American Oil and Gas Reporter - September 2016 - 53

calcite content in all six wells, providing
confirmation of targeting potentially higher
calcite layers to improve fracture placement. In fact, the stages with fracture
placement problems in well 6 correlate
to areas along the lateral with low calcite
content/injectivity.
Microseismic, Hybrid Data
Microseismic fracture mapping was
performed on all six wells, and microdeformation monitoring was performed on
four stages on the 4-5-6 pad with a hybrid
geophone/tiltmeter array. Wells 1 and 3
were monitored with a horizontal tool
string array located in well 2, which subsequently was monitored using a vertical
tool string in well 3.
Because of observation distance limiting microseismic events, only the heelhalf of well 2 and the toe-half of the 4-56 pad were mapped. A vertical observation
well was located near the toes of wells 4,
5 and 6 to position the microseismic/microdeformation tool string.
Figure 3 shows map and side views
of all microseismic events colored by
well. The hydraulic fractures created a
high number of microseismic events with

FIGURE 2
Map (Left) and 3-D (Right) Views Showing Spatial Positioning
Of Six Wells Colored by Gamma Ray Count along Laterals
(15x Vertical Exaggeration)
Map View

3-D View-15x V.E
#1

#6

#4

#2

#5

GR
Scale

#3

150
145
140
135
130
125
120
115
110
105
100

#4

#5

#3
#6

#1

#2

FIGURE 3

-6,000

-4,000

-2,000

0

2,000

4,000
6,000
East (feet)

8,000

10,000

12,000

14,000

16,000

12,000

10,000

-10,000

8,000

-8,000

TVD (feet)
6,000

North (feet)
-6,000
-4,000

-2,000

4,000

0

2,000

2,000

4,000

0

Map (Left) and Side (Right) Views
Of Microseismic Events Colored by Well

-12,000

Completion Designs
Well 1 was completed with 2.37 million
pounds of 100-mesh and 7.045 million
pounds of 40/70-mesh white sand, and
529,561 barrels of slickwater with a maximum proppant concentration of 1.5 ppa.
Four of the 42 stages were challenging,
placing only 10-15 percent of the designed
proppant and 10-20 percent of the designed
fluid.
Well 3 was completed with 2.30 million
pounds of 100-mesh and 8.13 million
pounds of 40/70-mesh white sand, and
545,687 barrels of slickwater with a maximum proppant concentration of 1.5 ppa.
Of the 46 stages, six of were challenging
to place, pumping less than 5 percent of
the designed proppant and fluid volumes.
Well 2 had two stages in which only
50 percent of the designed treatment was
pumped. It was completed with 2.75 million pounds of 100-mesh and 13.03 million
pounds of 40/70-mesh white sand, and
545,687 barrels of slickwater with a maximum proppant concentration of 1.75
ppa.
Wells 4, 6 and 5 on the second pad
were completed six months later. Well 4
was completed with 2.89 million pounds
of 100-mesh and 10.42 million pounds
of 40/70-mesh white sand, and 660,475
barrels of slickwater with a maximum
proppant concentration of 2.0 ppa. Eight
of its 49 stages were challenging, placing
less than 10 percent of designed proppant
volumes.
Well 6 was completed with 1.69 million
pounds of 100-mesh and 9.38 million
pounds of 40/70-mesh white sand, and
527,992 barrels of slickwater with a maximum proppant concentration of 2.0 ppa.
Well 6 was the most challenging to complete, with 16 of 46 stages placing 25
percent or less of the designed proppant.
Well 5 was completed with 2.37 million
pounds of 100-mesh and 12.07 million
pounds of 40/70-mesh white sand, and
634,932 barrels of slickwater with a maximum proppant concentration of 2.0 ppa.
Open-hole borehole images, triple-combo,
and dipole-sonic were run in the lateral
of well 5. Continuous mechanical prop-

erties were interpreted along the lateral
and perforations were picked to place
initiation points at similar relatively lowstress intervals along the length of the
wellbore.
Landing the wellbore in a zone that
promotes efficient hydraulic fracturing
is critical to well performance and impacts
the geometry and complexity of induced
hydraulic fractures. The hydraulic fracture
injectivity index is a measure of fracturing
efficiency that is calculated by finding
the ratio of the average pump rate and
surface treating pressure for a given stage,
corrected for wellbore friction based on
the stage's measured depth. The injectivity
index is a measure of "fracturability,"
where a higher index indicates a formation
more accepting to treatment.
X-ray diffraction data collected in all
six wellbores allowed the laterals to be
characterized by three main mineralogical
classes: quartz, calcite and clay. The average weight percent of each class was
calculated for every stage interval and
was integrated with other engineering
and completion data along the lateral.
Although the data show high variability,
the injectivity index does increase with

-14,000

east direction, starting with wells 1, 3
and 2 on the first pad, and them progressing to wells 4, 6 and 5 on the second
pad. Figure 2 shows the map view and 3D relative positioning of the wells. The
selected well azimuth was roughly perpendicular to the maximum stress azimuth
and open natural fracture sets (Figure 1),
and allowed for a slightly toe-up lateral
while staying in zone. Gamma-ray log
data along all six laterals show both horizontal (especially wells 4, 5 and 6) and
vertical heterogeneity (deeper well 3).

0

2,000

4,000

6,000
8,000
Distance along Cross Section (feet)

10,000

12,000

14,000

SEPTEMBER 2016 53



Table of Contents for the Digital Edition of American Oil and Gas Reporter - September 2016

Contents
American Oil and Gas Reporter - September 2016 - Cover1
American Oil and Gas Reporter - September 2016 - Cover2
American Oil and Gas Reporter - September 2016 - Contents
American Oil and Gas Reporter - September 2016 - 4
American Oil and Gas Reporter - September 2016 - 5
American Oil and Gas Reporter - September 2016 - 6
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American Oil and Gas Reporter - September 2016 - Cover3
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