MANAGED PRESSURE DRILLING
Click here to see more graphics from this article.
Figure 1 (left): A new dilution-based dual-gradient technology allows for well designs with fewer casing strings compared with
a conventional single-gradient well, as illustrated in this simulation of an ultra-deepwater gas well in the US Gulf of Mexico.
This is primarily because of the more favorable mud density gradient profile (red dotted line) of dual gradient compared with
single gradient. Figure 2 (right): For the well shown in Figure 1, reducing the number of casing strings also reduces the pre-
dicted days needed for drilling, from 140 for a single-gradient well design to 80 with a dual-gradient design.
tions, usually a significant drilling limiter,
can be mitigated with a stiffer drillstring.
Rate of penetration is expected to benefit
from these measures. The larger production
hole size is particularly important when
pursuing geothermal targets, which typi-
cally require larger diameters for produc-
tion fluids than oil and gas wells for eco-
nomic heat and power production.
Application in geothermal
well construction
New geothermal technologies vary in
focus and areas of advancement. Surface
technology is generally coupled to a spe-
cific subsurface design or targeted heat
source. There are also a smaller num-
ber of other technologies focused on heat
transfer innovations and new wellbore
construction methods that deviate from
current oil and gas drilling practices. Few
of these technologies, however, are at an
elevated technology readiness level (TRL),
and even fewer are operationally ready for
implementation. 34
UltraDeep’s dilution DGD package is at a
high TRL and can be deployed with exist-
ing land-based drilling rig operations. The
integration with standard drilling tech-
nologies provide access to deep (15,000-
25,000-ft TVD) and ultra-deep (25,000-
35,000-ft TVD) well construction opportu-
nities. The ability to drill these geothermal
wells to these depths with large bore is
critical to implementing the Geothermal
Anywhere concept while drilling through
geopressured sedimentary rock in pursuit
of deep targets.
The large-bore well design at depth pro-
vides several benefits, including reduced
well construction time and costs, as well
as a reduced carbon footprint from rig
operations, casing and cementing time.
The larger bore at TD is the required con-
duit needed to scale heat and energy trans-
fer. Additionally, the well integrity and
zonal isolation improvements enabled by
DGD are essential for long operational life,
as well as the ability to implement new
technologies restricted to large-bore wells.
Accessing ultra-deep gas
reserves Sizable deep and ultra-deep gas reserves
exceeding 100 Tcfe are present along the
US Gulf Coast. From 2000 to 2010, sev-
eral attempts to access these reserves
were undertaken with various projects,
such as Davy Jones, Blackbeard, Joseph,
Highlander and Lineham Creek.
Except for the Highlander project, the
technical and economical limits of con-
ventional drilling methods of the time
were reached on most of these wells, and
the projects ended prior to completion.
This was primarily due to drilling prob-
lems associated with well control, induced
lost circulation and wellbore instability.
However, by using dual-gradient drilling
technology, in combination with conven-
tional MPD technology, the industry can
eliminate most, if not all, of this nonpro-
ductive time.
“Dilution-based dual-gradient drilling”
continued on page 36
JAN UARY/FEB RUARY 2023 • D R I LLI N G CO N T R ACTO R
MANAGED PRESSURE DRILLING
MPD-enabled real-time pressure
testing helps Shell improve safety
in ‘conventionally undrillable wells’
Results from dynamic pressure tests during
drilling enable selection of optimal strategies
for safer well construction in deepwater GOM
BY STEPHEN WHITFIELD, ASSOCIATE EDITOR
Shell has registered a ton of experience
with managed pressure drilling (MPD) in
the US Gulf of Mexico (GOM) over the past
four years. Armed with 27 wells and more
than 300,000 ft of hole drilled, the company
believes it has set a new standard in deep-
water safety by leveraging MPD, includ-
ing using the technology’s capability to
conduct real-time dynamic pore pressure
assessments, dynamic formation integrity
tests and dynamic leak-off tests.
These tests not only helped Shell with
pressure management and early kick
detection, but they also allowed the opera-
tor to redefine target depths while drill-
ing, trip and kick margins, well-balancing
methods and the cement design.
“Most wells where we use MPD are
already challenging from a safety and eco-
nomic perspective,” said Nathan Tuckwell,
Wells Engineering Team Lead – Deepwater
MPD at Shell. “Although the well planning
process includes detailed formation pres-
sure predictions, there are still levels of
uncertainties during the actual drilling.
Real-time MPD tests have been proven
throughout our campaigns to improve the
management of the process safety risks
associated with these wells.”
Speaking at the most recent SPE/IADC
Managed Pressure Drilling & Underbalanced
Operations Conference in Kuala Lumpur,
Mr Tuckwell outlined how two specific
tests – the dynamic pore pressure test
(DPPT) and a combination of the dynamic
formation integrity test and dynamic leak
off test (DFIT/DLOT) helped the operator to
balance various GOM wells, run casing and
then cement. The DFIT/DLOT is the MPD
version of the more conventional formation
integrity test and leak-off test.
Mr Tuckwell discussed the use of MPD,
DPPT and DFIT/DLOT on a pair of wells
drilled as part of a drilling campaign
that began in 2018 using Transocean’s
Deepwater Thalassa drillship. This was
Shell’s first MPD application in the deep-
water GOM for what it called “conven-
tionally undrillable wells” – specifically,
wells that could not have been drilled
without incurring severe circulation losses
during drilling, tripping and cementing
while simultaneously elevating the risk
for safety issues during the well construc-
tion process.
Key among the MPD system’s compo-
nents were an annular surface pressure
control system that communicates with
the MPD equipment and the rig’s control
system. The surface pressure control sys-
tem utilizes the capabilities of a central-
ized, programmable automation controller
with an integrated human-machine inter-
face screen. It also allows users to run
an integrated hydraulic software model
that enables real-time management of the
annular pressure profile and monitoring of
well construction parameters.
Completing hole sections
safely In his presentation, Mr Tuckwell talked
about one well where the DFIT/DLOT pro-
vided real-time information that allowed
the operator to determine the maximum
kick intensity that the MPD system could
handle without exceeding formation lim-
its. In the 14 ¾-in. hole section, for exam-
ple, Shell was able to determine the safest
strategy for drilling the section, tripping
out, running casing and then cementing,
Mr Tuckwell said.
The test began with the MPD choke
operator increasing the surface back pres-
sure (SBP) in small increments. The flow
balance behavior (flow-out vs. flow-in)
and the rig active pit level were then
observed. In instances where the balance
was preserved and the target equivalent
mud weight was not reached, the opera-
tor proceeded with a subsequent pres-
sure increment, repeating all observations
until an agreed DFIT value was reached
or when a slight loss was detected. This
helped to establish a DLOT point.
At that final maximum pressure stage,
the reading from the pressure-while-
drilling (PWD) tool was defined as the
confirmed or new limit. The SBP then
returned to the original value observed
before the start of the test.
Before displacing the kill-weight mud
into the drill pipe, Shell performed a DFIT
test. That test revealed the formation was
beginning to leak off and showed losses at
14.3 lb/gal – the presence of leak-off meant
that a DLOT test had to be run. For that test,
the well was displaced to a 14.1-lb/gal sur-
face intensity, with the MPD system main-
taining a minimum 14.1-lb/gal bottomhole
equivalent circulating density (ECD).
The displacement was completed in
two stages. First, the drillstring pumps
were used to get the 14.1-lb/gal fluid up to
the riser. After that, the displacement was
finished with the boost only. The BHA
was stripped out of the well with the MPD
holding the SBP to offset swab. The RCD
bearing assembly was retrieved, and the
BHA was pulled out of hole conventionally.
The DFIT test allowed Shell to identify
the point at which the losses started. This
was set as the weakest point in the well-
bore, providing an actual reference point
that otherwise, if not spotted, could have
led the operator to overdesign the balanc-
ing method for the well, inducing more
losses that could have triggered unsafe
conditions. “In this case, we just stopped drilling at
a certain point and ran the DFIT and DLOT.
We saw that the limit was not where we
thought it was, and it had actually started
leaking off at a point earlier than we expect-
D R I LLI N G CO N T R ACTO R • JAN UARY/FEB RUARY 2023
35