American Oil and Gas Reporter - January 2015 - 103

Unconventional Resource Science
terpretation increased the number of hydraulic fractures from one to three.
Figure 3 shows a similar example of
microseismicity separation, correlating
microseismicity both during (black) and
after (white) injection with the engineering
curves. The orange line shows interpreted
hydraulic fractures and the red line shows
pre-existing structures. The yellow rectangle highlights events that occurred in
the previously stimulated stage. The injection rate (black) and pressure (red)
also are shown during stage stimulation.
Microseismicity is shown by circles colored according to SNR.
Microseismicity during injection had
a clear northeast-to-southwest trend, with

FIGURE 4
Example Microseismicity During (Yellow) and After (White) Injection

Stage 1
90

12,000

1,000

Pressure Drop

3,000

7

900

80

6

10,000

2,500
800
70

8,000

5

700
2,000

500

1,500

40
400
30

4

3

BH Sand Ratio (psa)

4,000

600
50

Distance from Stage (feet)

6,000

Pump Rate Tot. (bpm/min.)

60

SNR

Study Results
After separating the events according
to injection time, microseismicity analysis
showed the northeast-to-southwest trend
was characteristic of microseismicity that
had occurred during injection, while the
east-to-west trend was characteristic of
microseismicity that had occurred mostly
after injection had stopped. The events
that occurred during injection showed
clear alignment along the maximum horizontal stress, confirming that they were
related to hydraulic fracture propagation.
The seismicity that occurred after injection had a distinct east-west trend
related to the reactivation of a pre-existing
structure. In this case, the well was drilled

to intersect the maximum possible number
of natural fractures, so its direction was
not aligned with Shmin.
Microseismic events that occurred during injection were significantly less numerous. It is not necessary to have a lot
of microseismicity to analyze the stimulation and determine hydraulic fracture
length and SRV, but it is necessary to understand which process microseismicity
relates to. By selecting only the injection
events, it became possible to see the
events aligned in the direction of SHmax,
and therefore, to interpret a hydraulic
fracture for each stage, which was not
possible while interpreting all the microseismic data at once. In this case, the in-

Calculated Bottom-Hole Treatment Pressure (psi)

nitudes are usually signs of shear events
on larger pre-existing structures.
It is difficult to calculate a b-value for
microseismic datasets related to hydraulic
fracturing because of the typical low range
of magnitudes and the small number of
events. Taking into account a detection
limit for the small magnitudes, it is impossible to detect a large range of magnitudes for a hydraulic fracture dataset,
making the b-value difficult to determine.
However, as a first approximation, a
dataset with a b-value of one can be expected to have more high-magnitude events
than a dataset with a b-value of two.
An additional problem for surface microseismic arises from having signal-tonoise ratios (SNRs) without event magnitudes. If noise changes from job to job,
stage to stage, or during a stage, the SNR
is not an appropriate representation of
magnitude. The seismic noise level measured during one stage is shown as the
purple curve in Figure 2, which shows
an example of a stage where major microseismic activity occurred after injection
stopped (after 100 minutes).
Microseismicity is shown by circles
colored according to SNR. The seismic
noise level measured on the seven closest
patches (median value) is represented in
purple. The change of noise from the injection to the post-injection period is noticeable, but negligible compared with
the variation in SNR. The high SNR in
the post-injection period is caused by the
change in the physical process. For bvalue calculations, the magnitude is approximated from the SNR based on the
proportionality of the amplitude of a
signal to the seismic moment.

1,000
300

2,000

2

20
200
500
1

0
10

-2,000

100

0

0
50

100

150

200

0

0

250

Time (min)

JANUARY 2015 103



American Oil and Gas Reporter - January 2015

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

Contents
American Oil and Gas Reporter - January 2015 - Cover1
American Oil and Gas Reporter - January 2015 - Cover2
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American Oil and Gas Reporter - January 2015 - Contents
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