American Oil and Gas Reporter - January 2023 - 73

refrac itself and losses in the infill well
can be significant. These phenomena are
not restricted to the Eagle Ford and are
not formation-specific; they are the result
of reduced closure stress at lower reservoir
pressures, and occur 100% of the time in
all basins.
Candidate Selection
To estimate the expected production
uplift, the total number of refrac candidates
first needs to be established. With cluster
spacing widely recognized as the most
important variable in recovery factors,
the workflow begins by reviewing historical
cluster spacing versus time.
Figure 1 shows a comparison of recovery
factor versus cluster spacing from
comparisons between EUR and oil in
place (OIP) using a model developed
by researchers at the University of Texas
at Austin's University Lands (UL) group
(see SPE 199721 " Effective Cluster
Spacing Plays the Vital Role in Unconventional
Reservoir Development: Permian
Basin Case Studies, " by Hongjie
Xiong, presented at the 2020 Hydraulic
Fracturing Technology Conference &
Exhibition). The blue dots are the results
of UL's simulation model and the orange
dots are estimated from a comparison
of OIP with EURs.
The UL model assumed 100% cluster
efficiency. However, prior to the advent
of XLE in 2018, very few wells had high
cluster efficiencies. Several studies have
suggested that poorly diverted completions
have ±60% cluster efficiencies. Figure 2
shows the results when the 100% cluster
efficiency model and the 60% cluster efficiency
model are applied to the historical
cluster spacings for 802 Eagle Ford wells
with cluster spacing data. The expected
total recovery factor is in the 4% range
until after the second half of 2016. With
a ±14% expected total recovery factor,
this suggests that the total recovery factor
can be increased with refracs by at least
a factor of three for wells completed
prior to the second half of 2016.
A review of historical cluster spacings
in the other areas reveals a similar trend.
In the Permian Basin, a major operator
did not drop below 60-foot cluster spacing
until July 2016, translating to a range of
expected recovery factors from 2.7% with
60% cluster efficiency to 5% for 100%
cluster efficiency. The operator completed
its wells during that period with 40, 0.42inch
perforations per stage, equating to a
range of pre-erosion perforation pressure
drops from 423 psi for 100% efficiency
to 1,123 psi for 60% efficiency. Both are
well below the 2,500-3,000 psi needed
to obtain 100% efficiency.
Top Refrac Priority
Using the second half of 2016 as a
cutoff for a greater than three-to-one
uplift in total recovery from refracs, there
are 36,302 wells in the five major organic
shale plays based on wide cluster spacings.
While not all of these candidates will
have sufficient oil and gas in place for
economic refracs, that uncertainty can
be derisked with petrophysics prior to
proposing a refrac. Preliminary screening
of a large number of Eagle Ford and
Haynesville wells indicates that at least
70% of the refrac candidates based on
wide cluster spacing should be economic
(defined by a 20% or higher internal rate
of return).
The top priority for refracs should be
primary wells with offset infill wells
waiting on completion. Refracs compete
with new wells for capital, and if operators
are not willing to part with 40% of
a new infill well's EUR, a refrac is
mandatory. This should guarantee that a
frac crew will be available for the refrac
since the infill wells on the same pad
most likely will be fractured. This is not
the case for opportunity refracs with no
primary-infill issues where a limited
number of spot crews are available. This
can delay the execution of the standalone
refracs, but also accelerate the execution
of the primary wells on pads awaiting
development.
The total number of upcoming infill
wells is known from the inventory of
drilled but uncompleted wells, wells being
drilled and permits. As of early December,
there were 7,585 total DUCs, new drills
and permits for the Eagle Ford, Haynesville,
Permian, Marcellus and Woodford.
Of these, 25% (1,896 wells) were
FIGURE 2
Eagle Ford Recovery Factor History
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
assumed to have primary-infill asymmetry
issues with potential 40% losses in EURs
and IPs per infill without primary well
refracs. Two major organic shale operators
indicate that 50%-80% of their infill wells
have these issues, meaning the 25% estimate
should be conservative.
Production Forecast
To forecast production from refracs,
it is assumed that 10% of the total pool
of 36,302 wide-cluster spacing wells in
the five plays would be refractured. This
would involve 3,630 total refracs with
1,896 infill protection refracs and 1,734
standalone refracs with no infill protection
uplift. A total of 34 Eagle Ford and 45
Haynesville mechanical isolation refracs
were evaluated from single-well lease
production out of 197 known refracs to
date in the Eagle Ford and 170 in the
Haynesville.
The post-refrac EURs from refracturing
were allocated on a monthly basis over
30 years using type curves for the various
areas. For the daily rate forecast, the first
month's production required to generate
the EUR with the type decline was used
rather than the actual first month's production,
since operators often utilize
choke management to manage drawdowns
because of the high percentage of unpropped
area in the stimulated reservoir
volume.
A comparison was made between the
last full month's production prior to refrac
and the normalized first month's post-refrac
production. The average reduction
of the post-refrac first month's production
was 6% to subtract the last month's production
prior to the refrac since that production
will be taken off line once a
refrac is completed. This multiplier then
can be used for the Permian, Marcellus
< H2 2016 >3:1 Total RF Uplift
RF 100% CE
RF 60% CE
JANUARY 2023 73
2010 H1
2010 H2
2011 H1
2011 H2
2012 H1
2012 H2
2013 H1
2013 H2
2014 H1
2014 H2
2015 H1
2015 H2
2016 H1
2016 H2
2017 H1
2017 H2
2018 H1
2018 H2
2020 H1
American Oil and Gas Reporter - January 2023

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