American Oil and Gas Reporter - September 2019 - 56

SpecialReport: Horizontal Wellbore Architecture

BHP (gauge)

H12

2,000

Bottom Hole Pressure (psi)
4,000
6,000
8,000

FIGURE 4
BHP and Cumulative Oil (First 30 days of Production)

06/01/2015

06/08/2015

06/15/2015

06/22/2015

06/29/2015

Date

~300 bpd
~500 bpd

~700 bpd
~700 bpd

~1,000 bpd
H12

~1,500 bpd

~1,500 bpd
H5

~300 bpd
H6

~800 bpd

~1,500 bpd

Oil Production Cumulative (STB)
10,000
20,000

Cumulative Oil (bbls)

06/01/2015

06/08/2015

06/15/2015

06/22/2015

06/29/2015

Date

wells, hydraulic fractures from MB wells
easily can overlap two-three neighboring
wells. Figure 3 shows the microseismic
and fracture model for the H7 MB well,
with hydraulic fractures extending across
the entire DSU from the H12 to H9 wells.
Production And BHP
The next step in the evaluation was to
combine the fracture modeling results
with production for the first 90 days and
BHP data to characterize the vertical and
lateral connectivity between wells. During
this period, all wells were flowing naturally
with no artificial lift. The H12 TF2 well
was the first well put on production and
produced about 1,000 barrels of oil a day
with a 60-70 percent water cut. The H5
and H7 MB wells were the second and
third wells on line, producing about 1,500
bbl/d with a 40-50 percent water cut.
The H6 TF was the fourth well to start
production, with initial oil production of
about 800 bbl/d with a 55 percent water
cut. The fifth producer was the H9 MB
well, which initially produced about 1,500
bbl/d with a 20-30 percent water cut.
The H8 was the last well to come on
stream at rates similar to the H6.
The H1 was returned to production
shortly after the H8. The H6 TF1 and
H12 TF2 wells stopped producing around
day 45, which was reflected in the increase
in and equalization of BHP. All wells
were shut in around day 90 to install artificial lift and exhibited very similar
56 THE AMERICAN OIL & GAS REPORTER

BHP trends. The BHP data suggests communication between all six wells in the
DSU, plus the H1 parent well. The BHPs
for the H5 and H7 MB wells virtually
overlay one another during the later
portion of the production period and the
shut-in period. The BHP in H9 tracks the
H5 and H7 during the final shut-in period,
and all wells trend toward the same BHP
of about 4,000 psi when shut in.
Figure 4 provides a detailed review
of the BHP data, illustrating communication between wells throughout the
pad. When the first well (H12) started
producing, the BHP in all wells began
to decline. This effect was repeated
across the DSU as each subsequent well
commenced production. The figure also
shows interwell interference by comparing oil production from wells already
on line both before and after the six
new wells started production. When H5
started producing, the oil rate from the
H12 direct offset decreased by 50 percent.
The same was true for direct offsets H5
and H7 when H6 began producing. The
effect of H7's production on H5's production was more subtle, but still amounted to a 20 percent drop.
History Matching
The BHP and production "sharing"
provide compelling evidence of communication between wells and formations
within the DSU. The qualitative interpretation of the BHP and production data

is consistent with the microseismic and
tracer data showing significant overlap
of hydraulic fractures from well to well
and hydraulic fracture connectivity from
MB to TF2. The next step was to better
characterize hydraulic fracture properties
and calibrate hydraulic fracture and reservoir simulation models through history
matching, which was an ambitious and
complex task involving the six new DSU
wells plus the H1 parent well.
The objective of the history match
was to characterize the "bulk" lateral
and vertical connectivity of the wells,
and better understand the conductivity
of propped and unpropped hydraulic
fractures. Together, the seven wells included 247 fracture treatment stages in
the MB, TF1 and TF2 horizons, and the
fracture geometries and proppant distribution for all wells were used for reservoir
simulation history matching of DSU production and BHP. Six months of production data was used for history matching, but BHP measurements were only
available for the first 90 days (before artificial lift was installed).
A six-layer model was used for the
reservoir simulation history match, requiring 1.7 million grid cells to adequately
represent the complex hydraulic fractures.
Fracture modeling showed the significant
overlap and connectivity of the hydraulic
fractures between wells.
In history matching BHP for H12,
H5, H7 and H6, there was good agreement
between the simulation model and actual
BHP, but a significant baffle or flow restriction in the fractures connecting the
MB and TF formations was required to
match the BHP behavior and connectivity
between the MB (H5 and H7) and TF
(H6 and H12) wells. Although there is
considerable uncertainty in the location
and properties of this flow restriction, it
is hypothesized that the relatively thick
(60-foot) Lower Bakken section mutes
the connectivity between the two formations, even though hydraulic fractures
clearly extend from the TF2 upward into
the MB.
Significant Insights
The integration of geology, microseismic, hydraulic fracture modeling, geomechanics, and reservoir simulation re-

American Oil and Gas Reporter - September 2019

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