American Oil and Gas Reporter - January 2015 - 102

The microseismic event dataset was
derived from processing 3-D "patchbased," surface-recorded data. Data were

recorded continuously during and between
hydraulic fracturing operations in each
stage. More than 4,000 microseismic

FIGURE 2
Significant Post-Injection Microseismic Activity
Stage 9
50

10,000

1,000

9,000

900

8,000

7,000

3,000

6
2,500
800

Pump Rate Tot. (bpm/min.)

Wellhead Treatment Pressure (psi)

5,000

4,000

600
50
500

400

1,000

30
15

1,500

BH Sand Ratio (psa)

6,000

2,000
Distance from Stage (feet)

700
60

SNR

RMS Median of Nearest 7 Patches to Well Pad (nm/s)

3,000

300

20
10

2,000

1,000

200

500
1
10

100

150

200

250

Time (min)

FIGURE 3
Correlation of Microseismicity During (Black) and After (White) Injection
Stage 7
12,000

1,000

3,000

Pressure Drop
900

8,000
Pump Rate Tot. (bpm/min.)

2,000
600

50
500
40
400
1,000

30
300

2,000
20

500
10

200

-2,000

1,500

100

150
Time (min)

200

250

102 THE AMERICAN OIL & GAS REPORTER

BH Sand Ratio (psa)

4,000

700
60

Distance from Stage (feet)

6,000

2,500
800

SNR

Calculated Bottom-Hole Treatment Pressure (psi)

10,000

events were detectable and locatable both
during and after pumping the 10 stimulation stages.
As a first step of the analysis, events
that occurred during injection were separated from events that occurred post-injection. After proppant and fluid injection
stops, the pressure gradient changes and
the fracture can no longer propagate in
tension. As the main hydraulic fracture
closes, it changes the stress regime in the
surrounding area. By separating the data
according to injection time, events that
were not related to hydraulic fracture
propagation (i.e., associated with fault/fracture reactivation) can be isolated from
the dataset.
Hydraulic fractures propagate in the
plane perpendicular to the minimum stress
in the region. The extent of the fracture
is limited by the stress barriers that typically are present in the vertical direction
because of stratigraphic layers, but also
in the horizontal direction because of
pre-existing structures and local heterogeneities. Microseismic events related to
hydraulic fracture propagation should
align along the plane of the hydraulic
fracture. Because of the stratigraphic layers, microseismicity often aligns along
the direction of maximum horizontal
stress (SHmax).
Of the sets of pre-existing structures
of various orientations, the set most favorably oriented for reactivation had an
azimuth about 30 degrees from SHmax in
the plane of SHmax and minimum horizontal stress (Shmin). Therefore, microseismicity related to hydraulic fracture
propagation and reactivation of pre-existing structures should show different
geographical trends.

Data Separation Constraints
Pressure declines and injection rates
can provide constraints to data separation.
If pressure in a well suddenly drops while
the injection rate is held constant, some
significant volume of fluids had to be
lost down hole. Such a sudden drop most
likely is related to the loss of fluids in a
fault.
Microseismic event magnitudes and
"b-values" provide additional constraints
to data separation. The b-value is related
to the relative magnitude distribution in
a dataset. If the logarithm of the number
of earthquakes of a given magnitude decreases by one with an increasing unit of
magnitude, then the b-value is one. If the
logarithm decreases by two with an increasing unit of magnitude, then the bvalue is two. From an interpretation point
of view, a b-value greater than one is
typical for hydraulic fracturing. For the
value of the magnitude itself, larger mag-

American Oil and Gas Reporter - January 2015

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