American Oil and Gas Reporter - January 2019 - 56

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Unconventional Resource Science
The LK is a "stand up" 640-acre
(one square-mile) DSU with relatively
short 4,500- to 5,000-foot laterals. The
three infill wells were drilled four years
after the LK-H1, the legacy well drilled
to hold the lease by production. Like
the H1, the LK-H2 infill well targeted
the 40-foot-thick MB. The H3 and H4
infill wells were drilled 50 feet deeper
to the TF, which is separated from the
overlying MB by the Lower Bakken
Shale formation.
Microseismic depletion delineation
(MDD) was performed on the H1 before
the offset wells were completed to estimate
the well's drainage pattern. The MDD
consisted of a low-rate injection of 5,000
barrels of water while monitoring with
microseismic arrays in the H3 infill well.
Bottom-hole pressures (BHPs) in the H1
were monitored during both MDD operations and inset well frac treatments.
Fracture geometries were modeled and
calibrated using microseismic for the H2
and H4 wells, with the microseismic
array in the H3. The MDD results calibrated the H1 reservoir simulation model,
and geomechanical modeling was used
to predict depletion-related stress changes.
The microseismic data showed fracture

height covering both the MB and TF
formations and very asymmetric fracture
growth toward the area depleted by H1.
Guided by the microseismic data and
numerous frac hits on the H1 during
infill well completions, the geomechanical
modeling results were combined with
advanced hydraulic fracture modeling
to evaluate depletion effects on infill
fracture geometry.
The offset well fracture geometries
were gridded discretely in the reservoir
simulation model, and well performance
was characterized with history matching.
The reservoir simulation model accurately
predicted infill well production behavior
and matched the threefold increase in
H1 production caused by the frac hits.
The calibrated hydraulic fracture and
reservoir simulation models have become
essential components of subsequent Hess
studies to optimize Bakken/Three Forks
development.
LK Drilling Spacing Unit
The H1 and H2 laterals are landed in
the Middle Bakken at a depth of 11,090
feet. The H3 and H4 are landed in the
Three Forks at 11,140 feet. The MB is
represented by five layers in the geomodel,

FIGURE 1
Microseismic Data Recorded During MDD Pump-In and H2 (Left)
And H4 (Right) Well Treatments
5,000

5,000

4,000

3,000

North (feet)

4,000

2,000

3,000

2,000

1,000

-2,000

-1,000

Virgin Reservoir Pressure

Downhole HK1 Pressure psi

1,000

MDD

-2,000

2,000
Closure Pressure
H2 Fracs

56 THE AMERICAN OIL & GAS REPORTER

-1,000

0
East (feet)

1,000

H4Fracs
Time

2,000

while the productive portion of the TF is
represented by 12 layers.
Water saturation in the TF increases
toward the bottom of the interval. The
Upper and Lower Bakken shales are represented by a single layer in the geomodel.
Reservoir properties were distributed geostatistically in each layer. This area of
the Bakken is overpressured, with a reservoir pressure gradient of approximately
0.78 psi per foot (»8,500 psi).
The H1 had been hydraulically fractured using the open-hole plug-and-perf
technique with swell packers for zonal
isolation. It was completed with 14 stages
and four perforation clusters per stage.
The clusters were designed with 60degree phasing and six shots per foot.
The H1 was treated with a slickwater
pad and 40/70-mesh sand followed by a
20-pound cross-linked gel and 20/40mesh ceramic sand ramp with a maximum
proppant concentration of six pounds
per gallon at an injection rate of 35-45
barrels a minute.
The H2, H3 and H4 laterals were cemented in place and each well was completed with 20 plug-and-perf stages with
three clusters per stage, again with 60degree phasing and six shots/foot. Frac
treatments consisted of a 25-pound crosslinked gel and 40/70- and 20/40-mesh
white sand at a maximum proppant concentration of 3.5 pounds/gallon. The infill
well treatments were pumped at an average
rate of 27 bbl/minute and a maximum
rate of 30 bbl/minute.
Data collected from the H1 included
fluid level, MDD before fracturing the
infill wells, and BHP from the downhole
gauge to record pressures during MDD
operations as well as H2, H3 and H4
completion operations. Microseismic mapping was used to measure hydraulic fracture geometry during the H2 and H4
completions. Microseismic monitoring
was performed using geophones positioned
in the H3 lateral (landed in the TF, H3 is
750 feet from the H2 MB lateral and
1,600 feet from the H4 TF lateral).
Cement bond logs were used to evaluate cement quality in all three infill
wells. A production logging tool and radioactive tracers were deployed in the

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