DI G ITALI ZATION OF DR I LLI N G
The ECO platform uses surface and downhole sensor measurements to calibrate the current state of a wellbore. These mea-
surements are then shown on a single interface, making it easier for rig personnel to stay within the corridors of the well plan.

generated by the software take into account drillstring param-
eters, friction coefficients, rheology and the density of the drilling
fluid. The drilling roadmap component organizes various param-
eters – ROP, WOB, estimated flow rates, section lengths, as well
as the mechanical and hydraulic load estimates from the drilling
section plan – for each planned interval. In the bit hydraulics
component, users can select the bit configuration that will maxi-
mize the bit impact force on the bottomhole.

Once analyses is performed through these modules, the soft-
ware builds a digital twin of the wellbore. By using surface and
downhole sensor measurements – on drillstring parameters; mud
density, rheology and temperature; drilling fluid; the well profile;
and friction factors – the twin is always calibrated to the current
state of the well. These parameters are visualized on a single
interface, helping the driller and other personnel ensure they stay
within the corridors established in the well plan.

The software also provides predictive trend deviation analysis,
integrated with hydromechanical analysis, to predict fluid gains
and losses, pipe-sticking mechanisms, cleanup problems and
washouts during well construction. Users are alerted to potential
issues so they can decide whether to take mitigating actions.

“ECO provides flexibility to configure the system per client
needs, to function either in supervisory or fully automated modes.

In both scenarios, actionable insights are delivered to decision
makers in a timely fashion,” said Khaydar Valiullin, Co-Founder
and CEO of WellsX.

He also described the platform as self-learning – effectively,
each well drilled becomes an additional data point. Users can
replay the drilled well data with parallel real-time calculation of
the mechanical and hydraulic loads, and they can analyze well
logs to clarify lithological information of the reservoir. When the
user plans future wells in the same field, or in different fields with
20 similar geologies, the system will leverage that previous data to
inform the design of new wells.

“The more we utilize the system, the more useful it becomes,” Dr
Valiullin said. “Even if you don’t have offset data, the digital twin
is running in the background so you’ll have examples of previous
exploration drilling to give you a better idea of what you’re doing.”
The technology has been in operation since 2019 for sev-
eral operators and drillers working in Eastern Europe, including
Hungary, Croatia and Serbia.

It has also been deployed in the Volga-Ural region of Russia by
an operator who sought to optimize well construction time for
onshore wells in mature brownfields. During drilling, the ECO
system’s predictive analytics tools alerted personnel to emerging
hazards related to wellbore integrity and open-hole quality, such
as stuck pipe, wash-outs and twist-offs. This capability enabled
continual updating and optimization of the drilling plan after
encountering potential hazards.

The operator saw a 16% reduction in average construction time
for directional wells drilled in the Volga-Ural region, as well as
a 20% reduction in sidetrack wells, according to Dr Valiullin. He
attributed a major part of the time savings to off-bottom activity,
as automated analyses of the drilling plan revealed that up to 30%
of the time spent conducting off-bottom activity in the drilling
plan was NPT.

While WellsX has had limited engagement in the North
American market so far, it now has plans to participat e in a geo-
thermal project in South Texas, Dr Valiullin added.

Last year, ECO was approved for deployment by a major nation-
al oil company in the Middle East after successful onshore and
offshore implementation. In June, WellsX also announced a joint
venture agreement to provide its technology for its clients in the
Middle East. DC
SEPTEMBER/OCTOBER 2023 • DRILLING CONTRACTOR




WELL CONTROL READINESS
Standardizing subsea BOP soak
testing: overview of value and
recommended best practices
Proposal for API Standard 53 annex aims to unify
testing methodology while considering different
BOP configurations, potential for digital tools
BY PATRICK HILLARD AND LEONARD CHILDERS, IPT GLOBAL;
AND AHMED OMAR, SEADRILL
The BOP soak test is an important yet
often misunderstood part of deployment
preparation for subsea BOPs. Although it
helps improve both the safety and efficien-
cy of drilling operations, this test remains
an area lacking industry standardization,
leading to potential uncertainties and
inconsistencies in BOP performance. This
article explores the history, challenges and
potential to standardize an often-over-
looked contributor to well control equip-
ment reliability.

The well control equipment
evolution The first BOPs were sketched out by
James Abercrombie and Harry Cameron
on a sawdust-covered machine shop floor
just east of downtown Houston in the early
1920s. Since then, the industry has come
a long way. State-of-the-art equipment is
used to set wellheads more than 10,000
ft below the water line, deploy, latch and
remotely operate multiplex subsea BOPs,
and then drill into ultra-deep, high-pres-
sure hydrocarbon reservoirs.

To safely accomplish these engineer-
ing breakthroughs, rigorous verification
requirements such as pressure testing,
function testing, manufacturing specifica-
tions, maintenance protocols and kick/
leak-off detection methodologies have
been developed. These standards have
regularly been adopted by state and fed-
eral regulators and incorporated into API
Standards and/or the Code of Federal
Regulations, in the context of subsea BOPs
and subsea BOP control systems.

BOP soak test value
The BOP soak test involves detailed
evaluation of the multiplex electro/
hydraulic circuitry in both the primary
and secondary control systems of the BOP.

It applies a predetermined pressure to
various operators and fluid circuitry for a
required duration. During this test, subsea
engineers meticulously inspect the BOP
for visible leaks, weeps, drips, fogging and
other indicators that inform necessary
maintenance before deployment. In many
instances, digital monitoring and pressure
signal analysis are performed concurrent-
ly to expedite the soak testing process and
mitigate the need for extended trouble-
shooting iterations.

A robust soak test prior to subsea deploy-
ment provides an essential assessment of
the health of the BOP. It provides crucial
insights into the BOP stack’s fitness for
service by identifying potential issues that
could affect its performance and availabil-
ity once deployed. By physically inspecting
the BOP and analyzing the stabilized pres-
sure readings over a brief period, trained
personnel can identify leaks or potential
component degradation within each pres-
surized fluid circuit. This not only facili-
tates troubleshooting and smarter mainte-
nance efforts but also offers stakeholders
peace of mind by ensuring due diligence
has been accomplished to protect person-
nel, the environment and related assets.

While soak testing remains the fore-
most method to assess control system
health before deployment, it’s imperative
to understand the inherent limitations.

Soak tests can’t replicate the multifaceted,
real-world conditions a BOP would face
when placed on a wellhead. These factors,
such as stack movement (both tension and
compression), fluctuating temperatures
and varying hydrostatic pressures, can
significantly impact system performance.

Recognizing these challenges, some BOP
owners have pioneered innovative testing
procedures. One such approach involves
placing the stack under tension during
surface testing, simulating the separation
forces encountered at interface connec-
tions. This method has proven beneficial,
unveiling issues related to the design of
specific seals. Moreover, these insights
have inspired the development of designs
that are better equipped to handle such
dynamic movement, ensuring enhanced
reliability and operational efficiency.

Thus, while current testing methodolo-
gies provide valuable insights, it’s impor-
tant to continually evolve, capturing the
nuances of real-world operations in the
form of recommended best practices.

Recent industry performance
data Technological advancements have
prompted industry experts and regula-
tors to develop stricter requirements for
equipment verification. These improve-
ments reflect a deeper understanding of
the industry’s increasingly complex equip-
ment, enabling refinement of testing pro-
tocols to ensure they are fit for purpose.

Historical data presents some signifi-
cant findings. As outlined in the BSEE-
sanctioned report, “Blowout Preventer
(BOP) Maintenance and Inspection Study
by the American Bureau of Shipping and
ABSG Consulting Inc. (2013),” 61% of sub-
sea BOP system failures were linked to
the control system. Notably, the blue and
yellow control PODs, along with the sur-
face MUX control system, accounted for
over half of these failures. The study’s
mean time to failure revealed an average
of 48 days of operation between compo-
nent failures. It’s crucial to note that due
to built-in system redundancies, some of
these recorded failures signaled the need
for upcoming repairs rather than indicat-
ing a stack pull.

Fast-forward to the current era, where
detailed defect data is available from the
Rapid-S53 database. In the 2018 and 2019
DRILLING CONTRACTOR • SEPTEMBER/OCTOBER 2023
21