MANAGED PRESSURE DRILLING
Machine learning-based pressure
management technology brings
full automation to MPD operations
BY STEPHEN WHITFIELD, ASSOCIATE EDITOR
Automation in MPD operations is not new
– operators and service companies have
been utilizing technologies and software
to automate various components of an
MPD system for years. Recently, though,
Opla Energy says it is bringing its ambi-
tions for a fully automated MPD system
that can run with no human intervention
to reality with its Pressure Management
Device (PMD).

The device, which is installed above the
BOP, is designed to replace conventional
MPD systems in both land and offshore
rigs. It connects to the rig’s control system
and utilizes proprietary machine learning
models to process rig data, such as flow
rates, mud weights, pressures and rheol-
ogy. After users input a desired downhole
pressure, the device automatically adjusts
the choke position, which is connected to a
non-linear closed-loop controller installed
with additional proprietary machine
learning algorithms, to account for pres-
sure changes due to pipe movement and
flow rate changes.

The machine learning models installed
in the device also train it to anticipate
potential pressure changes in the future,
helping to maintain a consistent downhole
pressure throughout the drilling operation.

“When you look at a traditional MPD
system, in order to calculate the hydrau-
lics model needed to maintain a pressure
profile, someone typically has to feed the
survey results, the BHA, the mud prop-
erties and so on, back into the system
on location. We’ve done away with that,”
said Elvin Mammadov, President of Opla
Energy. “This device is really a bi-direc-
tional stream of data. It sees the downhole
and surface data coming from the well in
real time, and we can control and actually
change the settings as needed.”
Development of the PMD began in 2019,
and Opla conducted field trials on a land rig
from its parent company Citadel Drilling in
September 2021 at the Wolfcamp D shale
in the Midland Basin. During testing, the
contractor was able to drill one well using
the PMD in just eight days, compared with
an average 16 days for other wells on the
same field drilled with a conventional
MPD system, according to Dan Hoffarth,
Citadel CEO.

The device has also led to a reduction in
NPT during rig-up. Rigs operating with the
PMD have averaged around 2.5 hours of
rig-up time, he added. By comparison, rigs
operating with Opla’s conventional MPD
packages average 8-10 hours for rig-up.

This is because the PMD is designed to use
much less piping than a conventional MPD
system, so the PMD can fit within a much
smaller physical footprint – the company
says it is around the size of a coffee table.

“As drilling contractors, we’ve have
never had so much scrutiny over NPT in
our history, so we really need systems that
can come to a location and be rigged up
in a simplistic manner,” Mr Hoffarth said.

“We’re also eliminating a lot of risk, both
from an operations perspective and a time
savings perspective, by not having all that
piping to build up.”
After the device was commercially
launched in September 2022, a Canadian
operator completed the first fully remote,
automated MPD tripping operation in
December, using the device on a well in the
Anadarko Basin in Oklahoma. Significant
time savings were realized, according to
Opla, because of the efficiency and speed
of the machine learning algorithms; they
replaced the MPD personnel typically
working on location.

For the Anadarko operation, Opla report-
ed reduced time in drill pipe connections
– the rig running the PMD reduced the
time for each connection by approxi-
mately three minutes compared with rigs
using a conventional MPD system. This
added up to time savings of approximately
Opla Energy says its PMD can fully auto-
mate MPD operations by using machine
learning models to adjust the choke
manifold and account for pressure
changes. The device was recently de-
ployed in Oklahoma, the company said,
to complete a fully remote, automated
MPD tripping operation.

5.5-6 hours for the well. The operator also
saw significant improvement in bearing
assembly change-out operations, reducing
the time required from approximately 30
minutes per bearing assembly change on
a well with a conventional MPD system to
just five minutes, according to Opla.

Opla Energy contracts the PMD directly
with operators, but it works with drilling
contractors to install the device on rigs.

The device is currently installed on 12 land
rigs, including one rig owned by Citadel,
in the Permian, Eagle Ford, Anadarko,
Haynesville and Canada’s Montney Shale.

For the future, Mr Mammadov said Opla
is looking to make potential enhance-
ments to the machine learning algorithms
around, for example, ROP optimization.

“We’re exploring the causes of nonproduc-
tive time and seeing how else we can help
the well to be drilled even faster. Maybe
that means giving suggestions with a
push notification sent into the field, or
something else.”
Further, while the PMD is already suit-
able for land and shallow-water drilling
because the device’s bearing assembly
bowl was designed to replace the above-
tension-ring rotating control device (RCD),
it can also be modified for use in deepwa-
ter. In those applications, where the BOP
and the RCD are installed underwater, the
bearing assembly can be removed and
replaced with a four-way port block that
can be used in conjunction with a below-
tension-ring RCD. DC
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