American Oil and Gas Reporter - August 2018 - 59

SpecialReport: Horizontal Wellbore Construction
FIGURE 2
Stimulation Treatment Plots Indicating Microproppant And Diversion (Left) and Desired BHP Trends (Right)
Treating pressure (psi)

A

BH proppant conc (lbm/gal)

A Slurry rate (bbl/min)
Calc'd BHP (psi)
C

B Slurry proppant conc (lbm.gal)
A

C

20,000
18,000

B

C

200

10

180

9

16,000

160

8

14,000

140

7

12,000

120

6

10,000

100

8,000

Microproppant on formation

Diverting material on formation

A

20,000

Treating pressure (psi)
BH proppant conc (lbm/gal)

A
C

B
A

Slurry rate (bbl/min)
Calc'd BHP (psi)

C

Slurry proppant conc (lbm.gal)

18,000
Calculated BHP build

B

C

200

10

180

9

160

8

14,000

140

7

12,000

120

6

5

10,000

100

5

80

4

8,000

80

4

6,000

60

3

6,000

60

3

4,000

40

2

4,000

40

2

2,000

20

1

2,000

20

1

0

0

0

0

0

0
7:00

7:30

8:00

8:30
Time

9:00

enhance and exploit any present secondary
fracture complexity.
It also was assumed that a significant
amount of hydrocarbon liquids production
was possible, so the stimulation design
needed to account for this scenario. A
hybrid slickwater and linear gel fluid
system was selected because the lowviscosity slickwater would be better able
to enter secondary fracture complexity,
and the linear gel (with a significantly
lower viscosity than a cross-linked fluid
system) would still be able to carry
higher proppant concentrations into the
hydraulic fractures.
Table 1 shows the general treatment
design parameters, consisting of the hybrid
fluid system as well as diversion and microproppant. Given the fracture gradient
and the well's 14,000-foot TVD, it was
assumed that the proppant pack would
encounter a significant amount of closure
stress. Therefore, higher crush-resistant,
curable resin-coated proppant was incorporated into the stimulation design to
help maintain NWB conductivity. Perforation cluster spacing, treatment rate,
water volumes and proppant amounts
were all based on trends in the SCOOP
and STACK plays.
Diversion And Microproppant
Diversion served several purposes in
the stimulation design. The first was to
help improve fluid distribution across all
perforation clusters for the given stimulation treatments along the horizontal lateral. However, without real-time distributed
acoustic sensing (DAS) and distributed
temperature sensing (DTS) fiber optic
measurements at the perforation clusters
being stimulated, it is difficult to assess
whether diversion actually is being
achieved and treatment fluid is being effectively distributed across individual
perforation clusters. This means that di-

9:30

10:00

16,000

1:00

1:30

2:00

2:30

3:00

3:30

4:00

4:30

Time

version only can be assessed in real time
through observed treating pressure responses, without an actual understanding
of changes in the fluid flow path.
Therefore, a novel diversion material
was used in part to help increase complexity, which then should increase bottom-hole pressure or the net pressure
slope during treatments. In other words,
the diversion material was used to mimic
the desired net-pressure trend for complexity generation. The ideal situation
would be to either maintain a neutral net
pressure or BHP slope, or drive the net
pressure/BHP to an increasing slope, with
the logic being that increasing net pressure
also can increase the likelihood of secondary fracture development.
The purpose of microproppant is to
enter and prop secondary fractures. These
micron-sized particulates are smaller than
100- and 200-mesh sand, and are designed
to enter in situ natural fractures and secondary microfractures generated during
stimulation to keep them propped open
during the production life of a well. Based
on available core data and petrophysical
studies, the Sycamore formation appeared
to have similar or greater fracture complexity than the Woodford formation in
the SCOOP area. Field trials were con-

ducted in the Woodford using microproppant to prop secondary fractures, showing
substantial production uplifts compared
with offset wells.
Figure 2 shows an example of a typical
treatment. Treatments were composed
of three individual proppant cycles separated by diversion, with microproppant
pumped during the initial pad stages
(left). The image at right shows that an
inclining BHP/net pressure slope commonly was observed throughout the individual treatments. NWB friction was
encountered often during initial pad
stages of the treatments, which could indicate pressure-dependent leakoff and
some degree of complexity. Microproppant appeared to impact this entry friction.
Leakoff also was observed post-stimulation, indicated by a 300- to 500-psi falloff
in post-instantaneous shut-in pressure
approximately five minutes after shut in,
which also could be an indication of
complexity.
Production Results
For the Sycamore well, cumulative
six-month production totaled 83,223 barrels
of condensate and 2.0 billion cubic feet
of gas. When normalized by lateral length,
the gas and condensate production equaled

TABLE 1
Sycamore Horizontal Well Completion Parameters
Parameter
Perforation cluster spacing (ft)
Perforation clusters per stage
Design treatment rate (bbl/min)
Water volume (gal/ft)
Proppant concentration (lbm/ft)
Treatment ﬂuid type
Proppant type

Value
60
4
80
1,800
2,000
Hybrid (slickwater, linear gel)
Premium white, resin-coated
AUGUST 2018 59
American Oil and Gas Reporter - August 2018

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