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Consequently, because of low formation permeability, pressure
in the formation was depleted only within a few feet of the well
after three months of production. In a long, narrow region of
pressure depletion, the poroelastic response was weaker, asymptotically approaching zero as the width of the region of
pressure depletion declined.
The V2 DFIT and the second V1 DFIT were performed after
this second period of H1 depletion. The two DFITs are
qualitatively different. The second V1 DFIT shows much more
rapid pressure depletion than in either the first V1 DFIT or the
V2 DFIT, quickly reaching subhydrostatic pressure of ~4,000
psi BHP (the test ended when the wellhead went on vacuum).
Even with much longer shut-ins, neither of the other two DFITs
approached subhydrostatic pressure.
The V2 DFIT's ISIP is slightly lower than the ISIP from the
first V1 DFIT, with pressure falling 500 psi lower by the end of
the test (and with a greater slope at the end). These observations
were matched by assuming that the V2 DFIT frac is close to the
V1 frac, but not directly connected. If there was a direct
connection, the V2 frac would drain into the V1 frac and behave
more similarly to the second V1 DFIT. In the match, the V2
DFIT frac is in proximity (offset 14 feet) to the V1 frac so that
it is impacted by pressure depletion and stress change, but does
not directly contact it.
Study Results
The modeling exercise in this study shows that planar fracture
modeling successfully explains all available observations. It
has been proposed that capillary pressure effects cause the effectively producing fracture length to be one or two orders of
magnitude less than the full-frac length and/or propped frac
length. However, in this dataset, it is clear that the effectively
draining fracture length equals the entire 1,000 feet separation
between the V1 and H1. This finding has implications for well
spacing.
If effectively draining fracture lengths are shorter, then
shorter well spacing is optimal. If effective fracture lengths are
longer, then the optimal well spacing is wider. This Bakken
study echoes findings from an earlier study performed in the
Utica Shale, which showed how inaccuracy in DFIT permeability
interpretation could lead to overestimated permeability, underestimated fracture length and a subsequent loss of economic
value associated with excessively close well spacing. In both
cases, the data suggests that effectively draining fracture halflengths are on the order of 500-1,000 feet.
Mechanisms of frac hit impacts on parent wells while
stimulating child wells are not thoroughly understood. Obviously, parent/child interactions have the potential to impact
production through pressure interference. Nevertheless, the
severity of frac hit damage in some formations suggests additional damage mechanisms may be at play, such as the
formation of chemical precipitation/emulsions or water leak
off that reduces relative hydrocarbon permeability around
fractures. In the Bakken dataset, however, the observed production uplift from the frac hit suggests that no other chemical
or special damage processes were at play. This is consistent

with other study results indicating Bakken parent wells are
more likely to see production uplifts than production losses
after frac hits.
The value of the history matching parameter maximum
proppant trapped per area was rather low, but importantly, it
was nonzero. Very likely, the amount of proppant trapping
relates to natural fracture density and other formation properties,
and so proppant trapping should vary by formation. It is an important parameter because the propped length decreases as
proppant trapping increases.
Propped length is very difficult to measure directly, but it
can be inferred from production interference tests and other
field observations, as shown in this study. Once propped length
is known, the amount of propping trapping in the model can be
calibrated to match the measured propped length.
❒
Editor's Note: For more information on the Bakken study,
see SPE 201566, a technical paper originally prepared for presentation at the Society of Petroleum Engineers 2020 Annual
Technical Conference & Exhibition. The preceding article was
adapted from the paper.

CRAIG CIPOLLA is a principal completions engineering
adviser at Hess Corp. He joined Hess in 2012 after serving
as chief engineering adviser for hydraulic fracture monitoring
and optimization at Schlumberger, vice president of stimulation technology at CARBO Ceramics and vice president
of engineering at Pinnacle Technologies. He is a former
Society of Petroleum Engineers distinguished lecturer on
hydraulic fracturing. Cipolla holds a B.S. in engineering
and a B.A. in chemistry from the University of Nevada-Las
Vegas, and an M.S. in petroleum engineering from the University of Houston.
GARRETT FOWLER is chief operating officer of ResFrac
Corp. in Palo Alto, Ca. Prior to joining ResFrac as vice
president of operations, Fowler was principal reservoir
engineer at Tachyus Corp., where he worked with national
oil companies, supermajors and independents on deploying
data science solutions. Before that, he was a reservoir
engineer for Occidental Petroleum specializing in waterflood
surveillance, piloting and optimization. Fowler holds a B.S.
in energy resources engineering and an M.S. in petroleum
engineering from Stanford University.
MARK MCCLURE is co-founder and chief executive
officer of ResFrac. Before founding ResFrac in 2015, McClure
was an assistant professor at the University of Texas at
Austin in the department of petroleum and geosystems engineering. He serves on a number of scientific and academic
boards and committees, and as an adjunct professor at
Stanford University. McClure holds a B.S. in chemical engineering, an M.S. in petroleum engineering and a Ph.D. in
energy resources engineering from Stanford University.
APRIL 2021 55



American Oil and Gas Reporter - April 2021

Table of Contents for the Digital Edition of American Oil and Gas Reporter - April 2021

Contents
American Oil and Gas Reporter - April 2021 - Intro
American Oil and Gas Reporter - April 2021 - Cover1
American Oil and Gas Reporter - April 2021 - Cover2
American Oil and Gas Reporter - April 2021 - Contents
American Oil and Gas Reporter - April 2021 - 4
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