American Oil and Gas Reporter - April 2017 - 61

SpecialReport: Drilling Technology
FIGURE 2
Extended-Reach Well 1 Section View
10,300

Kickoff point 10,466.12 ft

True Vertical Depth (200 U.S. ft/in)

10,400
Scallion
10,500

Build rate 12.00°/100 ft

False Bakken
Upper Bakken Shale

10,600

End build 11,132.79 ft

Mid Bakken A

10,700

Mid Bakken B
Mid Bakken C

10,800

Mid Bakken D

7-in Casing

10,900
100

200

300

400
500
600
700
Vertical Section at 177.57° (200 U.S. ft/in)

800

900

FIGURE 3
Extended-Reach Well 2 Section View
10,400
10,450
10,750

10,500

Begin build 10,784.48 ft

10,550
False Bakken

10,600

Scallion

10,650

Mid Bakken A

10,700

Mid Bakken B

0

,00

11

Mid Bakken C

10,750

Mid Bakken D

10,800

End build 11,415.63 ft

Lower Bakken Shale
Pronghorn Mbr

10,900

50

Mid Bakken E

10,850

10,950

Build rate 12.00°/100 ft

Upper Bakken Shale

11,
2

True Vertical Depth (50 U.S. ft/in)

Extending Lateral Reach
The horizontal section of the first extended-reach well (Figure 2) measured
more than 14,600 feet and total depth
was 25,023 feet. The well was drilled to
23,367 feet conventionally with the motor
assembly. The inability to slide beyond
that depth was attributed to increased
friction caused by hitting a fault that required more slide intervals to correct. A
total of 1,928 feet of heavyweight drill
pipe in the string did not provide enough
weight to push the pipe. A short trip for
4,000 feet assisted in reducing the drag,
but a single friction-breaking tool was
not sufficient to break friction.
At that point, a motor-assist rotary
steerable assembly was picked up to penetrate the fault and drill the final 1,656
feet to TD in the Upper Bakken above
the target reservoir. The 13,868-foot lateral
was drilled in 30 days (41 days total to
TD) and 94 percent of the lateral was
drilled within the Bakken target.
This trajectory design was altered to
include a nudge in the intermediate section
through the final 2,000 feet above the kickoff point to reduce string buckling (this
was where axial stress was highest on the
drill string with compression). The nudge
up to 10 degrees inclination helped support
the pipe and reduce axial stress while and
aiding in better weight transfer at TD.
Extended-reach Well 2 targeted the
Three Forks (Figure 3) and its trajectory
design was optimized for better weight
transfer. It was drilled to 25,431 feet TD
in 33.6 days, and the 13,961-foot lateral
was drilled in 22.3 days while remaining
100 percent in zone. The trajectory held
a 20-degree nudge tangent over 4,000
feet until the kickoff point in the build.
The build section was planned for 12 degrees/100 feet with a 58-degree turn
before landing in the target formation.
A 2,576-foot length of heavyweight
drill pipe was picked up based on torque
and drag modeling and placed optimally
for target run depths following the pipe
shuffling schedule. Two mechanical friction-breaking tools were placed 3,000
feet and 7,500 feet from the bit, respectively. The tools were configured for a
flow rate and orifice size that would
create enough pressure drop to propagate
an axial force through the shock sub.
The motor BHA assemblies were modeled to track neutral on rotary tendencies
to reduce slide drilling. The well drilled
with a mud motor assembly until 24,118
feet, when sliding became difficult and

Three Forks
TF A Marker

750

800

850

7-in Casing

900

950 1,400 1,400 1,400 1,400 1,400
Vertical Section at 172.78° (50 U.S. ft/in)

1,400

1,400

1,400 1,400

APRIL 2017 61
American Oil and Gas Reporter - April 2017

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