cone to 20° near the gauge.
The bits were tested in five separate configurations. The first
configuration was used to examine the effect of bit wear on HFTO,
with successive configurations changing different elements of
the bit to isolate which parameters had the most significant
impact. Configuration 1 involved the use of Bit A directly from the
field, already having dull and broken round cutters on its primary
and secondary blades. Configuration 2 involved the replacement
of the dull and damaged cutters on Bit A with undamaged 16-mm
round cutters on the primary and secondary blades. Configuration
3 involved the use of non-planar cutters to increase back rake
angles. Configuration 4 involved replacing the secondary cutters
with cylindrical diamond impregnated material. Configuration 5
involved the use of Bit B.
Each configuration was tested at 10 separate combinations of
weight on bit (WOB) and RPM. Before testing a configuration, the
hole was prepared by drilling 130 mm into the rock to generate
the bottomhole pattern, ensuring that all tests start with similar
formation engagement.
Testing of Configuration 1 compared with Configuration 2
showed that worn cutters increase the risk for HFTO. At 100 RPM,
the new cutters in Configuration 2 led to a 53% reduction in the
amplitude of HFTO. The disparity in amplitude increased as RPM
decreased – Configuration 2 saw an 82% drop at 75 RPM and a 97%
drop at 50 RPM. This indicated that the PDC cutters should be cho-
sen for longevity and durability in areas where HFTO is a concern.
Configuration 3 had a 39% decrease in HFTO amplitude com-
pared with Configuration 2, indicating that higher back rake
angles – the angles of the face away from the end cutting edge
of the drill bit – can reduce HFTO for a given WOB and RPM.
However, the average ROP also increased 23% from Configuration
2 to Configuration 3. The use of diamond impregnated cutters
(Configuration 4) in place of the secondary cutters showed a 12%
reduction in amplitude and an 11% increase in ROP.
The differences in back rake angle proved less significant than
the other factors tested in determining the risk for HFTO. The data
did not support the theory that increased back rake angle would
worsen HFTO – in fact, Configuration 3 showed the 39% decrease
in HFTO amplitude despite having an increased back rake com-
pared with Configuration 2.
The results from the study indicated that the optimal bit design
to limit HFTO vibration magnitude requires the use of durable cut-
ters with either non-tracking secondary PDC cutters or diamond-
impregnated cutters and a low back rake angle.
While NOV said it has no imminent plans to turn the learnings
from this study into a new product, the company’s ReedHycalog
business unit does hope to have a roadmap by the end of this year
for developing a product line of bits designed specifically for miti-
gating HFTO. “Our next goal is to develop an agenda where we can
go to our customers and tell them how we’re going to bring about a
bit that will help the industry reduce HFTO at the source. We don’t
have a product line solely dedicated to HFTO right now, but we do
have an agenda,” Mr Centala said.
Predicting dysfunctions with a digital twin
Computer-based well planning and drilling dynamics model-
ing is a standard practice for improving drilling performance.
However, it has its limitations.
Primarily, conventional well planning software produces static
models of the downhole, which are not useful in analyzing down-
hole behavior over a period of time. That is key to identifying the
risk of dysfunctions, said Mr Gandikota of MindMesh. “What we
are missing with the static model is the interaction of the drill
bit cutting rock, and how the BHA interacts with the hole while
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