American Oil and Gas Reporter - April 2015 - 136

inch drill collars and 60 joints of 5.0inch heavyweight drill pipe (HWDP).
Figures 2 and 3 display the downhole vibration data.
For the majority of the interval, lateral
root mean squared (RMS) vibration stayed
below the high threshold of 2.5 g-force.
However, in zone 1 in Figure 2 at 7,400
feet measured depth, a 7-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.
Throughout the interval, torsional vibrations (i.e., downhole rotational speed
variation) stayed below the 35 percent
high threshold. At the beginning of zone

FIGURE 1
Drilling Time Curve and Location of Wells Analyzed

Depth (ft)

ZONE 1

ZONE 2

Time (days)

FIGURE 2
Well A 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

FIGURE 3
Well A 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 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)

136 THE AMERICAN OIL & GAS REPORTER

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

2 in Figure 3, from 8,300- to 8,500-feet
MD, a 60-80 percent torsional vibration
was observed at the bit, and likely was
the result of a formation change from
dolomite to limestone. Once in the limestone of zone 2, torsional vibrations were
higher than in the rest of the interval.
It was concluded that high lateral RMS
vibration while transitioning from the
shale into the dolomite in zone 1 (shown
in Figure 2) damaged the cutting structure,
leading to a premature trip for penetration
rate.
The BHA was redesigned to address
key performance limiters in well A. As
the 5-inch HWDP was being run solely
in tension, 42 joints were removed, leaving
18 to serve as a transition from the 61⁄2inch drill collars to the 5-inch drill pipe.
This transition minimizes fatigue to a
section of the drill string where a large
change in area moment of inertia (AMOI)
would otherwise occur.
AMOI is a measure of a tubular's
ability to resist bending. The lower the
percent change between tubulars being
made up together is, the lower the bending
stress ratio will be.
The AMOI reduction from 61⁄2-inch
drill collars to 5-inch drill pipe is an 84
percent change. From 61⁄2-inch drill collars
to 5-inch HWDP is a 68 percent change,
and 5-inch HWDP to 5-inch drill pipe is
50 percent.
Although three 61⁄2-inch drill collars
were added, the loss of 42 joints of 5inch HWDP resulted in an 11 percent reduction in rotational kinetic energy in
the BHA at 65 rpm, compared with well
A. More rotational kinetic energy in the
BHA will maintain a more constant rotational velocity as the BHA decelerates
during a sticking event.
In an effort to improve lateral stability,
a full-gauge drill-on-gauge (DOG) sub
was added above the bit. A driller's road
map was prepared that captured successful
drilling parameters from well A, and included offsets by formation top. We gave
the road map to operations as a job aid
for the next well.
All BHA design changes were implemented and run on well B1.
High Lateral RMS Vibration
Well B1 was drilled with BHA two,
which included 12 61⁄2-inch drill collars,
18 joints of 5-inch HWDP, and a DOG
sub directly above the bit. Figures 4 and
5 display the downhole vibration data.
For the majority of the interval, lateral
RMS vibration stayed below the 2.5 g
threshold, with very little seen at the bit,
which extended the length of run one in

American Oil and Gas Reporter - April 2015

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