American Oil and Gas Reporter - July 2018 - 61

SpecialReport: Horizontal Wellbore Construction

Diagnostics Reveal Stimulation Effects
By Mark Odegard,
Charles Ohlson,
Neha Sahdev,
Jon Doucette,
Ben Bagherian,
and Wendell Salas
DENVER-Effectively applying multiple fracture mapping diagnostics technologies can help accelerate the learning
curve in horizontal resource plays, guide
well completion optimization strategies,
and give the operator exceptional knowledge concerning which technologies to
choose when targeting specific issues in
future field development work.
The capabilities of multiple diagnostic
technologies were demonstrated in a
project involving a "wine rack" of wells
completed in Niobrara A, B and C benches
on the Horsetail 30F well pad in the
Denver-Julesburg Basin. An extensive
survey was performed using both nearwellbore and far-field diagnostics to give
the operator insights into the completions
order of the wells, height growth in
various benches, well spacing, lateral
landing points, the effects of varying
treatment types and sizes, and cross-well
communication.
This project began with the intention
to expand the limits of an eight-well test
project on the Horsetail 30F pad to determine optimum well spacing while applying diagnostic tools to evaluate performance. A technical steering team and
an overseeing senior management advisory
committee were formed to manage project
expectations. The goal was to evaluate
the number of laterals per section to
contact as much of the reservoir as possible
to help maximize reserve recovery and
production per unit.
To address such a high-level goal, crucial direct learning objectives from this
project included:
* Optimum well density/well spacing
in the Niobrara A, B and C benches;
* Optimum fracture spacing;
* Number of stages per lateral;
* Treatment size and design;
* Completions timing/order; and
* Wellbore placement.

distributed acoustic sensing (DAS), wellbore pressure gauges, and a full suite of
water, oil and proppant radioactive tracers
to measure stimulation effectiveness, interstage communication and cross-well
communication.
The far-field diagnostics solutions included a new hybrid borehole microseismic/tilt array tool string deployed in a
dedicated vertical observation well to
measure fracture network height resulting
from direct fluid placement measured
near select stages. Surface-deployed interferometric synthetic aperture radar tilt
tools were used to measure microdeformation before, during and after stimulation
to quantify the proportion of fluid placed
along respective primary and secondary
azimuths, fracture dip, and the vertical
versus horizontal component to measure
the relative degree of complexity.
The analysis was performed on individual diagnostics independently, and
subsequently combined interpretations
led to a better understanding of the subsurface. In addition, surface microdeformation data provided significant insight
into the effects of "zipper fracturing" and
the importance of the treatment order of
the wells in optimizing results.
With all data available, a fracture
model history match on the permanent
fiber optics well was constrained to the
measured diagnostics. The final match
between the aerial deformation from the
surface tilt and calibrated fracture model
was excellent.

Understanding the actual hydraulic
fracture geometry is important in any
unconventional field development because
it dictates the stimulated reservoir volume
and drainage patterns. While understanding
the effects of various parameters (treatment
type, fluid type, stage lengths, number of
perforation clusters, etc.) on fracture
geometry is essential, it is also important
to understand the effect of multiple wellbores on a well pad.
The treatment order of the eight Horsetail 30F wells was decided with the objective of maximizing learnings. As shown
in Figure 1, the 1942 well was treated
first. Wells 1943 and 1947 were then
zipper fractured to measure the effect of
interference on the farthest wells and between the Niobrara A and C benches.
Wells 1941 and 1948 were then zipper
fractured to measure interference between
the B and C benches. Well 1944 had the
microseismic monitoring downhole array
and was treated last.
Permanent Fiber Optics
Permanent fiber optics were installed
on the outside of the casing string in
Well 1942 (B bench) and cemented in
place. This permanent fiber provides monitoring for the life of the well, with DTS
and DAS simultaneously recorded along
the entire wellbore over time. This provides
the ability to monitor the heat of hydration
post-cementing to understand the top of
cement, acquire real-time information on
primary treatment and quantitative fluid

FIGURE 1
Well Layout, Target Bench and Order of Treatment for Horsetail 30F Pad

Diagnostics Technologies
The near-wellbore diagnostics included
permanently installed fiber optical distributed temperature sensing (DTS) and
JULY 2018 61
American Oil and Gas Reporter - July 2018

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