American Oil and Gas Reporter - January 2015 - 97

Unconventional Resource Science
Good Bear 15-22HW were used. The results from these matches were consistent
with what the model was predicting for
the recommended design fracture geometry.
Figure 3 shows how the propped fracture
length area (PFLA) and fracture height
from phase two compared to the rest of
completion/isolation combinations. With
the optimized completion design, fractures
are being achieved that maximize PFLA
while limiting height growth out of zone.
Tracer Data
Multiple types of tracers were utilized
to observe possible communication between offset wells, to better understand
productive communication between the
Three Forks and Middle Bakken formations, and to monitor oil flow along the
wellbore over time.
Proppant tracers were pumped with
proppant in both the State of North Dakota
10-3HA and Adam Good Bear 15-22HW.
Figure 4 shows the isotopes pumped and
the locations along the wellbore where
they were used. The traced wells were

logged using a spectral gamma ray tool.
The original plan for the project included
logging three offset wells, but only one,
the State of North Dakota 10-3HW, was
successfully logged because of weather
complications and economic considerations.
Proppant tracer was not detected within
the wellbore or the near-wellbore region
of the 10-3HW well. This was in contrast
to the considerable amount of proppant
tracer detected on direct offsets of the
previous fracture treatment design, which
used less proppant and fluid volume but
fewer entry points and number of stages,
compared with the recommended design
utilized on the 10-3HA and 15-22HW
wells. This was a significant result, as
one of the goals of the recommended design was to more effectively control the
fracturing treatment energy to prevent
overstimulation and maximize treatment
within the oil-producing zone.
Both oil-soluble and water-soluble
chemical tracers were used. On the State
of North Dakota 10-3HA, five unique
oil-soluble tracers and five unique water-

FIGURE 3
Phase One and Two PFLA and Fracture Height Comparisons

Avg. PFLA for Phase 1 and Phase 2 (ft2)

180,000
160,000
140,000
120,000

soluble tracers were pumped during the
frac treatment. Following treatment, samples of production fluids were taken from
the treatment wells and several offset
wells (Figure 5).
A noteworthy observation was that
oil-soluble tracers pumped during the
treatment of the No. 10-3HA were not
observed in samples collected from the
nearest offset to the east (the State of
North Dakota 10-3HW, a Three Forks
well). However, oil-soluble tracers were
detected in the next nearest offset well to
the east (the State of North Dakota 103H, a Middle Bakken well). The two
offset wells to the west of the 10-3HA
(the Brunsell 16-9H and the Van Hook
16-4H) also both had oil-soluble tracers
detected in production fluid samples.
These results, combined with the fact
that proppant tracer was not detected in
the State of North Dakota 10-3HW,
suggest that the recommended design
pumped on the State of North Dakota
10-3HA may have resulted in preventing
downward growth into the Three Forks
formation. Also noteworthy was that oilsoluble tracers were detected in both directly offsetting wells to the Adam Good
Bear 15-22HW, which are both Middle
Bakken, while the Adam Good Bear 1522HW is a Three Forks well. This is in
agreement with microseismic results that
show height growth into the Bakken from
the Three Forks.
FIGURE 4
Proppant Tracer Layout and
Logged Wells

100,000
80,000
60,000
40,000

Logged

20,000
0

Iridium
Double

Optimized

Single

PLUG & PERF

PLUG & PERF
Cemented

Single

RAPID FRAC SLEEVE

STIM SLEEVE

OH Packers

Scandium
Antimony
Bakken Lateral
Three Forks Lateral

450

Avg. FPHM Fracture Height (ft)

400
350
300
250
200
150
100
50
0

Double

Optimized
PLUG & PERF
Cemented

Single

Single
PLUG & PERF

Single

RAPID FRAC SLEEVE STIM SLEEVE
OH Packers

JANUARY 2015 97

American Oil and Gas Reporter - January 2015

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