American Oil and Gas Reporter - April 2020 - 46

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a slight reduction in the pressure decline
rate at the onset of wireline pump down,
highlighting the sensitivity of the measurement. Stage 2, shown at the upper
right of the figure, has many of these
same signatures.
SWPM provides a powerful diagnostic to quickly determine VFR during
offset well completion. A higher VFR
suggests more uniform fluid distribution,
which creates more similar fracture
geometries and improves drainage efficiency within the stimulated rock volume. A lower VFR indicates poor fluid
distribution within a stage, which can
lead to dominant fractures with excessive
geometries, increasing the potential risk
of "short-circuiting" well spacing and
excessive well communication. Several
factors can affect VFR, including rock
mechanical property heterogeneities,
geologic structure, faults, natural fractures, unequal perforation diameters,
an insufficient pressure drop across perforations, poor cement isolation and a
faulty frac plug.

Shortly after intersection occurred, the
second fracture stopped growing, shown
by the lack of tension at this depth and
pressure decrease, amplified on the derivative plot. At the end of Stage 1, the
strain plot shows three fractures in a
compressive state, which is interpreted
as three hydraulic apertures decreasing
in width at the monitor well location.
Sealed wellbore pressure began to decrease
when the stage was completed and pumping ceased.
In multistage plug-and-perf horizontal
completions, wireline is pumped down
the lateral between each stage to set a
plug to isolate the previous stages before
shooting new perforations for the next
stage. As wireline is pumped down, fluid
re-enters the fracture created in the previous stage. When pumping wireline after
Stage 1 at 15 bbl/minute, two areas of
tension were evident (denoted in Figure
1). These are believed to be reactivations
of the two most conductive fractures from
the previous stage. SWPM also recorded
FIGURE 2

Microseismic and SWPM for Stages
With and Without Pre-Existing Fractures
No Pre-Existing Fractures

Volume vs. Distance
2,500

1,400

1,000

0 ft /s
2

800

0 ft /s
2

D=2

1,200
Northing (ft)

1,200

1,500

Distance to Gauged Well (ft)

1,400

1000

Gauge Well

1,600

VFR Diffusivity

D=4

Stim Well

1,600

MS Diffusivity

2,000

1,800
1,800

VFR

Distance (ft)

Map View

2,000

MS Events

1,000
800
600

600

400
400

500

200
200
0
0

0
0

800

1,600

2,400

3,200

4,000

4,800

5,600

6,400

7,200

500

2,000

Easting (ft)

Pre-Existing Parent Fractures

Map View

Volume vs. Distance
2,500

2,000

MS Events
1,800

VFR

t /s

1,600

VFR Diffusivity

1,200
1,000
2

ft
= 30

800

Distance to Gauged Well (ft)

1,400
1,500

1000

Gauge Well
Parent

2,000

MS Diffusivity

1,500
Northing (ft)

f
45

Stim Well

2,000

Distance (ft)

1,500

1,000

Volume Pumped (bbls)

1,000

600

Parent

D2
500

400

500

200
0

0
0

800

1,600

2,400

3,200

4,000

4,800

5,600

6,400

7,200

Volume Pumped (bbls)

46 THE AMERICAN OIL & GAS REPORTER

0
0

500

1,000

1,500
Easting (ft)

2,000

2,500

Meramec Case Study
Field applications of SWPM have
demonstrated the technology's effectiveness in quantifying in real time the cluster
efficiencies of hydraulic fracturing treatments. In the Anadarko Basin's STACK
play, SWPM monitoring was used successfully to evaluate depletion impacts
on fracture geometry and estimate fracture
geometries and the presence of frac
barriers in the Meramec formation. Meramec lithofacies include tight carbonates
(silty peloidal skeletal packstone), sandrich carbonates (calcite cemented siltsandstones), siltstones, calcareous siltstone,
argillaceous silt-sandstones, and clayrich siltstones.
Meramec reservoir quality and rock
mechanical properties are broadly controlled by the amount of early calcite
cementation. The stress regime in the
Meramec is strike-slip, where the overburden is the intermediate principal
stress. Tensile natural fractures, observed
from image logs, are associated with
tight carbonates and sand-rich carbonate
facies. However, image logs tend to underestimate fracture counts when compared with Meramec core.
The primary landing zone in the area
of interest is the upper half of the Meramec,
which has higher porosity, permeability
and pore pressure. An area of pore pressure
gradient transition occurs between the
upper and lower Meramec, which are
separated by a low porosity, high calcite
interval that potentially can act as a frac
barrier. It is critical to determine whether
created hydraulic fractures can breach
this barrier and contact both the upper
and lower Meramec intervals from a
single horizontal wellbore.
Microseismic and SWPM were collected on a 12-well development in the
Meramec formation to improve the understanding of parent depletion and
parent fractures on the stimulation of
infill wells. Microseismic data was collected with a surface array and had an
average perf-relocation error of seven,
15 and nine feet for the x, y, and z directions, respectively. An initial comparison of the microseismic and SWPM

American Oil and Gas Reporter - April 2020

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