DNV GL has various efforts under way with oil
companies as industry works to embrace digitalization technology and standardization to improve
productivity and help reduce operating costs.
Lundin Norway and DNV in August said they
developed the first step toward forecasting unplanned shutdowns of Lundin Norway’s Edvard
Grieg platform within the Utsira High area in the
Norwegian North Sea.
The platform and associated infrastructure, on
stream for 2 years, is equipped with more than
2,000 sensors. Lundin Norway is the operator
with 65% interest. Partners are Wintershall 15%
interest and OMV 20% interest.
Lundin and DNV engineers worked with four
students on a project to use data analytics to detect
events that might cause an unplanned shutdown.
Another goal of the data analytics was to initiate
necessary preventive action.
Kjell Eriksson, DNV oil and gas regional man-
ager, Norway, said, “We’ve seen similar results in
several other digitalization initiatives we’ve had
lately. Engineers with domain knowledge of oil
and gas operations are critical to complement the
data analytics approach.”
The students created statistical models that
they trained using the data generated by sensors.
They built a computer program to analyze the re-
sults of each statistical model.
Previously, DNV directed a joint industry project
(JIP) standardization collaboration that resulted in
a recommended practice (RP), DNVGL-RP-0101,
covering technical documentation for engineering,
procurement, and construction phases of subsea
JIP participants wanted to establish a set of
minimum paperwork between oil companies,
contractors, and suppliers.
Industry devotes much time and numerous
staffers to assemble technical documentation.
“If we were to quantify the replications across
the supply chain, we could realize that many of
these activities add very little or no value to the
safety or performance of the subsea equipment
and systems,” said Martha Viteri, DNV head of
subsea and well systems.
Jan Ragnvald Torsvik, Statoil’s lead engineer of
life cycle information and JIP co-chair, said Statoil
benefitted from implementing a draft RP version
in the Johan Sverdrup project, which is under construction in the Utsira High area with production
expected toward yearend 2019.
He said the RP “will dramatically cut waste in
handling technical information...this standard’s
approach in utilizing package specific require-
ments has a positive impact on standardization,
efficiency, and quality.”
A contractor in the JIP said subsea documenta-
tions increased by fourfold during 2012-15. The
Norwegian Oil & Gas Association and Petroleum
Safety Authority Norway were JIP observers.
In addition to Statoil, JIP partners included:
Aker Subsea AS, Centrica Energi, Det Norske
Oljeselskap ASA, DNV GL, FMC Technologies,
GE Oil & Gas, GDF SUEZ E&P Norge AS, Kongs-berg Oil & Gas Technologies AS, Lundin Norway
AS, Oceaneering, OneSubsea, RWE Dea Norge
AS, Subsea7, Subsea Valley, and Suncor.
DNV also is testing a remote surveillance service for
subsea equipment manufacturers. Both contractors
and operators seek improved safety and increased
flexibility on testing schedules for surveys and inspections.
Viteri said DNV has developed protocols to optimize an interface between cameras and software.
The camera can be manually operated or installed
on equipment. The camera is focused on critical
equipment points and its feed is transmitted to a
surveyor’s or inspector’s office, cutting travel costs.
“Pilots show clearly that remote witnessing is
an acceptable tool for independent surveillance
when suitable conditions are met,” Viteri said.
“With remote witnessing, operators purchasing
subsea equipment can now observe vendor tests
as they happen.”
Previously, operators relied on third-party ob-
DNV promotes digitalization