DE E PWATE R DR I LLI N G MAR KETS & TECH NOLOG I E S
Fast innovation process allows
Petrobras to tap Búzios with
lower cost, higher reliability
Alignment of well design with technology R&D
and procurement strategy among innovations
helping to maximize the presalt field’s potential
BY LINDA HSIEH, EDITOR & PUBLISHER
In the Búzios presalt field offshore Brazil,
the numbers are staggering. The thickness
of its oil reservoir, for example, can reach
up to 480 m, comparable to the majestic
Sugarloaf Mountain in Rio de Janeiro.
Just one single well on Búzios can reach a
production peak of 60,000 bbl/day, and two
FPSOs on the field were able to reach their
maximum capacities with just three wells.
Further, by 2026, the field is anticipated
to account for 33% of Petrobras’ total oil
production. “Búzios is probably the largest deep-
water field in the world, or at least the
largest deepwater project in the world
at the moment,” Marcos Coradini Tolfo,
Well Construction General Manager for
the Búzios Field, said at the 2022 IADC
International Deepwater Drilling & Human
Performance Conference, held in Rio on
7-8 December. He expects Búzios to even-
tually produce 2 million bbl/day.
To tap the full potential of a giant field
like this, Petrobras knew it had to innovate,
both in terms of the way it approached
technology and in its well construction
processes. In the first phase of the Búzios’ develop-
ment after the field’s discovery in 2010,
Petrobras had been contractually bound to
produce only a limited volume. Embarking
on the second phase of development –
after securing a new contract in 2019 with
the Brazilian government to access the
rest of the reservoir – Petrobras developed
a methodology called Selepoço . It’s a con-
cept connecting well design with technol-
ogy opportunities in the early stages of the
project, Mr Tolfo said.
32 “Usually we would define the design of
the well and the technologies that we are
going to apply in phase two of the project,”
he explained. “But if we wait until phase
two, some of the technologies wouldn’t be
applicable anymore because of the lead
time to apply those technologies.”
Recognizing that being able to leverage
new technologies would be key to achiev-
ing two primary goals – reduced cost and
increased reliability – the operator zeroed in
on minimizing the lead time to deploy new
technologies . This led to the creation of the
Well Efficiency Program, or PEP70, where
the ambition was to achieve an average well
construction duration of 70 days. It defined
several focus areas for Búzios, including
connecting technology development with
the project’s procurement strategy.
The other pillars of the program were:
well safety, which called for having high-
capacity shear rams; top-hole drilling
improvements; new completion technolo-
gies, including transitioning to electric con-
trols; and reservoir scope optimization.
Open-hole intelligent
completions Mr Tolfo cited Petrobras' open-hole intel-
ligent completion technology, called PACI,
as an example of the program’s success .
Petrobras began looking at the technol-
ogy in 2011 in the early days of presalt
development, yet the first installation didn’t
happen until 2019. “We had eight years
from concept to first field installation, and
eight years is too long,” he said, noting that
Petrobras now aims to reduce that time to
four years.
Petrobras’ current development plans
for the Búzios field, located in the pre-
salt Santos Basin, calls for a firm 11
FPSOs. Four of those are already pro-
ducing, and a fifth unit is expected to
start producing in mid-2023. Six more
units are scheduled to be delivered by
2027 , and Petrobras is now considering
a potential 12th FPS O.
He added that the well where the first
open-hole intelligent completion was
installed took 91 days to drill and com-
plete, and “today we already have one
well that was drilled and completed in
65 days.”
A dditional work is ongoing to further
advance the technology. In 2024, for exam-
ple, Petrobras expects to install its first all-
electric open-hole intelligent completion,
“which we expect will be a game-changer
for us in terms of reliability and ability to
manage the reservoir,” Mr Tolfo said.
In terms of innovations on the drilling
rigs working on Búzios, Mr Tolfo said
Petrobras is planning to trial NOV’s NOVOS
drilling automation platform on one drill-
ship, and two other rigs on the field – one
drillship and one semisubmersible – will
be outfitted with a new shear ram technol-
ogy called K-BOS . Multiple rigs on Búzios
are also already equipped for managed
pressure drilling (MPD) operations. While
MPD isn’t exactly new anymore, he said,
Petrobras continues to work on enhancing
the way MPD is deployed – for example,
working through IADC to enhance well
control training in MPD operations. DC
JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R
MANAGED PRESSURE DRILLING
Dilution-based dual-gradient
technique aims to remove limiters
for drilling ultra-deep wells
Deeper hydrocarbon, geothermal wells can be
enabled by reducing number of casing strings,
preserving larger production hole size
BY ERIC VAN OORT, LEWIS J. DUTEL AND LUC DE BOER, ULTRADEEP ENERGY COMPANY
The industry’s current ability to drill effi-
ciently at great depth limits the economic
development of ultra-deep oil and gas res-
ervoirs, as well as the implementation of
the “Geothermal Anywhere” concept, which
aims to deliver clean baseload geothermal
energy at any location around the world.
Dual-gradient drilling (DGD), which was
traditionally limited to deepwater and ultra-
deepwater well construction, was recently
extended to be used in the shallow-water
shelf and onshore drilling environments.
Using a dilution-based DGD technique, it is
now possible to remove technical and eco-
nomic limiters while pursuing ultra-deep
hydrocarbon and geothermal reservoirs.
Reviving the focus on DGD
DGD technology received considerable
attention in the late 1990s and early 2000s,
with coordinated industry efforts such as
the SubSea MudLift Drilling Joint Industry
Project. Several DGD technologies were
considered for deepwater application prior
to 2010, including Transocean’s Continuous
Annular Pressure Management (CAPM)
dilution-based technology, which is a
direct predecessor to UltraDeep Energy
Company’s technology described here. At
the time, DGD-equipped deepwater drill-
ships were projected to operate in up to
12,000-ft water depth and drill wells up to
40,000-ft deep.
Post-2010, however, DGD technology
implementation was negatively affected
by a decline in deepwater drilling projects.
Later, economic downturns in 2014, 2017
and 2020 also hindered the implementation
of DGD technology in deepwater. Pre-BOP
riserless mud recovery (RMR) and post-BOP
controlled mud level (CML) drilling had
become the only surviving DGD variants.
Moreover, the momentum of dual-gradient
technology was largely lost, as many DGD
experts retired from the industry.
UltraDeep aims to revive the focus on
DGD by introducing an adaptation of the
CAPM method, which is based on dilution
to produce a dual-gradient fluid profile.
This adaptation can be implemented in
both onshore and offshore well construc-
tion. .
The dilution-based technology is a com-
bination of new surface and downhole tech-
nologies and current, off-the-shelf equip-
ment and drilling practices. It exploits the
use of a casing annulus to create a dilution
injection point at an optimized, engineered
subsurface location. Heavy-density mud is
injected through the drillstring and used
for hole-making. On its return to the sur-
face, this heavy mud is diluted with light
mud, creating a mixed mud of medium
density. The hydrostatic head in the well
on the annular side is now determined by
two gradients: medium-density mud above
the injection point and heavy-density mud
below the injection point.
Once at surface, the medium-density
mud is separated into heavy and light frac-
tions using proprietary centrifuge separa-
tion equipment. The heavy mud is subse-
quently used for drillstring injection, and
the light mud resumes its role as a dilution
fluid. A proprietary “flow stop” valve is
used at the base of the drillstring to pre-
vent U-tubing, a common issue in dual-
gradient systems due to the difference in
hydrostatic head between the drillstring
side and the annular side.
The dilution-based DGD system can be
incorporated on any standard onshore or
offshore drilling rig and is complemented
with standard MPD system offerings.
Figure 1 demonstrates a dual-gradient
well versus a conventional single-gradient
(SG) well for the same geopressured pore
pressure/fracture gradient (PPFG) profile
encountered while pursuing a deep hydro-
carbon or geothermal target. The SG well
wouldrequires eight casing strings and
end up with a 6-in. hole at TD. The same
well drilled with DG technology would
require only four casing strings and can
preserve a 12 ¼-in. hole size at TD.
Even when employing conventional
MPD technology, the SG will be difficult to
drill due to a high equivalent circulating
density (ECD) exceeding 1.0 ppg, whereas
the DG well will have an ECD smaller than
0.5 ppg. Notice in Figure 1 that the DG pres-
sure gradient profile is represented by a
curve, not a straight vertical line. This is
due to the combination of the hydrostatic
head of a lighter mud above the dilution
point and that of a heavier mud below it.
This creates a unique pressure gradient
profile that fits the PPFG profile much
better than the SG mud weight approach,
resulting in a reduction of the number of
casing strings required to get to total depth
and an associated reduction in the loss of
drift diameter.
The control over the PPFG profile is based
on the dilution weight, the rate of dilution
injection, the weight of the heavy drilling
fluid, as well as the backpressure applied
at surface, which uses a conventional MPD
surface backpressure arrangement com-
mon in today’s drilling operations.
Figure 2 compares the days versus
depth associated with the SG and DGD well
depicted in Figure 1. Reducing the num-
ber of casing seats from eight to four also
reduces the predicted days from 140 days
to 80 days. The integrity of DGD wells is
also expected to be better by having larger
cementable annuli. The associated design
changes reduce casing and cementing time
and costs, in addition to the cost savings
from the elimination of casing strings.
Moreover, the DGD well design reaches TD
with a 12 ¼-in. bit and heavier drill pipe.
In the DGD design, force transmission to
the bit (weight-on-bit and torque-on-bit) is
improved, and harmful drillstring vibra-
D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023
33