American Oil and Gas Reporter - August 2015 - 65

0.745 psig/foot in the second Bone Spring
to 0.794 psig/foot in the third bench.
The first obstacle, however, was determining the ideal lateral length and
placement. As for lateral azimuth, playspecific geomechanical studies generally
suggest that the primary horizontal stress
runs relatively east-west at 8 degrees
(Figure 2). Taking into account the geologically driven exceptions and low topto-bottom permeabilities, the objective
was to create a platform where multiple
hydraulic fractures could be placed to
enable a comparative evaluation to determine the highest possible recovery.
Earlier work held that the lateral should
be drilled into a less-stressed north-south
azimuth, which would afford maximum
frac stages and perforation clusters, thereby
generating higher reservoir contact and
production. Fracture spacing continues
to evolve from a beginning value equal
to one cluster per three casing joints, or
approximately every 120 feet.
Another offshoot of the earlier phase
of the investigation was debunking longheld petrophysical contentions that classified the Bone Spring as a typical shale
with a brittle and relatively isotropic
stress regime, which would respond well
to a fracture network-like stimulation
treatment. It was that understanding that
prompted completion engineers to design
treatments using extremely thin waterbased frac fluids with small proppant.
Microseismic mapping has revealed
the Bone Springs fracture geometry to
be largely planar, with subsequent geomechanical studies showing the threshold
pressure to dilate any natural fractures to
be more than 10 percent above closure
gradient, making creating a natural fracture
network difficult at best. The previous
fracturing fluid and small-mesh proppant
selection was deemed ineffective for maximum recoveries.
Owing to the planar fracture geometry
and a frac height greater than 200 feet,
the evaluation settled on a low-viscosity
and nondamaging frac fluid formulated
with an extremely low-loading, guarbased cross-linked gel. Linear gel was
used in the early stages in tandem with
excess breakers and a nanosurfactant
package to enhance load recovery.
Complementing the redesigned fluid
stream was a wholesale analysis of the
proppant selection. Along with closure
pressures, another data point used to
select proppant was the gas-to-oil ratio
coupled with high initial flow rates, which
raised concerns about the presence of
multiphase flow compounded by nondarcy flow issues.
Logically, it can be maintained that
the producing pressure exerted a net load

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American Oil and Gas Reporter - August 2015

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