American Oil and Gas Reporter - April 2015 - 137

Low Lateral, High Torsional Issues
Well B2 was drilled with BHA three,
which included 12 7-inch drill collars,
12 joints of 5-inch HWDP, and an RNB
stabilizer directly above the bit. Figures

6 and 7 display the downhole vibration
data. No data were retrieved during run
two from DDDR1 or DDDR2, or during
run three from DDDR1.
From the data collected, lateral RMS
vibration stayed below the 2.5 g threshold
throughout the interval. No significant
lateral vibration occurred in zone 1 of
Figure 6 to damage the cutting structure,
as occurred in wells A and B1. During
run one in Figure 7, torsional vibrations
above the motor and in the 5-inch HWDP

stayed below the 35 percent threshold,
but fluctuated between 35 and 60 percent
at the bit. In run two (Figure 7), torsional
vibrations in the 5-inch HWDP were significantly higher than in wells A and B1.
Compared with well B1, this drill
string had significantly less stick slip
above the motor, which could be attributed
to the additional mass and stiffness of
the 7-inch drill collars. However, torsional
vibrations were elevated at the bit, initiated
by a combination of factors that included

FIGURE 4
Well B1 RMS Lateral Vibration
10
9
7
RMS (g)

Zone 1

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

8
6

Run 1

Run 2

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

10,000

10,500

FIGURE 5
Well B1 Delta RPM Torsional Vibration
100%
90%
70%
D RPM

Zone 2

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

80%
60%

Run 1

50%

Run 2

40%
30%
20%
10%
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

FIGURE 6
Well B2 RMS Lateral Vibration
10
9
7
RMS (g)

Zone 1

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

8
6

Run 1

Run 3

Run 2

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 7
Well B2 Delta RPM Torsional Vibration
100%
90%
80%
70%
D RPM

Figure 4 from well A. However, at 8,020
feet MD in zone 1 in Figure 4, a 5.5 g
lateral RMS vibration occurred at the top
of the motor with enough intensity to
propagate down the drill string and damage
the cutting structure, requiring a trip for
penetration rate.
This likely was once again a result of
a formation change from shale to dolomite.
In run one in Figure 5, torsional vibrations
at the bit and in the HWDP stayed below
the 35 percent threshold, but were much
higher, and varied between 60 and 100
percent above the motor. In run two in
Figure 5, torsional vibrations stayed within
acceptable limits.
This drill string had significantly more
torsional vibration above the motor in run
one than in well A. Although torsional vibrations were high above the motor, they
did not propagate far enough up the drill
string to affect the 5-inch HWDP, and
were decoupled by the motor at the bit.
Compared with well A in run one in
Figure 5, the 11 percent reduction in rotational kinetic energy made it more difficult for the BHA to overcome stick
slip. However, the DOG sub decreased
lateral vibration significantly and extended
bit life. The reduction in torsional vibrations seen above the motor in run two in
Figure 5 versus run one is likely the
result of a change in drilling parameters.
Compared with well A, the penetration
rate increased by 28 and 135 percent
through runs one and two, respectively.
It was decided to focus efforts on continuing to reduce high lateral RMS vibration seen while transitioning from
shale to dolomite, while minimizing torsional vibration seen above the motor.
The BHA was redesigned to address
key performance limiters in well B1.
First, six more joints of 5-inch HWDP
were removed, leaving 12 to serve as a
transition from the 7-inch drill collars to
the 5-inch drill pipe.
In an effort to mitigate stick slip above
the motor, the 12 61⁄2-inch drill collars
were replaced with 7-inch drill collars,
which increased the overall rotational kinetic energy in the BHA by 38 percent at
65 rpm compared with well B1. In an
effort to further improve lateral stability,
a 1⁄8-inch undergauge rotating near-bit
(RNB) stabilizer was run in place of the
DOG sub.
All BHA design changes were implemented and run on well B2.

Zone 2

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

60%

Run 3

Run 2

Run 1

50%
40%
30%
20%
10%
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

APRIL 2015 137

American Oil and Gas Reporter - April 2015

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