American Oil and Gas Reporter - January 2020 - 54

Unconventional Resource Science
for each tracer be used to infer the degree
of fracture complexity?
As operators elect to enhance fracture
complexity by increasing perforation cluster density, using lower viscosity fluid
systems and pumping smaller mesh proppants, the modeling of fracture geometry
has proven difficult. In addition, varying
perforation cluster efficiency and "sand
duning" effects can prevent fluid and
proppant from being uniformly distributed
within the fracture network.
Without these effects, a piston-like
displacement of the frac fluid would be
expected within a given fracture. It also
is possible that a limited recovery of
the pad stage will be observed should it
be placed outside of the propped fracture
network. By tagging each fluid and sand
segment of the stage, the residence time
distribution of each tracer should yield
insight into fluid and proppant distribution.
The Wolfcamp formation in the
Delaware Basin is highly heterogeneous.
It contains interbedded shale and limestone.
The formation's carbonate in the northwestern part of the basin has light-colored
dolostone, while the Wolfcamp in the rest
of the basin consists of dark-colored lime
packstone, wackestones and mudstones.
The Wolfcamp's average thickness in the
Delaware is 2,000 feet, but thickness can
exceed 6,000 feet in the western portion
of the basin. Depth ranges from 10,000
to 12,000 feet, with the Wolfcamp divided
into four units: A, B, C and D, from
shallow to deep, respectively.
Unique Chemical Tracers
The Crimson study focused on a horizontal well drilled and completed in the
Wolfcamp B formation. The lateral length
is ±10,000 feet with 48 fracture stages.
Each stage consisted of ±500,000 gallons
of water-based frac fluid and 451,000 lbm
of sand. Slickwater and linear gel were
used as the carrier fluids. The pump schedule consisted of pumping 100-mesh sand
from 0.2 to 1.0 lbm/gallon, followed by
40/70-mesh sand from 1.0 to 2.0 lbm/gallon. The entire stage treatment was divided
into 15 segments based on the frac fluid,
54 THE AMERICAN OIL & GAS REPORTER

proppant size and concentration.
A total of 12 unique water-phase
tracers and oil-phase tracers were injected
into the heel-most stage (stage 48) to tag
individual fluid and sand segments beginning with the pad segment and ending
with the 2.0 lbm/gal, 40/70-mesh stage.
All fluid and sand segments were allocated
unique tracers. The tracers were continuously injected along with the frac fluid at
a constant concentration throughout each
individual segment. The chemical tracers
were "conservative" tracers, exclusively
soluble in their carrier fluid and resistant
to decomposing or reacting under subsurface conditions. The detailed tracer
injection layout and pump schedule is
shown in Table 1.
After the well was brought on line for
flowback and production, water and oil
samples were collected at the wellhead.
One sample a day was taken for the first
two weeks, followed by a reduction in
sampling frequency for the remainder of
the study. The entire sampling process
lasted 80 days, during which 21 water
samples and 21 oil samples were collected.
All samples were sent to the laboratory
for analysis. Water samples were analyzed
using high-resolution liquid chromatography-mass spectrometry (LC-MS) and
oil samples were analyzed using highresolution gas chromatography-mass spectrometry (GC-MS).
Tracer Data Results
Raw tracer concentrations measured
in the collected samples indicate that
tracers injected into different fluid and
sand segments were commingled to some
degree. Most of the tracers pumped were
detected in each sample, including the
earliest flowback samples. This shows
that some fluid pumped early in the treatment (i.e., pad) was placed near the wellbore, indicating a degree of fracture complexity. Enormous connectivity between
primary and secondary fractures may
result in sufficient blending of frac fluid
segments. This also could have been
caused by varying cluster efficiency during
the treatment, or duning effects at certain
perforation clusters.

In general, the tracer concentration in
each fluid sample declined over time as a
result of dilution from increasing formation
water influx. However, the tracer concentrations suddenly increased on July
25, which suggested that the water flow
contribution from the heel stage increased
relative to the prior sample date. This
normally would be verified by relative
changes in tracer production from other
fracture stages if that data was available.
The other fracture stages of this well
were not traced.
Normalizing raw tracer data to its injected amount accounts for the concentration variations related solely to the
different segment volumes. Segments
48G and 48F recovered more tracer than
other segments, but their normalized response was decreased somewhat, which
allowed for accurate comparison with
the other segments. Segment 48A, during
which 476 barrels of frac fluid were
pumped down hole, was selected as the
standard, and corresponding normalization coefficients then were applied to
other tracers.
Figures 1 and 2 show the normalized
concentration for each tracer. The vertical
axis represents the tracer concentration
in parts per trillion and the red curve indicates the average tracer concentration
during the sampling period.
The earliest segments for both phases
of tracer display overall increasing concentrations up to Segment 48C for water
tracer and 48I for oil tracer. This could
indicate that the earlier segments are
more likely to partially flow into unpropped SRV and are at a much lower
relative concentration to the other tracers
during flowback and production.
Since oil tracer concentration is representative of the oil that is being contacted
by the tracer as it travels down hole with
the frac fluid, differing magnitudes of
concentration imply that the tracers were
contacting completely different pockets
of hydrocarbon throughout the stage. This
further supports the idea of the increased
fracture complexity with this style of
completion program.

American Oil and Gas Reporter - January 2020

Table of Contents for the Digital Edition of American Oil and Gas Reporter - January 2020