De-engineering

Elaine Maslin

August 1, 2016

Statoil is applying new concepts and new thinking to the Johan Castberg development on the Norwegian Continental Shelf. It’s a DC fiber optic future, Elaine Maslin reports.

Transocean’s Polar Pioneer semisub drilled the Skrugard prospect in 2011, now part of the Johan Castberg field.
Photo: Harald Pettersen/Statoil.

During this year’s Subsea Valley Conference in Olso, Norway, Lundin’s CEO Kristin Færøvik made a typically bold statement: “The good thing about the [low] oil price is it forces us to do things differently. The price had got too high on the Norwegian Continental Shelf. That’s part of my optimism.”

The amount of capex shaved off projects was a prominent topic for speakers at the annual event. Statoil’s CEO Eldar Sætre stated that having had average US$70/bbl capex in 2013, some 80% of the firm’s project portfolio now stood at $45/bbl and that was dropping to below $40/bbl.

But, while a large amount of that saving has been helped by a 25-30% drop in rig rates, there has also been, even before the oil price plummet, a hunt for innovative and smart solutions to help reduce costs and simplify developments.

The Johan Castberg development is a case in point. Capex costs have been reduced by nearly 50%, from $11.3 billion to about $6 billion, thanks to “selecting a floating project combined with efficient subsea solutions and an effective drainage strategy,” Sætre told Subsea Valley. “Innovative solutions and engineers with good smart ideas” have been brought to bear.

One solution, which Statoil has been working on with French telecommunications cables firm Alcatel Lucent Submarine Networks (ASN), was to develop a new subsea power and communications cable system, reducing and simplifying the infield architecture. Statoil has also been taking a more risk based approach to infield flowlines protection and reassessed its drainage strategy.

An artist’s illustration of the FPSO. Image from Statoil. 

The field

The Johan Castberg area is regarded as the next major development in the Norwegian Barents Sea, opening up a new province in the north. A final investment decision has been set back from the original mid-2014, with production start-up in 2018, to today’s planned 2017 decision, with first oil possibly by late-2022. Delays have focused on costs, but also disappointing exploration results in the area and tax changes.

Johan Castberg, previously known as Skrugard, comprises three oil fields, Skrugard, Havis and Drivis, discovered in 2011, 2012 and 2014, respectively, in 380-400m water depth in PL532. The fields sit in a relatively under-produced part of the world. The nearest developments to Johan Castberg are Snøhvit, about 100km to the south, which has been producing since 2007, and Eni’s Goliat, the Barents Sea’s first oil development, some 150km away, and which only came onstream this year. Goliat is some 240km from Melkøya.

A key decision for the field has been around having a pipeline to shore, favored by the Norwegian government, and initially by the field partners, versus tanker offloading.

Early this year, Aker Solutions was selected to provide a concept study, focused on a floating production, storage and offloading (FPSO) unit, which will have a winterized design, qualified for ice loads, in the harsh Barents environment, plus measure including deck heating and falling ice protection, with tanker offloading. IKM Ocean Design also won a two-year contract for subsea integration pre-FEED and FEED, covering pipelines, risers, cables, tie-ins and related structures.

An FPSO model drawn up during Aker Solutions’ Johan Castberg concept development. Image from Aker Solutions.

Reducing costs

The drainage strategy on Johan Castberg is based on long, horizontal producers, containing autonomous inflow control devices and gas lift, with gas-reinjection and water injection for pressure support.

In the latest incarnation of the development, the number of wells needed has been dropped from 40 to 31 and the number of templates from 15 to 10, plus two satellite, said Tore Karlsen, flowline manager Johan Castberg project, Statoil, at Subsea Valley. This means the number of risers has also dropped, from 18 to 11. All of which has reduced the length of pipe and umbilicals required to 116km, cutting materials and installation costs, as well as the number of rig days.

DC fiber future

A significant new element to Johan Castberg is its electric and communications infrastructure – in the form of new direct current fiber optic (DC/FO) cable technology. ASN, now part of Finnish communications giant Nokia, has been working on the technology since forming an agreement with Statoil in 2011-12, which Chevron has also supported. The goal was to design a solution incorporating high-bandwidth communications with reliable electrical power supply into subsea control systems, with “near-unlimited distances at any sea depth,” says Håkon Frøyshov, principal engineer, subsea cables leader Johan Castberg project, Statoil. The result is an electrical and optical fiber infrastructure – separate from service umbilicals – to connect a production facility with subsea nodes, which can be placed inside or outside the subsea template, anywhere along the cable. The daisy infrastructure can feed 10kW downstepping the backbone high voltage to low voltage wet mate user interfaces, without any requirement for high voltage connectors, and wet mate direct fiber optic connection from the platform.

Depending on how it is configured, each node could serve 1-2 templates, or, to put it another way, at each node four electric outputs independent of each other can provide 2.5kW power, plus two fiber optic wet connectors. The nodes, which can will be controlled from the FPSO, have also been designed to have a standardized interface, to be independent of any subsea supplier.

“They have a standard DC 400V interface, can communicate with any subsea control module on the market and can have optional inverters, to AC 220V, 400V or 500V,” said Ronan Michel, O&G product line manager at ASN, at the Underwater Technology Conference (UTC) in Bergen this June.

The cable, which is in the final stages of qualification, is comprised of two electric conductors with fiber optic in the middle, and can either be powered by the production facility, or for long-distance step-outs, of up to 350km, with 100kW, Frøyshov says. The system may be equipped with more than eight nodes providing that overall system power (100kW) is not exceeded.

“The cable is fully repairable re-using standard telecommunications techniques that have been proven in 8000m water depth,” Michel says. “Cable end boxes and Y-splices enable future tie-ins.”

As well as extending cable length capabilities (current limitations are up to about 150km), the beauty of the design is that, on Johan Castberg, which would have had some 16 separate cables feeding eight templates, just two DC/FO cables will be needed, looping around the lot, Frøyshov says.

“Traditionally, one template, you would have two electric leads to provide electric power, each providing 1.5kW, for redundancy,” he says. “For Johan Castberg, we have many templates. If we had eight templates, we would need 16 cables for power. With DC/FO, we can get the same from one cable with 10kW to each template, and this includes fiber optic.”

Of course the hydraulics and chemical lines are still needed. But, delinking the electric and fiber optic from umbilicals means there’s more space in the umbilicals, which also become cheaper and more reliable, just supplying hydraulics and chemicals, he says. It’d also be easier to make repairs to a DC/FO cable, being able to cut and splice sections, rather than having to replace whole hybrid umbilical cables, Frøyshov adds.

“The most vulnerable part in such a system is the electric,” he says. “Hydraulic is more reliable, so you can put more templates in series. If you have damage, you can repair that in this system while leaving the hydraulics. It simplifies the riser base, as you don’t need so many connections, and it makes installation easier. It simplifies the dynamic umbilical and you can have more flexibility in it as more space is available [for hydraulics, chemicals, etc.) so there is more future flexibility.

“There are other upsides too,” including lighter topsides support equipment. “It’s also an enabler for control functions for future tiebacks at least below 200km distance, i.e. there are no length limitations below 200km.”

Add in electric-trees, which Statoil is moving towards and hoped to see within five years, another presenter told a session during UTC, and you have the potential for an even more simplified system. Indeed, Michel says, if you went all electric, all you would need would be the DC/FO cable and a chemical line – or use local chemical storage on the seafloor.

The DC/FO can be installed and ploughed within a single pass from a single and cost-effective standard installation cable ship. Rock dumping or mattressing are typically limited to e.g. pipe crossing. In addition, since the DC/FO is repairable from a standard maintenance cable ship, in areas where external risk aggression (e.g trawling) is limited, ploughing may be replaced by surface lay.

Flowline risk management

Karlsen’s focus has been on simplifying the flowlines at Johan Castberg. It’s a very irregular seabed, he says. Traditionally, this would mean all the production pipelines have to be protected by rock, which means excavation works and precise rock placement.

It’s a huge cost, so Statoil took another look. “We started using a risk-based approach,” says Karlsen, to both protection covers and rock placement. Using locking of inline structures on infield flowlines, not just on export lines, enables the removal of protection covers and reassessing the rock dumping regime reduces 70% of the cost for this work, he estimated. “This is in area with no trawling, so why cover non hydrocarbon carrying products? We don’t have a total solution, but have road map and tool box now,” he says. “This is what we call a design to cost way of thinking.“

“The total saving today is NOK1 billion ($118.5 million). But we are not stopping there. We are using the tool box to ask if bigger pipe can protect smaller pipe,” i.e. if something did trawl over the pipe, if a smaller pipe was laid next to a larger pipe, would its strength prevent damage to the smaller pipe. Furthermore, could residual curvature in the pipe be used and matched to the seabed?

The work is ongoing and is no doubt more comprehensive than what we can cover here. Indeed, there have also been discussions around whether Johan Castberg’s FPSO, and therefore the subsea infrastructure, could be powered from shore. When it finally does get to project sanction, and first oil, Johan Castberg will be a further step for the industry into the Barents Sea, however.

What’s more, developing Johan Castberg could mean infrastructure is in place for other nearby fields, such as Lundin Petroleum’s Gohta and Alta finds.

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Power trip