American Oil and Gas Reporter - April 2016 - 64

SpecialReport: Drilling Technology

3,000.0
4,000.0
5,000.0
6,000.0
7,000.0
8,000.0
9,000.0
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12,000.0
13,000.0
14,000.0
15,000.0
16,000.0
17,000.0
18,000.0
19,000.0
20,000.0

200

150

100

ROP (ft/hr)

50

0

14
-O
26 ct-O 20
08 ct-2 13
-Ja 01
10 n-2 3
-J 0
23 an- 14
-J 20
09 an- 14
-F 20
23 eb-2 14
-F 0
23 eb- 14
-F 20
25 eb- 14
-F 20
28 eb- 14
-F 20
04 eb- 14
-M 20
05 ar-2 14
-M 0
13 ar- 14
-M 20
15 ar- 14
-M 20
15 ar- 14
-M 20
16 ar-2 14
-M 0
21 ar- 14
-M 20
23 ar- 14
-M 20
26 ar- 14
-M 20
26 ar- 14
-M 2
27 ar- 014
-M 2
30 ar- 014
-M 20
31 ar- 14
-M 20
03 ar-2 14
-A 0
11 pr- 14
-A 20
13 pr-2 14
-A 0
15 pr-2 14
-A 0
17 pr-2 14
-A 0
22 pr-2 14
-A 0
25 pr-2 14
05 Apr 014
-M -2
11 ay- 014
-M 20
13 ay 14
-M -20
27 ay- 14
-M 20
04 ay-2 14
-J 0
08 un- 14
-J 20
24 un- 14
-J 20
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-J 20
30 un- 14
-Ju 20
n- 14
20
14

MD (ft)

FIGURE 2
Increased One-Run Success Rates after Optimizing Vertical Parameters

the Wilcox by reducing mud flow rates
to 450-550 gallons a minute and total
rpm to 170-210 through the formation.
This technique resulted in a visibly reduced
ROP through the vertical section, although
this was not significant compared with
the time associated with a BHA trip.
The rigs that were unable to drill oneruns were not slowing down in the Wilcox,
which resulted in bits with considerable
shoulder wear and an inability to continue
drilling effectively into the curve section.
Because of the necessary balance in
design elements for one-run bits, damage
that would be considered normal wear
and tear on a drill bit became a substantial
factor for maintaining build rates and
ROP in subsequent sections.
The investigation established a base
line of acceptable parameters for drilling
through the Wilcox. Figure 1 shows an
initial comparison of parameters run
through the Wilcox.
Bit damage was evident on one-run

Length

attempts that were unable to achieve build
rates in the curve. The difference between
the successful and unsuccessful runs is
approximately 50 rpm down hole caused
by higher flow rates and higher top-drive
rpm. The one-run success rate increased
by 21 percent immediately after implementing optimized vertical parameters
(Figure 2).
However, despite the improvement
through base-line vertical parameters,
there was a large decrease in one-run
success rates after the rigs moved to a
different focus area within the operator's
Eagle Ford acreage. Even after altering
parameters in the Wilcox, failed one-run
attempts unexpectedly exhibited bit damage substantial enough to inhibit drilling
the curve.
In the new focus area, the Wilcox
proved to be thicker than expected and
denser at its deepest point. This discovery
added a new element to the Wilcox: It
was not simply a matter of how to drill

FIGURE 3
Wilcox Thickness versus One-Run Success Rate
0

Wilcox < 4,000'
46.7% success rate

2,000.0

Wilcox > 4,000'
16.7% success rate

MD (ft)

10,000.0
12,000.0
14,000.0
16,000.0
18,000.0
20,000.0

Run Length (success)

Wilcox Length

64 THE AMERICAN OIL & GAS REPORTER

Run Length

4,450

4,530
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4,440

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4,400

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4,340

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4,170
4,230

4,308

4,050

4,080

3,980

4,040

3,950

3,980

3,960

3,950

3,950

3,890

3,890

3,850

3,830

3,800
3,810

8,000.0

3,800

3,750

6,000.0

3,800

4,000.0

the formation, but also where to drill it.
The success rate was nearly 50 percent
in locations where Wilcox thickness was
less than 4,000 feet, but declined to 17
percent where it was more than 4,000
feet thick.
This realization helped eliminate some
wells from consideration for one-run attempts, improving the overall success
rate (Figure 3). It also meant that successfully drilling through the Wilcox in
the new focus area required an even
greater reduction in parameters to preserve
the bit for the curve, reducing both time
savings and the probability of success by
adding more exposure time to the BHA.
Other Variables
Another limiting factor for potential
one-run wells is overall lateral length.
Wells that are longer than average add
an element of exposure time to downhole
drilling conditions on the motor and
measurement-while-drilling tools. Bottom-hole well temperatures can vary as
much as 150 degrees from drill-out to
TD. The longer tools are exposed to harsh
drilling conditions, the more likely they
are to fail, thereby negating almost all
savings and gains by forcing a trip late in
the lateral.
This finding encouraged the rigs to
control ROP during the last part of the
lateral to ensure that equipment would
not fail. Because longer wells increased
the probability of failure and losing rather
than saving money, they were easily eliminated as potential one-run wells.
Several variables were analyzed, but
proved somewhat benign on one-run success rates. These included formation dip
in the lateral, updip versus downdip, and
stabilized versus slick BHAs. Wells that
were drilled in a northerly direction typically exhibited a 2.0- to 4.0-degree angle
increase updip above a true lateral base
line. The intuitive expectation was to observe more unsuccessful updip wells, but
these wells actually accounted for 22-23
percent of both successful and unsuccessful
one-run attempts.
Stabilizers also were anticipated to
hinder drilling the curve while helping
in the vertical and lateral sections. However, adding stabilizers to the BHA did
not have a significant effect. Half of all
one-runs attempted used a stabilizer and
comprised 56 percent of successful attempts, which was a negligible difference
on the outcome of one-run attempts.
The results of this study provided the
American Oil and Gas Reporter - April 2016

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