American Oil and Gas Reporter - August 2019 - 78

SpecialReport: Horizontal Wellbore Architecture
FIGURE 2
Chemical Tracer Results from Wells H12 (TF2) and H6 (TF)
H12 Tracer

H6 Tracer
H1
Oil: Stage 1
shows up at
H5 and H12

H12, H5, H6, H7, H8, H9

H1

Water: Stage 19
shows up in
H12, H5, H7, H8,
H9, H1 and H2

H12, H5, H6, H7, H8, H9
Water: Stage 89 shows the
same
H2, H12, H7, H5

H2

Oil: Stage 15
(no anttrack)
oil tracer
shows in
H5, H6, H7, H9

2013

2011

2015

Water: No
water tracers
shows up in
other wells
from stage 15

Oil: Stage 14
and 15 show
up at H5 and
H12

H2
Water: Stage
14, 15 show
up in H12, H5,
H7, H1 and
H2

Oil: Stage 22
shows up at
H12, H5, H7
H9-Highest
communication

Water: Stage
22, 27, 28
shows up at
H12, H5,
H9, H7, H2

Oil: Stage
27, 28 show
up at H12 and
H5

Water: Stage
27 and 28
show up at the
same wells H1
and H2
H3

H4

2,600 ft

Water: Stage 31, 35 show up
at H1, H2, H3,
and H4

Traced Stages:
1, 8, 9, 15, 19,
20, 27, 31, 35

reservoir simulation history matching.
The workflow consisted of:
· Modeling parent well hydraulic
fractures and history matching production;
· Performing geomechanical modeling to determine the effects of parent
well depletion on the 3-D stress state for
hydraulic fracture modeling of infill wells;
and
· Production history matching of the
entire pad.
Table 1 provides a summary of all six
well completions and the data acquired
for the DSU. Except for the H6 microseismic monitoring well, all wells were
completed with 35-stage open-hole, ball
drop-activated sliding sleeve systems (H6
was completed with cemented coiled tubing-activated sleeves with a larger internal
diameter to allow placement of the microseismic monitoring array). Each stage
pumped 70,000 pounds of sand and 1,100
barrels of fluid. Fluids consisted of a
hybrid system using slickwater in the
pad and early proppant stages (40/70
sand) and cross-linked gel for the rest of
78 THE AMERICAN OIL & GAS REPORTER

Water: Stage
38 and 39
show up in
H12, H5, H7, H1
and H2
Oil T: Stage
38, 39 and
44, 45 shows
in H12, H5,
H7

Traced Stages:
All stages, 1, 14,
15, 22, 27, 28,
38, 39, 44, 45

Water: Stage
44 and 45
shows up in
H12, H5, H7, H8,
H9, H1 and H2

the treatment (20/40 sand).
Diagnostic fracture injection tests
(DFITs) were performed in the toe of
each lateral on wells H5, H7, H8, H9
and H12 to provide stress and reservoir
pressure measurements. A pressure gauge
was installed in parent well H1 to record
bottom-hole pressure during the MDD
operations and the H5, H6, H7, and H12
completions. MDD was performed in H1
by injecting freshwater into the wellbore
at a rate of five-eight bbl/minute for eight
hours. The objective of MDD was to
evaluate H1's depletion. During MDD
operations, the wellbore and hydraulic
fractures were repressurized and the corresponding microseismic events were
recorded and analyzed.
Following MDD operations, fracture
operations were performed in the following
sequence: H5 (MB), H12 (TF2), H8 (TF),
H7 (MB), H9 (MB) and H6 (TF). MSM
data was gathered for wells H5, H7, H8
and H12. Iridium RA tracer was added
to the proppant in stages 17-31 in the
H12 well and stages 25-35 in the H7. In
addition, 31 unique oil tracers and 31

unique water tracers were strategically
placed throughout the fracture stages of
the H5, H6, H9 and H12 wells.
After completing stimulation operations
on all wells, the H5, H6 and H9 were
logged for the presence of RA tracer.
There was no evidence of iridium tracer
in the H6 or H9 wells, but it was found
in the H5 MB well, indicating that proppant traveled 190 feet from the TF2 in
the H12 well into the overlying MB in
the H5. Because of the limited depth of
investigation of spectral gamma-ray logs,
it is important to note that a lack of
detected tracer in a specific well does
not confirm a lack of fluid or proppant
communication, making it important to
integrate RA tracer data with chemical
tracer and microseismic monitoring data.
The oil and water chemical tracer
stages were selected based on image logs
and mud gas data with the objective of
correlating natural fractures with actual
fluid movement. In addition, chemical
tracer was used in Well H6 to confirm
zonal contribution within the wellbore.
Fluid samples were collected during flowback and production phases and analyzed
for tracer concentration. Tracer samples
were also taken from older offset wells.
Analysis of the collected wellbore
fluid samples confirmed significant stimulation fluid movement between wells in
the DSU. Figure 2 shows details of the
communication captured from chemical
tracer samples. Oil tracer movement of
2,800 feet was detected between wells
H9 and H2. Furthermore, tracers from
H9 were found in all wells of the batch.
Water tracer from the H12 (TF2) well
was detected as far as 2,600 feet away in
the existing H4 (MB) well, supporting
the RA tracer log results indicating upward
fracture growth from the TF2 into the
MB. The extended distance of tracer
communication from the newly drilled
batch of wells to existing wells with three
years of production can be attributed to
fracture growth toward depleted areas.
Microcosmic And MDD
As part of the H1 MDD operation, a
geophone array was positioned in the H6
cemented wellbore and fresh water was
pumped into the H1 well at a rate of 5-8
bpm for 8 hours.
American Oil and Gas Reporter - August 2019

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