American Oil and Gas Reporter - September 2016 - 55

FIGURE 5
Four Stages on Second Well Pad Mapped
With Hybrid Microseismic/Microdeformation Array
Depth scaling is 2:1

Well 4 - Stage 1
Well 5 - Stage 1
Well 5 - Stage 2
Well 5 - Stage 3

TVD (feet)
7,000

6,000

Looking N60°E

Well 4
Well 5
Well 6

8,000

the laterals.
The hybrid microseismic/microdeformation array was used to map four stages
on the second pad to determine whether
the significant upward microseismic height
growth was related to hydraulic fractures
opening, or stress-related events with no
significant deformation. This was a key
question because shallow events seemed
to generate a much larger event cloud
spread in map view, suggesting they
might be stress-related events along bedding planes in the highly laminated and
potentially critically stressed formation,
and not necessarily related to adjacent
hydraulic fractures with meaningful deformation.
The microdeformation data show 5060 percent less fracture height growth
than indicated by microseismic (Figure
5). Fracture tops are at 6,900 feet TVD
in the Niobrara and the fracture bottom
is in the Fort Hays, with total fracture
heights of 750-950 feet. Microseismic
data also show an area of less activity
between 6,900 and 7,200 feet, which
may be related mechanically to the microdeformation results.
Proppant transport during slickwater
fracturing is known to create significant
"dunes," and it is likely that proppant
was placed only in the bottom portion of

VMW1
6,000

7,000

8,000

9,000
10,000
Distance along Cross Section (feet)

the fracture height below 7,200 foot TVD.
SDT And Fall-Off Tests
Several stages included step-down
tests (SDT) to evaluate near-wellbore and
perforation friction. For example, high
near-wellbore friction of 1,300 psi at 30
bbl/minute was observed on stage 39 in
well 5. The test showed low perforation
friction (50 psi).

11,000

12,000

13,000

14,000

As noted, all six wells had some
pumpability and lower injectivities issues,
which could have been a result of well
positioning within the section. For example, lower calcite (higher clay) percentages in a stage interval could be
related to lower hydraulic fracture injectivity or higher near-wellbore tortuosity.
Fracture closure stress is a critical
input parameter for net pressure matching.


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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
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