28 Offshore August 2017 • www.offshore-mag.com
commissioning team was supported by QEDI.
Production from the project is expected
to ramp up to a plateau level of 130,000 b/d
before the end of 2017.
Subsea technology has taken off over the
last few decades, and many of these enhance-
ments and improvements would be critical
to Schiehallion’s revamped subsea system,
especially since Train said it was one of the
first deepwater developments when it came
onstream in the late-1990s.
Train said brownfield redevelopments such
as Quad 204 required “a fine balance between
understanding what you need to replace and
what you are able to keep.” That balance was
particularly challenging here, given the com-
plexity of the existing subsea system and the
need to expand capacity and extend field life.
An additional challenge would be compatibility
issues, particularly pairing up the new control
system with legacy equipment.
“Subsea technology has evolved and improved, and through field life there had been
enhancements and updates to the control system within Schiehallion. So, what we had to do
was design a system that could accommodate
different evolutions of the existing control
modules and at the same time take a step into
the future with the latest controls technol-
ogy,” Train said. A standard was established
for the control system that considered the
types of technological evolutions and industry
learnings since the field was first designed.
From there, BP worked with Aker Solutions,
the control system provider, to ensure it was
backwards and forwards compatible.
For example, to manage the compatibility
between new and legacy, BP used controls distri-
bution assemblies. With high-speed communications coming from the FPSO, that distribution
assembly on the seabed would then slows down
the signal speed, then take the signal to each of
the individual wells. There are 14 distribution as-
semblies on the seabed at different drill centers.
It was designed to provide the highest possible
reliability and enhanced diagnostics capability
back to Glen Lyon, and BP said it would also
avoid the need for an intervention vessel that
would otherwise perform the diagnostics.
Train likened it to “moving from analog
A decision was also made to switch to an inte-
grated control system between subsea and top-
sides, a change from the previous system, which
Train described as being much like a separate
unit bolted on to the topsides control system.
Another key challenge he identified was
in the diver-less flowline connection system.
BP standards for subsea materials had moved
on from the original field design and requali-
fication of the connection system, supplied
by AFGlobal, using different materials was
necessary. The original ROV tooling used
for the DMaC connection system had been
in service across the Foinaven and Schiehal-
lion assets for the original developments and
through operations. T wo new suites of tooling
systems were designed and built to make and
break over 200 connections that would be
needed as part of the redevelopment. These
were integrated with work-class ROVs.
Aker Solutions and AFGlobal were not the
only legacy equipment manufacturers to return to work on the Quad 204 project. Others
included OneSubsea, who had provided the
new and replacement subsea Xmas trees.
Train said another key challenge in rede-
velopment was the highly congested seafloor.
Once again, a lot of destruct was necessary
before proceeding with the new build-out.
The company said that 96 items were disconnected and recovered from the seabed before
installing more than 292 new assembled com-
ponents over five drill centers and the FPSO
location. Due to the water depths, everything
was completed diverless, adding an additional
challenge, with ROVs moving around the
congestion and working on both new and the
more challenging legacy equipment. Subsea
construction took over 3,000 construction
vessel days using 14 different construction
support and pipelay vessels over a five-year
period. The harsh water west of Shetland environment required all work to be compressed
into five- to six-month “summer” window. At
peak, there were 11 vessels and over 900
people working infield at the same time.
Train said that a key success factor for the
subsea construction work was a highly col-
laborative relationship with the installation
contactor Technip. The combined team recog-
nized the challenges of successive and complex
offshore campaigns and focused on planning
each campaign “in excruciating detail,” closely
tracking safety and efficiency performance dur-
ing the operations and having pre-determined
contingencies readily available when unex-
pected events occurred or to bring activity
back in line with the plan. Through learning
and continuous improvement, he explained that
the team was able to increase vessel working
efficiency by over 20% from the first campaign,
achieve each campaign full scope and even pull
some work for ward.
In addition to layering in various technological enhancements that have occurred over the
years, BP’s own standards and practices have
progressed over the years. This meant materials
had to be verified against latest standards and
practices. As a prime example of this, Train said
that in the analysis of the existing gas lift and
export infrastructure, BP found an issue with a
phenomenon known as flowline-induced pulsa-
tion. This required laboratory testing to design
and build dampers that were then installed by
ROV at more than 30 locations on pipework
within existing manifolds on the seabed. Train
said it was a full project within its own right, with
detailed analysis on everything from the design
of the damper to where the dampers would be
placed through to installation and testing.
In 2015, BP started a seven-year drilling
campaign west of Shetland as part of the re-
development, with the sixth-generation
Deepsea Aberdeen MODU contracted from Odfjell
Drilling. The work began on Loyal and then
moved to Schiehallion as part of the campaign.
Once again, newer technology and advanced understanding met up with legacy
equipment, Train said, which led to some
unexpected re-design work.
The rig had a bigger, stiffer drilling riser system than the fourth-generation rig that had been
in use until that point. This resulted in greater
forces being exerted on the wellhead system,
he said, causing the team to have to move from
a 36-in. conductor to a 42-in. conductor. That in
turn meant a new verification program around
the welding and fabrication of the larger conductor that would take time. On the first six wells,
BP had to design, fabricate, and install a support
structure that would allow the use of the 36-in.
conductors until the verification program on the
42-in. conductor was complete.
Train said that “the investment in the well-
head system and the new MODU has paid
dividends as the wells are being drilled and
completed safely, much more efficiently and
at significantly reduced cost than before.” •
The build for Quad 204’s new Glen Lyon FPSO took four years and 21 million hours.