American Oil and Gas Reporter - January 2015 - 95

Unconventional Resource Science
as the design as a whole.
The second phase of the project was
implemented to test the effectiveness of
the recommended design and verify the
predictions of the datasets that were used
in the first phase. An offset pad was identified to perform the second phase that
had an available wellbore for microseismic
monitoring. Two wells were tested with
the optimized completion design: the
State of North Dakota 10-3HA (Middle
Bakken) and the Adam Good Bear 1522HW (Three Forks).
The fluid system for the two wells
was similar to the phase one system. A
hybrid design was used with slickwater
in the pad and 100-mesh stages, and 20pound cross-linked guar gel was used for
the 20/40-mesh stages. The same 35/65
split of sand/intermediate-strength proppant was used as in the phase one wells,
but gel loading was decreased to retain
conductivity.
The microseismic program in this
phase was two spacing units west of
phase one. It utilized two vertical monitor
arrays and one horizontal monitor array
(Figure 1); 12 stages from the treatment
well, State of North Dakota 10-3HA,
were monitored. A 30-tool, 14-level
stacked array was deployed in the 103H, with the depth of the top tool at
8,350 feet measured depth and the bottom
tool at 9,350 feet MD.
The same array design was deployed
in the Brunsell No. 16-9H, with the top
FIGURE 1
Phase Two Layout

tool at 8,550 feet. An 18-tool unstacked
array was deployed in the horizontal section
of the No. 10-3 HW and was moved up
hole to remain opposite the active treatment
stages. The arrays were oriented using
perf shots and 610 microseismic events
were located. Some stages of the Adam
Good Bear 15-22 HW were monitored,
but these results are not yet available.
The dominant fracture trend that had
been observed in the microseismic data
acquired in phase one was not as prominent
in phase two data. The dominance of the
primary trend varied slightly, and the
frac coverage was consistent along the
wellbore. In five stages, events can be
seen at the 10-3H well; which at the
time, had been producing for 2.5 years.
The microseismic showed good fracture
coverage along the wellbore with adequate
stage isolation.
Significant vertical height growth was
a common thread among all completion
types in phase one. The north-to-south
cross sections in Figure 2 show all microseismic events (colored by stage) from
phase one (top) and phase two (bottom).
In all but one stage in phase two the
maximum vertical height growth did not
exceed 300 feet. The very shallow events
on the south (right) end of the bottom
picture are the product of simultaneous
operations on an adjacent pad.

Of the 610 located microseismic events
in phase two, 42 were related to simultaneous drilling operations on an adjacent
pad and 273 (48 percent) of the remaining
568 events were in zone. Height growth
out of zone was significantly and systematically reduced.
Hydraulic Fracture Model
Since the entire phase two wells were
pumped with the same recommended design, not as many stages needed to be
hydraulic-fracture pressure-history
matched in order to get a high number of
data points (FPHM was used on a little
more than half of the stages on both
wells). The previous GOHFER® planar
3-D geometry fracture simulator model
was able to achieve high confidence
matches when shifted to the Adam Good
Bear 15-22HW.
On the State of North Dakota 103HA, however, the GOHFER model
showed a significant mismatch at the beginning-of-job and end-of-job instantaneous shut-in pressure, indicating that
the MEM model was not an accurate
representation of current stress conditions.
The original 10-3H well is 1,400 feet
away from the 10-3HA, and a sidetrack
exists on the 10-3HA. These both could
be affecting the initial stress state. Therefore, only the results from the Adam

FIGURE 2
Comparison of Height Growth for Phases One and Two (Top = Past
Design; Bottom = Current Design; Grid Cell Size = 250 x 250 feet)

Bakken Lateral
Three Forks Lateral

JANUARY 2015 95

American Oil and Gas Reporter - January 2015

Table of Contents for the Digital Edition of American Oil and Gas Reporter - January 2015