American Oil and Gas Reporter - August 2016 - 70

SpecialReport: Hydraulic Fracturing Technology
FIGURE 2A
Well K Niobrara Structural Cross-Section

FIGURE 2B
Well L Niobrara Structural Cross-Section
Well L

Well K

A Marl

A Marl

B Chalk
B Chalk

Toe
C Chalk

Toe
C Chalk

Landing

Landing
Ft. Hayes

Ft. Hayes

South

North

South

FIGURE 3
Limited-Entry (Top) versus Intrastage Diversion (Bottom)
Example with Tracers

had four perforation clusters in each stage
(80 total). Both wells had six perforation
shots per foot and 0.35-inch diameter
holes.
The ability to pump eight fewer stages
enabled Well L to achieve substantial
cost savings. The intrastage diversion
process used on Well L consumed 11
percent less proppant than Well K, and
while the treatment pumped 15,000 more
barrels of fluid than in Well K, almost all
of this difference came from the slickwater
part of the hybrid frac and not the crosslinked fluid system.
A step-rate test was performed before
each stage in Well L except stage 1,
where no diverter was applied as a precautionary measure. The step-rate test
results were then applied to a proprietary
algorithm to determine the amount of di70 THE AMERICAN OIL & GAS REPORTER

verter to pump. The main objective with
diversion is to ensure uniform near-wellbore proppant distribution, instead of
having proppant follow the path of least
resistance. An example from a pilot well
is shown in Figure 3, comparing proppant
concentration from a limited-entry stage
treatment at top with an intrastage diversion stage treatment (bottom). The tracer
log confirms the intrastage diversion representation.
Since a diagnostic fracture injection
test (DFIT) was not available in any of
the Niobrara wells, representative information from the area was used to history
match a few of the stimulation stages in
both wells K and L before calibrating
the fiber optic results. Stage 26 in Well
K was randomly chosen for treatment
history matching. A maximum proppant

North

concentration of 4 pounds/gallon was
pumped in this stage and the model treatment data agreed well with the actual
data without any calibration from fiber
optic diagnostics. However, a history
match analysis of proppant distribution
showed some perforations in stage 26 received no treatment. This could have
been the result of "stress shadowing"
from other clusters.
Similarly, stage 1 was randomly chosen
for the Well L treatment history match
analysis (intrastage diversion was not
fully implemented until stage 2 onward).
The modeled data matched closely to the
actual data without any calibration from
the fiber optics diagnostics results. Since
it was the first stage in the well, a conservative maximum proppant concentration
of 3 pounds/gallon was pumped. The history match analysis shows all perforation
clusters getting some treatment and uniform proppant distribution across the
target intervals. The log properties for
the fracture model were developed from
the same vertical offset well and the
reservoir properties used were similar for
both wells.
The stimulation treatment history match
analysis was performed to understand
the proppant distribution effects with and
without diversion prior to any calibration
to DTS and DAS fiber optics diagnostics
results. Getting meaningful results, especially in regard to fracture geometry,
requires calibrating with fiber optics diagnostics.
Fiber Optic DTS And DAS
Coiled tubing-deployed fiber optics
is extremely versatile and efficient, and
can be deployed multiple times in multiple
wells to acquire DTS and DAS data along
the length of the CT or wellbore. Diag-



American Oil and Gas Reporter - August 2016

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