Subsea strikes back

While significant costs have been stripped out of the oil and gas industry, shale is fighting back. And, if the subsea industry is to survive, it will need more than just reduced costs, industry executives told the Underwater Technology Conference (UTC) in Bergen. Elaine Maslin reports.

The Njord A production facility, into which the Pil and Bue discoveries are set to be tied.Image by Thomas Sola, from Statoil.

Subsea has a fight on its hands – the opponent is the shale business, the challenges are high costs, a harsh environment to work in and a fragmented market.

So far, huge costs have been stripped out of the industry, through business “right-sizing,” but also product and process rationalization and project simplification. Vertical integration, through mergers and alliances, are also making their impact felt.

The scale and duration of the downturn has meant strategies have had to change, Stuart Fitzgerald, VP technology and strategy at Subsea 7, told UTC Bergen, a city which, like others, has felt some of the pain of the downturn.

To paint the picture, he says that, in 2016, just one project was sanctioned in Norway. Over the past three years, just five have been sanctioned, compared to 25 over the three years before that. “It has been a very painful process for many companies and the people in those companies. Shale has changed the game and created a different dynamic in the industry and subsea has had to fight back.”

Shale is also fighting back, with what Rystad has called Shale Chapter 2, and while the oil price has been resting at above $50/bbl or above for some months, offering some stability, recent drops below $50 have injected some nervousness.

However, to date, there have been more projects sanctioned in Norway than there were in 2016 (which was just one), more are expected and there’s more optimism about substantial final investment decisions being made in 2018, he says. “A recovery is not assured, but sentiment has shifted, for now, mostly because of better project economics,” Fitzgerald says.

He cites Statoil’s Johan Castberg, which he says was put at US$16 billion in 2014, and is now at $6 billion. According to IHS, deepwater projects have also reduced breakevens, from an average full cycle, including drilling, of $60/bbl to under $40/bbl, Fitzgerald says.

Johan Castberg, an artists’ illustration.Image by Kåre Spanne, from Statoil.

Knut Nyborg, head of front end, Aker Solutions, reflected some of the uptick in sentiment. He told UTC: “We have won more front-end engineering and design (FEED) in the last six months than ever before in a six-month period.” He says cost has been cut and efficiency improved, with a 50% reduction in lead time and 30% reduction in man-hours for Xmas trees. Digital and automation technologies had also helped to drive a 50% increase in the speed taken to produce umbilicals, he says.

“Subsea has reacted well,” Fitzgerald says, by revisiting solutions and field designs, looking at staging projects. “We’ve had time to revisit projects,” he says. The results were evident at UTC. Australia’s Woodside, Murphy Oil and VNG presented new slimmed down, simplified concepts for subsea tieback developments.

On Pil and Bue (bow and arrow in Norwegian), offshore Norway, VNG has to deal with waxy oil and host facility (Njord) constraints. VNG plans to remedy this through use of electrically trace heated pipe-in-pipe technology. Murphy is working on its Gulf of Mexico Dalmatian project – a 50km tieback on which it is planning a subsea multiphase pump at 35km step out. Woodside has managed to circumvent the issues around getting the Greater Enfield project – a 32km subsea tieback offshore Australia – into an existing floating production system swivel designed for 3km tiebacks by modifying the slip rings and using uprated subsea pumping, without having to have a subsea transformer.

Improving processes and early engagement have helped, as has also changing cultures and attitudes towards removing waste, Fitzgerald says. Lower raw materials costs, currency variations and deflation due to excess capacity in the supplier market have also helped, he says. “The key is, what’s structural (sustainable) and what’s cyclical (reversible)? Estimates are that only 50% is sustainable if we revert to business as usual,” he says.

Nyborg agrees. “We need to explore contract models. We must change from contractual silos. We see opportunity to optimize the entire field, from wells to products. Bundling saves cost, but why stop there?”

As part of a project with Statoil, called NCS2017+, a portfolio of projects was gathered and then looked at collaboratively. “Nothing was sacred, no requirement went unchallenged,” Nyborg says. “Then, we came up with solutions for the whole portfolio of projects and that’s a clever and effective way of doing standardization. I’m optimistic, if we see more of that.”

The challenge to develop cost-effective, but smart, field solutions is getting harder, however, says Tore Havlorsen, executive vice president and senior advisor, TechnipFMC, who has a similar vision, albeit from a different route. “We, as suppliers, are trying to deliver a system to an operator that has less and less information about the field. Fewer wells are being drilled. This [the concept selected] has to be frozen 2.5 years before it is used.

“For me, a perfect project would be that you buy a small starter package,” Halvorsen says, “And, from there on, I will configure the next tree based on what you find out in the next well. Need water injection? I will configure that for you, which means we become more dynamic as a supply industry as the operator is. We are far from that, but think about what that could achieve. Vendor-based specifications are mandatory and agreements have to be in place.” Like Nyborg’s idea, such an approach would enable a more industrialized manufacturing process and, therefore, cost and lead time savings.

Nils Arne Sølvik, president - processing, OneSubsea, also thinks vendor-based specifications would enable the industrialization needed to reduce costs (consider there are four main vendors yet some 140 clients – 200 before 2014). But, Sølvik told UTC that contracting models also need to change, with performance-based philosophies a way to avoid the potential return to “business as usual” and the cost escalation we had in the recent past, alongside integration and life of field solutions.

However, a structural change is happening, Fitzgerald says. “The majority of operators are now introducing a different approach. These include design competitions, partnerships and client-driven alliances.

Indeed, on Dalmatian, Murphy has developed a “unique contracting strategy” – a turnkey engineering, procurement, installation and commissioning contract, with a back-end loaded payment structure – with the multiphase pump vendor, OneSubsea, which has helped Murphy get the project over the line. “With the EPIC approach, we can save three months of schedule. We are not telling the market what we want, we are letting them come to us with solutions,” Mike Clarke, project manager, Murphy Oil, said at UTC.

“These models allow suppliers to engage earlier, drive optimization of fields and work on value driven delivery,” Fitzgerald says. Through a FEED process with Centrica, costs on a project were reduced 45%, he says.

“We are seeing a shift in commercial models and client partnerships,” with the likes of paying for performance, design competitions, design through to installation. “These are delivering results for Subsea 7. But we need to continue the structural change to ensure sustainable improvements in value creation for subsea because shale is breathing down our neck.”

Fitzgerald also offers a word of warning. In a slimmed down industry with fewer staff, careful planning will be needed as the market recovers in order to maintain execution quality. The industry should also use more of the tools it already has in its technology tool box, Nyborg adds, such as separators, pumps, etc., to increase from mature areas.