American Oil and Gas Reporter - March 2020 - 46

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SpecialReport: Unconventional Resource Science
It can take one-five days depending on
the temperature, and once it's done, there's
no risk the diverter will solidify as the
well cools during clean-out.
To test the diverter's strength, Soarus
worked with Premier Oilfield Laboratories.
"Premier told us that even after they
bridge the slots on its test equipment,
most diverters allow water to drip through.
Ours was the first that let nothing pass,"
Psihogios recalls.
In the field, the bridge's strength has
a side benefit. "As the barrier forms, surface pressure increases more sharply than
it does with most diverters, so the crew
members know the diverter is working.
They don't have to wonder or wait for a
gradual signal before they go to the next
step," Psihogios details.
This pressure spike is easy to spot
even when the operator is sending the diverter down with proppant, Psihogios assures. "Our material is unique in that it
binds to the sand and helps it move to
the fracture. This means operators can
pump at 90-100 barrels a minute, and
still get diversion pressure," she says.
Because BVOH softens in water, it is
not as likely as hard diverters to damage
equipment, Psihogios mentions, noting
this eliminates the need to use dedicated
diverter pumps.
Since its first field trial in June 2018,
the BVOH-based diverter has been deployed in 40 Permian Basin wells, Psihogios reports. "We plan to try using the
80-degree version to control lost circulation
during drill-outs and already have used
the technology in three acid fracs," she
comments.

"We also are applying other specialty
BVOHs to the oil field," Psihogios says.
"For example, to seal water-prone zones,
we are experimenting with a grade that
can absorb 200-300 grams of water for
every gram sent down hole. Our current
product is temporary, but we are developing a permanent version for plugging
thief zones during drilling or wateredout formations during production."
Eliminating Plugs
Operators can reduce or eliminate the
need for bridge plugs significantly during
completions by using pods to plug perforations, says Jenna Robertson, SlicFrac
product line manager for Thru Tubing
Solutions. She says the company has
helped operators perform more than 50
plugless completions, with as many as
55 stages in a single wellbore.
"It takes time for operators to become
comfortable with the pods and try a plugless completion," Robertson acknowledges. "Most operators initially include
the pods in their completion design by
using them to replace bridge plugs at the
toe of the well, or the portion milling assemblies can't reach. Once they see the
results, they often look at optimizing
their full wellbore design by extending
stage lengths, which reduces their total
plug count."
As an example, operators may double
their standard stage length by shooting
more clusters across each wireline run.
"Reducing the number of wireline runs
and bridge plugs by half shortens frac
pumps' standby time," Robertson says,

Oil Production (bbls)

100,000

7,253 bbl difference

80,000
6,700 bbl difference

60,000

3,200 bbl difference

40,000
Production equal

20,000
0
0

60 70 80 90 100 110 120 130 140 150
Production Day

Completed w/SlicFrac

Standard Completion

Results from two wells in the Austin Chalk show how much diversion pods can improve
cluster efficiency and production. At the 90-day mark, Thru Tubing Solutions relates, the
well with pods had produced 6,700 more barrels of oil than its peer.

46 THE AMERICAN OIL & GAS REPORTER

"resulting in total savings that can add
up to $500,000-$750,000 for each well."
The pods are designed to seal the
dominant perforation from inside the
casing, Robertson says. They resemble
a solid core made of dissolvable fibrous
material with tassels on both sides. "As
each pod flows down hole, the loose
ends catch the turbulent flow and carry
the pod to the dominant perforation,
creating a strong intrawellbore seal,"
Robertson outlines.
The pods are made of individual
fibers that deform slightly to compensate
for variations in the perforation's size
and shape. They are designed to reliably
seal each perforation, with one pod for
each perforation. According to Robertson,
they have been used successfully across
2,000 wells.
To improve cluster efficiency, TTS
suggests deploying pods during each
stage. "In many applications, operators
complete half the stage, then drop pods
to seal the dominant perforations before
pumping the remaining proppant. In extended stage applications, we typically
see better results by splitting the stage
more often to allow smaller segments to
be stimulated with each proppant cycle,"
she says.
It is common for each stage in these
applications to have two-five diversion
cycles, Robertson details, noting that
more are possible if needed.
"When we compare wells that use the
pods with ones that employ traditional
diversion techniques or no diversion at
all, we typically see a meaningful increase
in production," Robertson reports. "For
example, one Austin Chalk horizontal on
a two-well pad produced 6,700 barrels
more than its partner after only 90 days
on production."
Pod-based diversion tends to increase
production in part because the seal occurs
inside the tubing, Robertson suggests.
"This means the entire perforation is
blocked, causing the fluid/proppant to divert to a new contact point within the
reservoir. By sealing the perforation from
the inside of the casing, there's little risk
of leaving any residual material in the
reservoir," she says.
To simplify removal, Thru Tubing Solutions makes the pods from materials
that degrade when the well heats after
the frac. "In wells where some or all the
bridge plugs have been replaced, this lets
operators complete the post-frac cleanout trip faster and turn the well over to
production sooner," Robertson says.

American Oil and Gas Reporter - March 2020

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