MANAGED PRESSURE DRILLING
ed. We had to make a decision. Where are
we going to set our casing? How are we
going to adjust the mud weight? Can we
keep drilling? We found that this was the
best strategy for completing the well safely.”
Determining real-time pore
pressure Shell has also conducted several DPPTs
with the same MPD system. These tests are
conducted with returns through the MPD
system while pumping downhole through
the drillstring with slow rotation. The
returns are lined up to a single pit system
or a pit with the smallest possible surface
area, in order to make it easier to identify
and measure any changes in mud volume
during the tests.

The pore pressure is determined by a
real-time PWD measurement. The well is
constantly measured, and the volume of any
potential influx is measured by a Coriolis
flow meter.

The test is performed once the bit is at
depth. With the MPD system lined up, the
rig mud pump section is isolated and the
returns are directed to a single pit system.

Once the flow rate and all other MPD and
rig parameters are stable and the returns
are clean, the MPD hydraulic model is cali-
brated to account for fluid expansion during
each pressure decrease step. The SBP is
reduced at small intervals, and all MPD and
rig parameters are recorded at each interval.

“Dilution-based dual-gradient drilling”
continued from page 34
UltraDeep is working to partner with
existing leaseholders to utilize the dual-
gradient technology to reach additional
formation targets of deep and ultra-deep
gas shelf and onshore reserves on existing
leases. It is worth noting that the production
infrastructure needed to commercialize
produced gas is within easy reach through
existing pipeline networks.

When effectively accessed, these ultra-
deep gas reserves can supply the growing
LNG infrastructure along the Gulf Coast.

More than 20 LNG terminals have already
been proposed to feed the growing LNG
supply chain with Europe.

Further, there are important secondary
36 These pressure decreases continue
toward a planned target until the MPD
system detects a gain. Once seen, the
PWD at that point is recorded as an initial
flowing pressure, and the SBP is increased
to the value required to obtain the same
standpipe pressure recorded just before
the start of the DPPT.

If the SBP amount is within the parame-
ters established in the well’s MPD Operating
Matrix and Influx Management Envelope
when inducing the influx and its volume,
the influx circulation can then be per-
formed with the MPD system – through the
riser, at full circulation rate, with returns
aligned to the rig’s mud/gas separator.

DPPT tests have helped Shell define the
safest strategy to determine the formation
pore pressure in real time. In fact, the first
such test that the operator performed in
the deepwater GOM is used as a reference
case to safely optimize all well construc-
tion processes in the region, Mr Tuckwell
said. This first test was performed using a
surface mud weight of 10.3 lb/gal while
flowing at 700 gal/min down the drill-
string. The test began with MPD targeting
an approximately 11.1 lb/gal ECD, which
required a 560-psi SBP. The SBP was
reduced in small incremental steps during
the test.

When the ECD reached approximately
10.75 lb/gal while holding 260-psi SBP,
the formation pressure was reached and
fluid began to enter the wellbore. SBP was
increased, overbalance was reestablished,
and the influx was stopped, followed by
removal of the influx in the well by circu-
lating through the MPD equipment while
concurrently displacing the well to a 10.8
lb/gal fluid.

After further analyzing the data collect-
ed from the DPPT, the formation pressure
was estimated to be closer to 10.77-10.81
lb/gal. The influx was circulated out of the
well and up through the riser using the
MPD system to maintain a constant BHP.

During the influx circulation, a displace-
ment from 10.3 lb/gal to 10.8 lb/gal surface
mud weight was also conducted.

The DPPT showed that the influx
expanded once at the surface. Mr Tuckwell
said this was not typically seen in cases
where the Coriolis flowmeter was installed
downstream of the MPD choke manifold.

With this particular well, the Coriolis
had been installed upstream of the MPD
chokes, and the test revealed that this was
an effective solution to determining for-
mation pore pressure. DC
benefits that can be achieved with the use
of DGD technologies, including:
The existing pipeline transport resourc-
es and proximity to shore can create addi-
tional value later in the (ultra-)deep well
lifecycle for CO 2 sequestration, where
depleted natural gas reservoirs can be
coupled with enhanced gas production
by injecting CO 2 into the reservoir as it is
being produced. This process is known
as carbon sequestration with enhanced
gas recovery. In addition, highly depleted
reservoirs without secondary gas recovery
potential may be used for direct carbon
capture and underground storage.

■ Wells drilled at great depth have reser-
voirs at elevated temperatures, allowing
for potential co-production of gas and heat,
with the latter to be used for electricity
production. In addition, there is the poten-
tial to convert wells late in their lifecycle
to geothermal wells, harvesting heat long
after all natural gas is depleted.

Proving dual-gradient technology for
onshore and shallow-water wells will de-
risk the technology for (ultra-)deepwater
applications. Note that true dual-gradient
technology has not been deployed in deep-
water in forms other than riserless drill-
ing, as CML technology is currently only
used for ECD reduction.

The geographical application of deep-
gas DGD technology is certainly not lim-
ited to just the US Gulf of Mexico Shelf and
onshore Louisiana. There are also similar
deep gas targets that can be pursued in
areas like the Mediterranean – offshore
Israel and Egypt, for example – and the
Far East – such as offshore Malaysia and
Indonesia. DC
For more information, please refer to SPE/
IADC 210541, “Real-Time Downhole Pressure
Environment Determination During Managed
Pressure Drilling, Tripping and Cementing
Operations to Improve Well Construction
Safety Standards in Deepwater Gulf of Mexico.”
JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R




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
D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023
37