American Oil and Gas Reporter - January 2012 - 80

Oil & Gas Shales
fracture initiation and propagation (hence
stimulated rock volume and coverage in
the lateral section of the formation), since
fractures in more brittle areas tend to initiate and propagate easily compared with
those in ductile sections.
The data retrieved from the PNL log
were then calibrated with the open-hole
log data from the vertical pilot hole.
Figure 2B shows that the CHI-modeled
pseudo open-hole data correlate well with
that of the vertical pilot shown in Figure
2A. The shale log model was used to
calculate the rock brittleness factor to
grade the shale reservoir into potential
completion intervals. Figure 3, displays
the CHI model of PNL shale log analysis
in the lateral well bore. The more ductile
rock is indicated by a green color spectrum

in the brittleness factor track, while the
more brittle rock is colored in red.
Completion Design
The lateral length of the Briscoe Nunley
well is 4,000 feet (16,643 feet measured
depth and 12,513 feet total vertical depth).
The well was completed with 250-foot
spacing between plugs, four perforation
clusters (three feet with six shots per
foot), and 50 feet between perforation
clusters. The lateral section was divided
evenly up to a total of 16 stages.
The vertical pilot hole was drilled,
logged and evaluated to determine where
to drill the lateral. The well bore configuration used 4.5-inch, 15.1-pound/foot
casing. The job was designed with a
series of three 100-mesh sweeps using

FIGURE 3
CHI Model of PNL Shale Log Analysis in Lateral

FIGURE 4
Radioactive Tracer Log (Briscoe Nunley GU No. 1)

80 THE AMERICAN OIL & GAS REPORTER

10-pound linear gel followed by linear
pad and main proppant stages ranging
from 0.25 to 2.0 pounds. The plug-andperf completion method was used to
isolate the stages.
Each stage consisted of 350,000 pounds
of total proppant (50,000 pounds of 100mesh and 300,000 pounds of 40/70-mesh
resin-coated sand) staged from 0.5 to 3.0
pounds/gallon with 12,800 barrels of a
"hybrid" system with 3 percent potassium
chloride (KCl) treated water. The average
surface treating pressure was 12,000 psi
at 80 bbl/minute.
The pump schedule was designed to
accommodate the complexity of the frac
system in the near-well-bore region. The
hybrid design schedule included 30,000
gallons of prepad, which created fracture
geometry ahead of three sets of 100-mesh
sweeps pumped with 5.0-centipoise linear
gel fluid, a 15,000-gallon main frac linear
pad, and the 40/70 resin-coated proppant.
Proppant was staged from 0.5 to 2.0
pounds/gallon, and at the 1.25 pounds/gallon stage, the fluid was cross-linked with
a borate cross-linker and cross-linked gel
was used to transport the heavier proppant-laden fluids and create frac width
for the tail end of the treatment.
Frac design was finalized on location,
the stimulation treatment was performed,
and both chemical and radioactive tracers
were run as part of the post-frac diagnostics
to evaluate the treatment. During each
stage, a different chemical tracer was
added to the proppant and frac fluid.
Proppant was traced with alternating isotopes, and fluid was traced with a fluid
tracer. Water samples were collected
during flow back, and production logs
were run in the lateral about six weeks
after the well was completed.
The radioactive tracer log (Figure 4)
shows that all 16 fracs had communication
with the formation. It also appears that
the majority, if not all, of the perforation
clusters had communication between the
well bore and the reservoir. However,
the log also reveals a large interval of
unpropped section near the well bore.
The section of the lateral without tracer
signature (unpropped) was counted, and
only 32 percent of the lateral section was
propped based on the tracer signature.
Also, the tracer signatures near the well
bore were not distinct, which may be a
result of low proppant concentration in
this area.
American Oil and Gas Reporter - January 2012

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