American Oil and Gas Reporter - August 2019 - 108

Painted Pony Energy and Wintershall
Dea-to improve models for estimating
vertical frac growth. He explains that
many of the traditional models were developed for conventional reservoirs and
tend to overestimate vertical frac growth.
"One of the reasons for that overestimation is geologic interfaces, or the
boundaries between beds," he says. "If
the boundaries have an imperfect seal, or
weak interfaces, the frac fluid can slip
between the beds and travel along them.
In that situation, some of the energy gets
put to the side instead of going upward,
as the old models assumed.
"To allow more people to try our simulators, we are putting parts of our technology into a cloud-based app," O'Conor
reports. "With that app, users will be
able to take surface drilling data, engineer
completions, and get production and economic forecasts, much as they can in our
traditional software. But because it does
not need to be installed on local machines
and can be licensed on an as-needed
basis, it will be easier to try and less expensive once the user sees the value."
Real-Time Monitoring
Given how much geology can vary
from stage to stage, even within a single
well, operators are moving away from
optimizing completion programs by conducting intense but expensive tests on
science wells, says Panos Adamopoulos,
founder and chief executive officer of
Seismos Inc. Instead, he describes, they
are using modern technology to understand
the subsurface and evaluate completions
quickly so they can iterate from well to
well or even stage to stage.
According to Adamopoulos, one of
the most effective evaluation methods involves sending acoustic pressure pulses
into the well after each frac stage and
using the reflections to reveal the fractures'
height, half-length and width, as well as
the fracture network's near and far-field

complexity, conductivity, and proppant
placement.
"This technique gets data to the frac
van in near real-time," Adamopoulos emphasizes. "This is extremely powerful,
because it means the completion engineer
can make adjustments from stage to stage
until the fracture network has the desired
characteristics."
Such real-time optimization can yield
significant production increases,
Adamopoulos says. "The size of the increase is all over the place because of
variations in reservoir quality and the
base line completion design's effectiveness,
but in general, it exceeds 10%," he says.
"We frequently see increases in production,
but most importantly, more sustainable
pressure depletion."
In one of the more dramatic applications,
the well completed with real-time adjustments was producing 32,000 barrels of
oil equivalent and had a wellhead pressure
of 900 psi 50 days after it came on line.
By that point in its life, the offset's production was at 18,000 boe with a wellhead
pressure of 300 psi, Adamopoulos relates.
"The equipment's footprint is almost
zero," he says. "To read the acoustic
pulses, we put a small instrument module
on the wellhead, which takes less than
half an hour. There is no change to the
frac job and no need for offset wells,
geophones or other equipment, so it is a
plug-and-play solution."
The acoustic pulses travel down hole
through the wellbore fluid, dissipate into
the fractures, and reflect back, Adamopoulos describes. Because the reflections
only need to travel a short distance and
do so through the wellbore fluid rather
than the rock, he says they can be measured
accurately without geological models,
which often incorporate assumptions that
might be incorrect. "This makes our error
bar extremely small," he reports. "In fact,
from tests where we could compare the
measurements with core data, we know

This wellhead instrument
records acoustic pulses that
allow Seismos Inc. to characterize fracture networks on a
per-stage basis and provide
information operators can
use to refine their completion parameters. The company emphasizes that the
technology works without requiring any extra downtime,
changes to hydraulic fracturing procedures or offset
wells.

108 THE AMERICAN OIL & GAS REPORTER

it is less than 5 percent."
In addition to characterizing the fracture
network after each stage, the acoustic
pulses can analyze each stage's perforation
tunneling before pumping begins to warn
the operator when stages may be difficult
to treat, Adamopoulos mentions. He says
this can allow changes in the completion
fluid's chemistry or the stage's pumping
schedule to minimize the amount of pressure and time needed, as well as the risk
of screening out.
"These connection checks act like insurance," he says. "The adjustments made
to the completion chemistry might cost
$3,000-$4,000 for each stage the service
flags, but that is far less than bringing a
coiled tubing unit on site to deal with a
screen-out, which can cost north of
$100,000."
Downhole Video Analytics
With the right analysis, downhole cameras can help completion engineers evaluate cluster efficiency, says Todd Lilly,
senior technical sales adviser for U.S.
land at EV. "By using cameras to capture
images of the perforations and dimensioning those perforations with cuttingedge video analysis software, we can
measure how much each perf has eroded.
The more extensive the erosion, the more
proppant went into the perf," he explains.
To calculate each stage's eroded area,
the company needs to know each perf's
initial size. "A bigger hole has more exposed surface area, so it will tend to
erode faster than a smaller one," Lilly
says. "A few operators record the perfs
before the frac to capture their pre-frac
size, then go back afterwards to capture
the erosion. But to save time and money,
we generally recommend shooting perforation reference holes that are never
fracced. These reference holes allow us
to estimate the other stages' starting perforation sizes at each phase angle, eliminating the need for prefrac camera runs."
The videos are sent to an office in Houston for analysis, Lilly relates. "While we
do extensive quality checks, much of the
work is automated," he says. "Since we
know the size of the tool assembly's centralizer blades, our software uses them as a
reference to calculate the size of each perforation, then compares that with the reference hole values to determine the amount
of erosion. The measurements are proven
accurate to within a hundredth of an inch."
The software tallies the total eroded
area for each stage, breaks that into
percentages for each perf, and applies
those percentages to the amount of
proppant pumped during the stage to
estimate how much went into each cluster, Lilly outlines.

American Oil and Gas Reporter - August 2019

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