No part of the E&P sector, however previously successful, has been immune to the industry’s intense focus on cutting expenditure and improving efficiencies. This is forcing all of the participants in the subsea market, whether end-user clients or service and supply contractors, to take a long hard look at how they—like every other market sector—can raise their game.
Two of the keys to unlocking continued new opportunities are the industry’s increasing adoption of wider collaborative research and technology initiatives, which help to share the costs and risks of developing new or improved solutions for targeted technology gaps, and also the recognition that forming new partnerships and alliances in the industry downturn can open up significant opportunities for companies to take on larger subsea projects than they were previously able to tackle on their own, with the resultingly higher risk shared more satisfactorily.
The overall prize remains clear. According to Neil Gordon, CEO of industry body Subsea UK at its Subsea Expo event in Aberdeen, Scotland, global subsea production output is set to grow by an estimated 80% between 2015 and 2020. This represents an investment of between $30 billion and $55 billion, he said.
But the industry is “in a totally different place with a totally different perspective compared to last year,” he said, and the next couple of years are expected to be tough.
His message, however, was one of “Don’t panic.”
Gordon said the operating landscape had changed dramatically over the past few months and that there was now a need to drive efficiency through innovation and technology. “This industry does go through cycles of highs and lows. We have been here before. We don’t have to panic. This is a long-term industry based over decades of investment.”
Infield Systems researcher Kieran O’Brien backed up Gordon’s warning of continuing tough times ahead for 2015 and into 2016, with operations in frontier areas such as the Arctic and East Africa likely to be delayed.
In the Gulf of Mexico, peak shallow-water activity is expected around 2016, while final investment decisions on deepwater developments there are also likely to be deferred. Deepwater activity is expected to recover, however, from 2017 to 2020 onward.
The perennial indicator of the health of the subsea sector—tree orders—made gloomy reading. Global subsea tree orders are expected to fall to 2,227 for the 2015-to-2019 period. This is down substantially from Infield’s earlier forecasts of 3,142. Spending on subsea trees is, however, likely to pick up in 2018, O’Brien said, with high levels of ultradeepwater tree orders expected.
That downturn has been exemplified by recent decisions to pull back from certain challenging subsea projects.
Shell’s Ormen Lange Field offshore Norway is one. The company’s plans for potential offshore and subsea compression, which it had agreed last year to prepare, are now not progressing. The operator and its partners are looking to identify viable alternative solutions to increase recovery, with a working group examining options to reduce costs.
“It is still too early to conclude if a project to increase recovery beyond onshore compression will be reopened as a future opportunity for Ormen Lange,” Shell told E&P’s sister publication Subsea Engineering News.
The possible scrapping of offshore compression will be a jolt for the Norwegian authorities, who have always shown willingness to invest in offshore R&D, and it may well be that the subsea option will not stay off the table forever. There also is the small matter of the $315 million already invested by the licensees in the subsea compression pilot project. Unlikely to be simply written off as money down the drain, it has yet to be formally explained how the subsea compression option compares with surface/onshore compression, the main aim of the pilot.
Ormen Lange lies 120 km (75 miles) offshore and is a greater challenge than Statoil’s Åsgard project, where the operator is progressing well with its subsea compression plans. That option was established long ago as preferable to platform-based compression for the 37-km (23-mile) tieback. The compression trains are due to be installed this summer, slightly behind schedule, with startup later this year.
The search for cheaper development options also has produced economically viable rival solutions to subsea tieback projects.
Statoil, a big proponent of subsea normally, has opted for a remotely controlled unmanned wellhead platform as the favored concept for its Oseberg Future project. It had first warned last year that there might be a swing away from subsea back toward surface installations as a means of cutting costs.
“The alternative was to place the wells on the seabed, but the costs of subsea wells have tripled during the last decade,” explained Anders Opedal, senior vice president, projects at Statoil. “We have therefore chosen a jacket-based unmanned wellhead platform that will reduce costs by several hundred million kroner.”
Dubbed “subsea-on-a-stick,” the stripped-down platform—for which three different concept studies were made—has no living quarters, helideck or lifeboats. These facilities will be located on the support vessel, which will transport maintenance crews to the platform instead of helicopters.
According to Ivar Aasheim, Statoil’s senior vice president, field development, the costs of subsea systems are still rising. While unmanned wellhead platforms without facilities represent a new concept for Norway, Statoil said, they are of course common elsewhere.
Further pre-studies of the concept will be carried out, opening the way to an investment decision next winter.
This theme was touched upon by GE Oil & Gas, with its senior vice president for subsea, Neil Saunders, expressing concern about companies looking for alternatives to subsea, which will assuredly drive down cost, as will collaboration. Customers are looking to shed between 15% and 25% of capex while at the same time slowing down projects.
He was talking at GE’s annual event in Florence, Italy, where BP’s Bernard Looney was also a guest speaker on a standardization panel.
Looney, in charge of BP’s operated upstream production, pointed out that with 64% of industry projects facing cost overruns and 73% running late, there needed to be more collaboration—but “collaboration with a purpose”—between operator and supplier to keep costs down. “The cost structure was too high at $100/bbl, let alone at $50/bbl,” he said, and the reality was that revenue has decreased by more than 50%. He called for “radical change” in business practices through engaging with suppliers.
Looney highlighted one successful example—that BP’s 16 deepwater rigs had 600 days of downtime in 2012, equivalent to almost two units being out for a year. By teaming up with GE, however, that was brought down to 200 days.
On standardization, Looney said BP had been working with its suppliers over the past 18 months to reduce specifications on equipment where its specs went beyond industry standards. Unnecessary complexity is being built into kit.
Another panelist, Michael Utsler of Woodside Petroleum, said his company had gone through a similar exercise and it was “staggering how many examples of incrementalization” had been seen. He pointed out one example where a Woodside employee had refused to accept a critical piece of equipment because it was priced at $1,700 in the catalog, but—with various add-ons—it was $27,000 supplied.
Partnerships and alliances
Back at the Subsea Expo event, Phil Simons of Subsea 7 stressed his belief that better collaboration is the answer and was able to demonstrate how it can be done.
He highlighted its Diving Support Vessel Initiative, or DSVi, arrangement in the U.K. North Sea, where it has provided services since 2009 to six different operators covering 40 small fields. This was an example of a possible model for companies looking to make savings and efficiencies on opex and maintenance. “As an industry, we have become more risk-averse. Collaboration helps to understand risk,” he said.
Other partnerships and alliances in and around the subsea sector have been springing up regularly. The last couple of years had already seen significant moves by players such as Schlumberger and Cameron in forming their OneSubsea joint venture (JV) company, followed by Baker Hughes and Aker Solutions with their “Subsea Production Alliance.” OneSubsea also went on last year to form an alliance with both its parent companies and Helix Energy Solutions Group to develop technologies and deliver services to optimize the cost and efficiency of subsea well intervention systems and their operating envelope.
One of the latest to adopt an alliance approach is McDermott International, which has sealed two such arrangements so far this year, pairing with Petrofac and GE Oil & Gas in separate deals.
The Petrofac linkup is for an initial five-year period and is pursuing top-tier ($200 million-plus in value) deepwater subsea, umbilical, riser and flowline (SURF) projects, giving each partner access to a wider geographic reach than they have individually at present. The aim is to provide operators with an integrated solution across a range of the more complex engineering, procurement, construction and installation subsea projects in deep- and ultradeepwater.
This includes combining McDermott’s SURF fleet, its new derrick lay vessel DLV 2000 and its strong subsea fabrication capability with Petrofac’s newbuild JSD 6000 installation vessel currently under construction, which will have ultradeepwater pipelay, subsea lowering and above-surface construction work capabilities.
McDermott’s pairing with Petrofac followed an announcement in January about its “io oil & gas consulting” alliance with GE, aimed at tackling the front-end deepwater development process on a holistic level at the design and planning stage. One aspect of that deal will see GE in particular lend its domain expertise in subsea production systems. (See related story.)
The most recent companies to make a similar move are FMC Technologies and Technip, with their new 50/50 JV Forsys Subsea. This field development entity brings together two market leaders after their management first started talking about coming together to find a way to cut project costs last summer—long before the precipitous oil price fall.
In fact, the falling oil price only highlighted the need to find a way to reduce project capex. If field economics were struggling at $100/bbl, what would they look like at the current $50/bbl to $60/bbl or even at (predicted by some) an eventual recovered rate of around $70/bbl to $80/bbl?
According to one FMC executive, it is where the impetus has come from. The inference is that rather than a “lowly” engineer from an operator suggesting a new way of doing projects to his boss, who then has to climb the ladder to find a champion, the current drive to reduce costs is coming from the very top—with worried CEOs aware that they might be replaced if they cannot find a way to revive earnings to previous levels.
At the Forsys launch in March, substantive numbers were given out, and the idea that 25% to 30% could be cut from project capex by letting Forsys undertake a project looks enticing. As is often the aim of such ventures, Forsys wants to get involved as early as possible in the project process.
Technip will be putting up some of the resources of its front-end specialist Genesis, with FMC throwing in its FEED team as well. However, Forsys is not only aiming at the front end but also the full life cycle, including well performance and maintenance. In addition, the companies will jointly fund R&D to drive further innovation to boost efficiency and reduce development costs.
“The world needs new sources of oil, and deepwater holds the greatest promise of meeting this demand. But these sources are expensive to develop, and operators will not pursue them unless they can significantly reduce costs,” said John Gremp, FMC’s CEO, in the accompanying press release.
Technip’s CEO, Thierry Pilenko, added separately, “Beyond concepts, we need to be strongly focused on the practicalities of project execution—simplicity, standardization, innovation, technological creativity and delivering tangible results to clients.”
Change in culture
Such moves are a step in the right direction. Another speaker at Subsea Expo, David Lamont, the CEO of Aberdeen-based Proserv, stressed the need for the industry to do what it can within its own controlled areas rather than be prone purely to oil price fluctuations. “If we are designing something, we should design to that cost,” he said. “And we should ask ourselves, ‘Are we bringing complexity in where it cannot be afforded?’”
Fellow speaker Mark Richardson, Apache North Sea’s projects group manager, highlighted just such an instance.
Apache’s requirement had been for a retrofit subsea choke valve with installation required by a specific time and with a valve lead time of 22 weeks. The traditional contractor’s approach saw Apache receive a proposal for a 7-m-by-7-m (23-ft-by-23-ft) over-trawlable structure with a planned delivery date eight weeks after the specified date, a required installation sea state of 1.2 m (4 ft) and the use of a metrology spool. The engineering quote was $174,000 with a fabrication cost of $732,000.
Not accepting this, Apache went back to the market looking for a new approach and eventually received a fit-for-purpose solution delivered on time, able to handle installation in a sea state of up to 3 m (10 ft) and with no metrology spool. The engineering cost was $45,000 with a fabrication cost of $75,000.
“Technology has its place, but currently it’s not the whole answer. It’s about how we do things,” Richardson said.
CGG has commenced the acquisition of a new high-density 3-D survey in the Anadarko Basin, the company said on Jan. 15.
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