American Oil and Gas Reporter - September 2015 - 75

SpecialReport: Reservoir Characterization
indicate the average perforation depth for
each stage.
On the right side of the plot, the wellbore crosses stratigraphy such that the well
lies in the same stratigraphy for stages 1
through 7, and crosses bedding in stages
8 through 15. The green line is the average value of the deepest 15 percent of microseismic events in each stage, representing the quantile at the low side of each histogram.
The results show a clear pattern of two
"bounces" of the histogram centers along
the length of the borehole capable of significantly impacting the amount of fracture contact within the producing interval.
The bounces are evident in the quantile
measurement (green line) at the average
depth of the deepest 15 percent of microseismic events.
Beginning with the first stage at the toe
of the well (left side of the plot), fractures
are centered at the borehole. The fractures
in the following stages gradually moved
upward about 200 feet (stages 3 through
6). They subsequently returned to the borehole in the middle of the well (stages 7
through 10), and the pattern repeated.
Analyzing the histograms with 2-D
FFT and correlation coefficients between
histograms verified that the microseismicobserved depth histograms behaved in a
two-bounce cycle along the well's axial
direction. Each histogram, taken as a series of values representing the relative frequency of points in each depth bin, was

FIGURE 4
Normalized ISIP, Maximum Treating Pressure and Job Size (Utica Well A)
1.2
1.0

Nrm SIP

Normalized Pressure

1.00

0.4

0.66

0.2

0.33

8
9
Stage No.

correlated with all other histograms. The
histograms are similar to their immediate
neighbors and to other histograms located six to seven stages distant, and again
to histograms located 12-14 stages away
(see SPE paper 170924).
Figure 4 shows normalized instantaneous shut-in pressures (ISIPs) (yellow
line), normalized maximum treatment
pressure (pink line), and normalized job size
index using a product of sand and water
pumped (yellow bars) from well A. Comparing these data to Figure 2C, the observed
out-of-zone bounces coincide with systematic changes in ISIPs and maximum pressure, as well as difficulty in placing the entire job (indicated by shorter yellow bars).

Sigma_v
Sigma_h
Sigma_H

2,500
2,000
1,500
1,000
500

0.00

The lower ISIPs occurred when smaller jobs were not able to develop the same
in-zone net pressure or fracture widths. The
shorter jobs for stages 1, 7 and 9 coincide
with fractures that remained in zone.
Stages that bounced upward had bigger job
sizes because they were easier to pump.
By the time the second bounce returned to
the wellbore (stage 15), the engineers already had adjusted by pumping higher-viscosity fluids, which may have helped finish the job.
Tracking Stress Shadowing

Quantile analysis measures the depth of
a portion of the histogram. For values that
change slowly from one stage to the next,

4,000

hf = 100 ft
Pt = 11,500 psi
σh = 7,860psi

3,500
3,000
Induced Stress (psi)

3,000

FIGURE 5B
Induced Stresses Along Fracture Cross-Section
(Fracture Height = 100 feet)

hf = 300 ft
Pt = 11,500 psi
σh = 7,860psi

3,500

Normalized Job Size

0.6

0.0

4,000

Sigma_v
Sigma_h
Sigma_H

2,500
2,000
1,500
1,000
500
0

Distance from Center of the Fracture (ft)

00
-7
00
-6
00
-5
00
-4
00
-3
00
-2
00
-1
00

-8

00
-7
00
-6
00
-5
00
-4
00
-3
00
-2
00
-1
00

Distance from Center of the Fracture (ft)

-500

-500
-8

Nrm MaxP

0.8

FIGURE 5A
Induced Stresses Along Fracture Cross-Section
(Fracture Height = 300 feet)

Induced Stress (psi)

Nrm Job Size

Relative increases in maximum treating pressure, decreases in ISIP, and
less sand pumped indicate unsuccessful fracs for stages 1, 7 and 9.

SEPTEMBER 2015 75

American Oil and Gas Reporter - September 2015

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