American Oil and Gas Reporter - July 2024 - 60

SpecialReport: Modern Chemistry
Limiting Water Cuts
Today, Ezell says one of the industry's
biggest challenges is high water cuts in
development wells. " Hydraulic fracturing
pumps a massive amount of water into
the formation. While some of that water
returns to the surface, much of it gets absorbed
by the rocks. This water imbibition
potentially alters the reservoir's physicochemical
properties, restricting hydrocarbons'
ability to flow in low permeability
pore spaces, " he explains.
" Early in a field's life, larger space
between wells helps minimize the impact
that water imbibition from previous completions
has on production, " Ezell acknowledges.
" It becomes more significant
as operators decrease spacing and reservoir
pressures decline. "
Simulfracs can minimize interactions
between wells because all the wells benefit
from untouched rock and similar reservoir
pressures, but Ezell points out that simulfracs
require a substantial capital investment.
" For operators who drill wells one by one
and use the revenue from the early wells
to fund the later ones, simulfracs are not
an option, " he says. " To help these companies,
we potentially need to use a different
completion fluids package in a downspaced
or child well than we would in the
parent. For example, the package may
have surfactants that focus on modifying
surface tension and account for the change
in contact angle caused by wettability fluctuations
resulting from water imbibition. "
The ideal fluid will vary from application
to application, Ezell notes. Although
the industry will likely never have a
perfect answer to water imbibition, he
says it is getting closer thanks in part to
tools for analyzing past results and testing
new ideas.
Applying Experience
Ezell mentions that Flotek has completed
more than 20,000 wells in North
America. " Our chemistry has shown time
and again to improve the uplift in the
first 25-plus months, which is helping
operators improve the ROI in every well, "
he reports.
To translate that experience into relevant
recommendations, Ezell says the company
has used artificial intelligence to group
wells based on the:
* Completion fluid;
* In-situ water;
* Hydrocarbon characteristics, and
* Reservoir properties (e.g., the target
zone, the percentage of breakup of the
clay, and temperatures and pressures).
These groupings let Flotek base completion
fluids for new wells on strongperforming
analogs, he explains.
" We can look at everything from friction
reducers to shale, scale and corrosion
inhibitors to find combinations that should
minimize formation damage and ultimately
enhance the well's performance, " Ezell
says. " The AI tools' recommendations
are not the final word, but they give us a
very specific target range in which to design
laboratory experiments. "
Like their predecessors, Ezell says today's
experiments try to understand flow
through the highly porous primary fractures
that drive wells' initial performance.
However, they concentrate on understanding
fluid, hydrocarbon and water interactions
in the much smaller pockets of
hydrocarbons around the main fracture.
Ezell says these pockets account for most
of a well's production past the first month.
" The microfluidics tests involve looking
at chips at a high magnification to check
for emulsion blockages or other issues
that can restrict connectivity, " he describes.
" They also study how the completion
fluid will interact with rocks' heterogeneity
in surface shape and chemical make-up,
as these interactions can impact hydrocarbons'
ability to flow effectively. The
goal is to release as many hydrocarbons
as possible from the smaller spaces around
a fracture. "
Ezell contrasts microfluidics with formation
response tests. " With a traditional
formation response test, we could spend
anywhere from three-six months looking
at various options for the completion
fluid, " he says. " Today, by getting as
much data as we can about the well and
running it through our AI adviser, then
performing microfluidics and various
compatibility tests, we can consolidate
that into a few weeks. "
Ezell points out that the microfluidics
tests take place at reservoir pressures
and temperatures rather than ambient
conditions, which improves the correlation
between test results and actual performance.
Because the tests are done at
a small scale, he adds, it's possible to
conduct several simultaneously and get
results quickly.
" Microfluidics lets us do far less labBy
providing constant feedback
on field gas quality,
this analyzer is helping a
dual-fuel hydraulic fracturing
fleet minimize fuel costs,
Flotek Industries reports.
Eventually, similar analyzers
may be used to monitor
wells' production streams
for warning signs of paraffin
or other issues that can be
resolved with the right
chemical treatment.
60 THE AMERICAN OIL & GAS REPORTER
oratory work but get much better correlation
in results, " he summarizes. " We
can run samples in three days that used
to take three months, which accelerates
our ability to test changes and ultimately
leads to stronger completion practices. "
Post-Completion Data
Over time, Ezell predicts that completion
optimization efforts will benefit
from more detailed and frequent feedback
after the well enters production. He says
getting that data will be possible with
American Oil and Gas Reporter - July 2024

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