American Oil and Gas Reporter - September 2016 - 56

It was determined by monitoring the closure stress of a low-volume fracture initiation and fall-off at the toe of well 4.
The "mini frac" showed a fracture closure
gradient of 0.75 psi/foot with a pore pressure gradient of 0.67 psi/foot, indicating
that the target formation was significantly
overpressured.
The predominant fracture azimuth observed from microseismic (north 64 degrees east) more closely matched the azimuth of the open natural fractures observed in borehole images from the first
vertical test well than the high-stress direction, which is 15 degrees closer to
north than the natural open fracture azimuth (Figure 1). One interpretation is

that the planar nature of observed microseismic events (1,500-foot half-length
and 500-foot event cloud width) is that
dilation or activation of open natural fractures was mainly along the direction of
the hydraulic fracture, and not opening
the mineralized fractures along the northwesterly transverse azimuth.
Some pumpability issues appeared to
be related to pressure-dependent leakoff, where fluid was leaking faster than
expected in a bi-wing fracture. If the hydraulic fracture had encountered several
large, interconnected open natural fractures, it likely would have led to rapid
fluid leak-off and abrupt treating pressure
spikes.

FIGURE 6
Cumulative Gas Production Normalized by Proppant/Fluid
Placed per Foot of Lateral
180

1,143 lbs/ft & 64 bbls/ft

160

1,603 lbs/ft &
74 bbls/ft

Cumulative Gas Production per Lateral (Mcf)

140

1,146 lbs/ft &
59 bbls/ft

120
100
1,376 lbs/ft & 69 bbls/ft

1,485 lbs/ft & 64 bbls/ft

60
1,123 lbs/ft & 52 bbls/ft

40
20
0

100
Well #1

Well #2

150
200
Cumulative Producing Days
Well #3

Well #4

250

300

Well #5

350

Well #6

FIGURE 7
Map View of Production Logging Results
PLT Stage
Contribution
(Fraction of Total Gas)
0.100
0.090
0.080
0.070
0.060
0.050
0.040
0.030
0.020
0.010
0.000

*Diameter of disc also
representative of gas
contribution from stage

#6
#1

Stages logged in aggregate

56 THE AMERICAN OIL & GAS REPORTER

The hydraulic fracture model was updated after net pressure matching treatment
data. The fracture model then was calibrated using several stages in wells 1
and 5 along with the microseismic and
microdeformation data. The model results
were imported into reservoir models to
perform sensitivity studies for optimizing
completion designs.
Fracture modeling indicated propped
heights of 400-500 feet versus a total
fracture height of 950 feet as a result of
proppant settling and a propped fracture
half-length of 1,100 feet, with 1,400 feet
total fracture length matching the fracture
geometry observed with microseismic
(Figure 4). Most of the proppant was
placed in the Rangely Bench, with some
potentially in the lower portions of the
Niobrara.
In a follow-up study, the fracture modeling results will be imported into a reservoir model and used to perform sensitivities to optimize completion and well
spacing.
Production Results
Figure 6 shows cumulative gas production for all six wells normalized to
their respective start dates and the amounts
of proppant/fluid placed per foot of lateral.
Overall, the 1-2-3 pad appears to produce
slightly better than the 4-5-6 pad.
While there is no obvious correlation
between well performance and proppant
placed per lateral foot, individual well
performance on both pads was affected
by well interference and possibly landing
positioning, making it difficult to fully
evaluate the completion effects. Microseismic data did not show any significant
differences between individual wells besides the longer fracture half-lengths on
the 4-5-6 pad and the deep "outlier"
events indicating potential fault interaction.
Well interference was observed in gas
rates and wellhead pressures on wells on
both pads. For example, well 1 on the
first pad was shut in about 180 days after
starting production while preparing for
the completion work on the second pad.
When well 1 was shut in, production
from well 2 increased 50 percent, followed
by a small decrease when well 1 was put
back on line briefly. There also was a
small increase in well 2's rate when well
3 was shut in. When wells 1 and 3 were
both shut in, well 2's gas rate increased
by 75 percent. This indicates significant
communication across the 1,350-foot
spacing between the wells, especially
wells 1 and 2. Similar interference behavior
also was observed on wells 4, 5 and 6 on
the second pad.
Production logs were run on 150 stages

American Oil and Gas Reporter - September 2016

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