American Oil and Gas Reporter - April 2019 - 56

SpecialReport: Drilling Technology
modulus, Poisson's ratio, and bedding
(i.e., VTI anisotropy). As seen in the lefthand image in Figure 3, these two facies
models show remarkable resemblance to
each another. Comparing these models,
the interdisciplinary team was encouraged
to see similar results derived from two
different measurements.
However, the image on the right highlights the difference in resolution between
the two models. On this expanded scale,
it is possible to compare the two facies
models over a 40-foot interval of the
Lower Spraberry. In addition to the mechanical facies, Track 6 also displays the
PE curve. Note the PE and lithofacies
suggest some vertical heterogeneity, but
the higher-resolution mechanical facies
resolve these laminations into many more
facies. The combination of multiple measurements of varying degrees of resolution
can improve an operator's decisions about
horizontal well development.
The other advantage of calibrating
mechanical facies in a pilot well is its
applications in future horizontal wells.
Because drill bit geomechanical data are
much easier and less costly to collect
than wireline logs or conventional core
in horizontal wells, operators can enhance
their geomechanical understanding by
relating each new long horizontal well to
data acquired in the pilot well.

In each well, the engineered design
required fewer overall treatment stages
to effectively stimulate the lateral length
than a geometric design would have required. Despite some minor differences
in perforation cluster spacing and stage
length, the three wells shared a similar
overall completion design. All three designs used the same number of perforation
clusters per stage, treatment fluid, proppant size, proppant concentration and
treatment rate.
Using step-down rate tests, engineers
validated that all three wells' perforation
and stage designs were equally effective.
Each well had at least 42 stages, providing
a statistically significant number of stepdown tests to analyze. The average perforation efficiencies (percentage of open
perfs) for Wells A, B and C ranged
between 62 and 67 percent. Similarly,
the average calculated tortuosity values
differed by less than 15 percent.
Because the step-down rate tests occurred at the start of each stage before
the proppant slurry was pumped, these
results suggested that all three completions
were equally well designed. However,
despite their geographic proximity and
their similar completions, the wells' production responses were notably different.
For completions, the petromechanical

Engineered Completions

FIGURE 4

56 THE AMERICAN OIL & GAS REPORTER

9,000

10,000

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19,000

9,000

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Well C

Well B

Well A

Well-to-Well Comparison of Mechanical Quality

In another Permian application, Hunt
Oil Company drilled three neighboring
horizontal wells (A, B and C) in the
same target landing zone. The wells were
spaced ~660 feet from one another and
had ~10,000-foot parallel laterals. Drill
bit geomechanical information was acquired along each well's path while drilling
and used to design each completion. This
process involved grouping intervals of
similar mechanical rock properties into
individual frac stages. Compared with
geometric completion designs (i.e., designs
that geometrically divide the well into
treatment stages), "engineered" designs
can increase production while reducing
completion costs.

workflow leverages petrophysical resources, applies them to mechanical data
and provides a predictive framework for
mechanical behavior (in this case, for
hydraulic fracturing). The ability to effectively fracture a rock volume depends
on its mechanical quality. To approximate
mechanical quality, the workflow uses
mineralogic brittleness and unconfined
compressive strength (UCS).
Designed for use in horizontal wells
without extensive wireline log data, the
petromechanical workflow estimates basic
mineralogy from the MWD gamma ray
and drill bit geomechanics-derived bedding
(VTI anisotropy). Clay volume can be
calculated independently from gamma
ray and bedding. The difference between
the two calculations provides a relative
estimate of kerogen. The model also estimates carbonate and quartz, feldspar
and mica, but these minerals are not used
to derive mechanical quality.
From the basic mineralogical model,
the workflow calculates brittleness, which
is a linear function of bedding-derived
clay volume. The workflow calculates
UCS from the drill bit geomechanicsderived Young's modulus, which is calibrated to horizontal, static values and
converted to UCS through a series of
empirical relationships.

Track 1: Measured Depth (ft)
Track 2: UCS
Brittleness
Track 3: Clay Volume
Quartz

High Mechanical Quality
Calcite
Kerogen

Low Mechanical Quality

American Oil and Gas Reporter - April 2019

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