American Oil and Gas Reporter - February 2021 - 76

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SpecialReport: Permian Resource Solutions
involves only fluids and no sand, thus
any adverse communication is short-run
as the unpropped fractures close after
pumping ceases with very little or no impact on production.
An estimated 6% of interwell communication signals can be tracked to a
phenomenon described as a poroelastic
frac hit, where the net pressure acting
on newly created fracture surfaces compresses the rock. More commonly referred to as frac stress shadowing, a
poroelastic interaction occurs beyond
the near-field fracture area and is distinguished by disturbances in the rock
properties, specifically increasing the
in situ stresses, with negligible to zero
impact on production.
Perhaps one of the most worrisome
issues is when no pressure changes or
detectable tracer recoveries are measured
during or after stimulation of the parent
well. The detection of no interwell communication events implies no fluid mass
exchange. Accordingly, it can be assumed
that productive reservoir space is being
left undrained between the parent and

child well.
Given that a certain degree of interwell
communication is desirable, the optimal
solution for promoting hydrocarbon flow
and EUR combine fluid migration with
poroelastic interaction, while avoiding a
direct hit between two sand-filled fracs.
This is where the new-generation smart
tracers and a surgical approach to precisely
diagnose the type and severity of a frac
hit play a vital role in spacing tests to enhance reservoir performance.
Conventional Approaches
Measuring the severity of a perceived
frac hit down to the stage level is fundamental to an effective infill development
program, but until now, the detection and
characterization of same is best described
as guesswork. Installing a wellhead pressure gauge on an offset well and observing
the response after the child well is fractured
provides an indirect indication of interwell
communication. A gradual pressure
buildup on the offset suggests fluid migration, while a rapid increase in pressure
indicates direct communication.

Response to an accelerated pressure
spike often includes the pumping of diverters or pressurizing of the offset well
to counteract the fracture growth, but
the effectiveness of either method can
be uncertain and result in unnecessary
expense without an accompanying flow
tracing mechanism.
Operators have long relied on wateror oil-soluble chemical tracers to evaluate
fracturing performance, but the solubility
of conventional liquid tracers requires
they be tailored for the individual fluid
streams intrinsic to each stage. The heterogeneity of shale rock along a horizontal lateral and the assorted fluid compositions requires different and specially
formulated chemical tracers that can add
as much as $150,000 in incremental
costs per well.
Chemical tracers disseminate quickly
in the rock matrix and flush from the
proppant pack, significantly reducing the
effective monitoring window and further
increasing the uncertainty on residual
tracer volume. Furthermore, the interpretation of chemical tracing test results

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American Oil and Gas Reporter - February 2021

Table of Contents for the Digital Edition of American Oil and Gas Reporter - February 2021

Contents
American Oil and Gas Reporter - February 2021 - 1
American Oil and Gas Reporter - February 2021 - Cover1
American Oil and Gas Reporter - February 2021 - Cover2
American Oil and Gas Reporter - February 2021 - Contents
American Oil and Gas Reporter - February 2021 - 4
American Oil and Gas Reporter - February 2021 - 5
American Oil and Gas Reporter - February 2021 - 6
American Oil and Gas Reporter - February 2021 - 7
American Oil and Gas Reporter - February 2021 - 8
American Oil and Gas Reporter - February 2021 - 9
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American Oil and Gas Reporter - February 2021 - Cover3
American Oil and Gas Reporter - February 2021 - Cover4
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