American Oil and Gas Reporter - April 2021 - 50

pages 47-55_Layout 1 4/8/2021 2:42 PM Page 50

SpecialReport: Frac Tech
ductivity to be 0.02-0.10 md-ft after closure during the DFIT.
Because conductivity is a function of effective normal stress,
conductivity was changing continuously over time as DFIT
shut-in pressure decreased. The overall match was accomplished
with a relatively high value of " aperture at contact " (0.096
inches) and low value of " 90% closure stress " (100 psi). The
90% closure stress is the effective stress at which 90% of the
aperture is lost.
These parameters suggest the hydraulic fracture is highly
conductive during injection, but that conductivity and aperture
drop sharply as pressure falls once the fracture walls come
into contact.
The simulated and actual BHPs in H1 show a good match
during MDD injection and the V1 frac job. During MDD
injection in H1, BHP abruptly leveled out at 6,000 psi. This occurred because of mechanically re-opened fractures at pressure
approaching the magnitude of the minimum principal stress.
The initial magnitude of Shmin in the layer is 7,250 psi, suggesting
a stress decrease of ±1,250 psi. This low stress decrease is
related to pore pressure diminishing from 6,000 to 1,000-2,000
psi in the depleted region around H1.
The fracture length from the simulated V1 frac job is ±1,000
feet and mostly symmetrical, consistent with observed microseismic data. The instantaneous shut-in pressure (ISIP) from
the simulated V1 frac was similar to the observed V1 frac ISIP
and first V1 DFIT ISIP.

Production Uplift
Figure 3 shows the actual-versus-simulated H1 production
uplift (left panel) and the distribution of fracture conductivity
(right panel) after fracturing the V1. Figure 4 shows the
distribution of pressure, poroelastic stress change, fracture conductivity and saturation at the end of the H1 production period
after the V1 frac and prior to the V2 DFIT.
Operational experience shows that similar wells that have
been shut in and/or experienced an MDD injection have not
demonstrated similar production uplifts. This strongly suggests
that the production uplift was caused by fracture connection
to the V1. History matching the observed production uplift
requires a continuous and fairly conductive pathway for flow
from the V1 to the H1. Matching to the first V1 DFIT
requires unpropped conductivity to be low. Therefore, the
match to the production uplift requires forming a continuously
propped pathway along the entire length of the fracture
between V1 and H1.
The history match is constrained by some very specific
features of the dataset. First, because of the relatively small
mass of proppant used in the V1 treatment, the proppant concentration (pounds/square foot) along the fracture cannot be too
high or the propped length will be insufficient. Second, the
second V1 DFIT had a much more rapid pressure falloff than
the first V1 DFIT, suggesting fracture conductivity at the
wellbore was enhanced significantly by proppant injection.

FIGURE 3
Actual and Simulated H1 Production Uplift (Left) and
Fracture Conductivity Distribution (Right) after the V1 Frac Job

Oil prod rate, Well_ H1
Oil prod rate, Well_ H1

100

Oil Prod Rate (STB/day oil)

0
9

9.5

10.5

Simulation time (years)

11.5

Fracture conductivity (md-ft)
0.0002696

11 y, 146 d, 4 h, 26 m, 12 s

50 THE AMERICAN OIL & GAS REPORTER

Stretch: Horiz = 5, Direction = 90 deg, Vert = 1

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American Oil and Gas Reporter - April 2021

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