American Oil and Gas Reporter - April 2015 - 139

SpecialReport: Performance Drilling

Slowest Drilled Interval
Well C1 was drilled with BHA four,
which included 48 joints of 5-inch HWDP.
Figures 8 and 9 display the downhole vibration data.
For most of the interval, lateral RMS
vibration stayed below the 2.5-g high
threshold. However, at 7,900 feet MD in
zone 1 in Figure 8, a 9-g lateral RMS vibration occurred at the bit with enough
intensity to damage the cutting structure
and require a trip for penetration rate.
This likely was a result of a formation
change from shale to dolomite.
In both runs one and two in Figure 9,
torsional vibrations at the bit and in the
5-inch HWDP stayed below the 35 percent
high threshold, while they regularly exceeded 100 percent above the motor.
This drill string had significantly more
torsional vibration above the motor in run
one than on well B2. Although torsional
vibrations were high, they did not propagate
far enough up the drill string to affect the
5-inch HWDP, and were eliminated at the
bit by the motor's power section. Compared
with well B2 in run one in Figure 9, the
72 percent reduction in rotational kinetic
energy made it much more difficult for
the BHA to overcome stick slip.
This is the only interval in which the
limber 5-inch HWDP was run in com-

FIGURE 8
Well C1 RMS Lateral Vibration
10
9
8

RMS (g)

7

Mov Avg DDDR 1
Mov Avg DDDR 2
Mov Avg DDDR 3

Zone 1

6

Run
3

Run 2

Run 1

5
4
3
2
1
0
2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500
MD (ft)

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

FIGURE 9
Well C1 Delta RPM Torsional Vibration
100%
90%
80%
70%
D RPM

drilling parameters (i.e., higher weight
on bit) and/or higher reactive torque at
the RNB stabilizer than the DOG sub because of a larger contact area in compression. Because of missing DDDR data, it
was difficult to deduce the root cause of
the vibration in runs two and three, but it
was evident that the torsional vibrations
were elevated versus wells A and B1.
It was necessary to reduce lateral vibration damage to the cutting structure
while transitioning from the shale to the
dolomite. We also needed to mitigate elevated torsional vibrations initiated at or
near the bit in well B2.
A popular BHA design that drilled
many previous offsets was selected to
further confirm whether this design approach yielded competitive performance
results. The near-bit sub and all drill
collars were removed from the BHA and
replaced with 48 joints of 5-inch HWDP,
which deflects at only 23 percent of the
compressive load of a 7-inch drill collar.
In addition, at 65 rpm, the BHA provided
only 28 percent of the rotational kinetic
energy observed in well B2.
All BHA design changes were implemented and run on well C1.

Zone 2

Mov Avg DDDR 1
Mov Avg DDDR 2
Mov Avg DDDR 3

Run 1

60%

Run
3

Run 2

50%
40%
30%
20%
10%
0%
2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

pression, which significantly increased
wall contact and reactive torque. As the
BHA decelerated at a stick event and the
drill string could not provide the rotational
kinetic energy required to maintain constant velocity, the top drive continued to
turn to the right while the drill string in
tension stored sufficient spring energy to
overcome the rock strength, at which
point a slip event occurred.
At the slip, the BHA accelerated forward, decelerated and stopped, accelerated
backward and stopped, and repeated this
cycle at an amplitude and frequency that
increased with depth. The backward rotation caused from severe stick slip is
very damaging to the cutting structure,
blades, and the gauge of a PDC bit. This
was the slowest interval drilled in the
study.
There was a need to continue reducing
the high lateral RMS vibration seen while
transitioning from shale to dolomite, and
to reduce torsional vibrations seen above
the motor.
The BHA was reconfigured with 7inch drill collars, similar to well B2. Evidence from previous intervals suggested
that the increased stiffness and additional
stored kinetic energy per linear foot in 7inch drill collars reduced torsional vibrations in the drill string. Additionally, the
RNB stabilizer was removed in an effort
to mitigate torsional vibrations seen at

6,500
MD (ft)

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

the bit in well B2.
All BHA design changes were implemented and run on well C2.

Low Torsional, Lateral Vibrations
Well C2 was drilled with BHA five,
which included 12 7-inch drill collars
and 12 joints of 5-inch HWDP. Figures
10 and 11 display the downhole vibration
data.
From the data collected, lateral RMS
vibration stayed below the 2.5 g threshold
throughout the interval. However, at 7,950
feet MD in zone one in Figure 10, a 6.5-g
lateral RMS vibration occurred at the bit
with enough intensity to damage the
cutting structure and require a trip for
penetration rate. This likely was a result
of a formation change from shale to
dolomite. In addition, torsional vibrations
stayed below the high 35 percent threshold
for most of the interval.
This interval generated relatively low
torsional and lateral vibrations, with the
exception of the transition from the shale
to dolomite in zone 1. Removing the
near bit stabilizer significantly decreased
torsional vibration, but increased lateral
vibration enough to reduce the length of
run one compared with well B2.
Drill bit damage associated with lateral
vibration at the transition from shale to
dolomite remained the key limiter.
A motor's power curve will show the
most efficient differential pressure range
APRIL 2015 139



American Oil and Gas Reporter - April 2015

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Contents
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American Oil and Gas Reporter - April 2015 - Cover2
American Oil and Gas Reporter - April 2015 - Contents
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