American Oil and Gas Reporter - November 2016 - 38

The DAS/DTS-observed fracture treatment distributions were modeled in a
gridded, fully decoupled 3-D hydraulic
fracture model to visually represent the
resulting fracture geometries. This process
was used to evaluate the impacts on the
resulting treatment distributions that occurred as a result of stress-shadowing between fractures. The ultimate goal was to
understand the influence that adjacent
fractures within a stage and adjacent
stages have on fracture distribution, fracture
geometry, and completion effectiveness.
The horizontal subject well was a toeup completion consisting of 14 plugand-perf treatment stages and a total
completion length of 4,113 feet. Each
treatment stage consisted of three, fouror five-perforation clusters spaced at intervals of 51-150 feet. Each cluster was
one to two feet in length with five shots
per foot and 0.42-inch entry holes (4050 total perforations per stage).
The frac stages were designed to
consist of three individual proppant ramps,
each separated by pad-only diverter drops.
Total fluid pumped per stage ranged from
4,132 barrels on stage 3 to 12,479 barrels
on stage 14, with most stages between
10,000 and 11,000 barrels. Total proppant
volumes ranged from 161,000 pounds
on stage 3 to 480,000 pounds on stage 9.
DAS/DTS Data Acquisition
Optical fiber was strapped to the
outside of the production casing and ceFIGURE 1
DTS Profile Showing
Interstage Communication

mented in place in the well. Prior to initiating completion operations, the interval
was mapped to determine the location of
the fiber around the periphery of the casing. Each stage was perforated then at
zero-degree phasing with perforations
located 180 degrees from the fiber to
minimize the potential to damage the
fiber during perforating and fracturing.
In addition to temperature and acoustic
fiber data, surface microseismic data were
collected throughout the stimulation treatment.
Intrastage communication between
subsequently treated stages was surprisingly common. As shown in the DTS
profile in Figure 1, 10 of the 14 stages
(71 percent) showed intrastage communication. Stages 1-7 are shown at the top
(stage 1 to the left and stage 7 to the
right), and stages 8-14 are shown on the
bottom (stage 8 to the left and stage 14
to the right).
Communication between subsequent
stages is indicated by the black boxes,
with the numbers showing the treated
stages (top numbers) and the stages with
which they communicated (second/third
numbers). The individual perforation
clusters are indicated by the green triangles
on the left of the figure.
As the treatments move uphole, communication with lower stages/clusters
can be observed. In stages 2, 5, 6, 9, 10
and 12, communication was limited to
the previously treated stage (i.e., stage 2
communicated with stage 1). However,
four stages (7, 11, 13 and 14) communi-

cated with the two previously treated
stages (i.e., stage 7 communicated with
stages 5 and 6).
Evidence suggests that stage 2-tostage 1 communication was to the result
of annular fluid flow. However, the communication in nine of the 10 cases was
the result of leaking plugs. This conclusion
is based on the character of the DTS
profile, which showed distinct entry points
associated with the perforation cluster
depths of the deeper stage(s) during treatment. The entry points indicate fluid exiting from the interior of the well rather
than communicating along the annular
portion.
Figure 2 demonstrates the impacts of
stage-to-stage leakage on the overall completion in terms of proppant distribution
for each stage, including proppant placed
by communication from adjoining stages.
The colored bars show final DAS-determined proppant distribution, while the
black dots indicate the proppant volume
pumped for each stage.
Leakage clearly had an impact on the
final completion profile, yet interstage
communication was not detectable from
surface pressure observation. Without
DAS/DTS data, interstage communication
would have gone undetected.
Proppant Distribution
As has been observed in other fiber
datasets, there was a distinct bias for the
largest portion of any given stage to exit
one of the two clusters closest to the
well's heel. Seven of the 14 stages showed

FIGURE 2
Final Proppant Distribution (All Stages)

DTS Stages 1-7

600,000

500,000

DTS Stages 8-14

Proppant Mass (lbm)

400,000

300,000

200,000

100,000

0
1

Stage
Proppant Placed in Stage (lbm)

38 THE AMERICAN OIL & GAS REPORTER

Proppant Pumped in Stage (lbm)

American Oil and Gas Reporter - November 2016

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