American Oil and Gas Reporter - February 2021 - 78

pages 75-79_Layout 1 2/15/2021 2:22 PM Page 78

FIGURE 2
Results of Eagle Ford Direct Frac Hit Flow Mapping (1,000-foot Well Spacing)

Direct frac hit

Direct frac hit

Northing (ft)

Direct frac hit

Direct frac hit
Direct frac hit
Direct frac hit

0

00

1,

ft

Offset Well

Traced Well

Easting (ft)

FIGURE 3
Direct Frac Hits Mapped in Toe Stages of Delaware Basin Well
(800-foot Spacing Between Traced and Offset Wells)

Northing (ft)

TVD (FT)

800 ft

Offset
Well

Traced
Well

Offset Well
S5
S4
S3
S2
S1

Traced Well

800 ft

Easting (ft)

78 THE AMERICAN OIL & GAS REPORTER

Toe Stages

E/W (ft)

extended time frame.
The delivery of once-inaccessible stagelevel flow profiles represent a novel advancement in understanding and measuring
direct frac hits, while promoting a surgical
interwell communication strategy sufficient
to optimize spacing and increase production
and EUR in unconventional wells.
Field Applications
As demonstrated in deployments in
the Eagle Ford and the Permian Basin,
the smart tracer and advanced diagnostics
played crucial roles in helping operators
re-evaluate their infill development spacing strategies.
An established operator in the South
Texas Eagle Ford play deployed the technology as part of a zipper frac application
on a five-well pad with 1,000-foot well
spacing. Before the introduction of the
smart tracer, stage-level flow profiling tests
had relied on chemical tracers and a combination of premium production logging
tools (PLT) and downhole fiber optics.
The distinctly tagged tracers were
pumped unobtrusively in a 21-stage well
after an analysis of the cross-linked gel
frac fluid, water and 100-mesh sand to
eliminate any background interference.
Tracer recoveries from the four offset
wells were analyzed over 20 days of
daily flowback sampling.
The recovery analysis showed extensive
direct frac hits on several stages of two
of the offset wells, indicating the interwell
spacing was too narrow and sacrificing
production (Figure 2). Furthermore, the
smart tracer recovery analysis showed a
heel-dominated flow profile for the final
nine stages, while two nonproducing frac
stages were detected at the toe section.
Seven stages exhibited strong production
rates, while another three were shown to
be underperforming.
To validate the analytical results from
the smart tracer, the operator ran PLT, and
followed with retrievable fiber optics to
the end of the lateral to measure the
acoustics and the temperature response.
The results from these technologies aligned
very closely with those of the smart tracer.
Elsewhere, surprising results from a
tracer application for an operator in the
New Mexico portion of the Delaware
Basin could prompt a re-evaluation of
both vertical and horizontal well placement
strategies. The smart tracer was deployed
on one well with a combined five toe
stages and 800-foot horizontal spacing
early in the field development stage as
part of an extensive investigation to determine optimum spacing. The smart
tracer was first pumped along with chemical tracers and permanent downhole fiber
optics. Chemical-based tracers were shown
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