Floating wind power has battled rough market seas since the sector’s first industrial-scale unit was installed off Norway in 2008, dogged by a reputation of being experimental and prohibitively expensive as it chased conventional bottom-fixed offshore wind down the cost-of-energy curve.
Now, however, on the brink of international industrialisation, with first arrays under construction and analysts forecasting some 260GW of floating turbines to be turning by mid-century — a new, potentially market-changing play is emerging for the fledgling sector, led by oil and power giants including Total, Engie and Acciona.
Hydrogen — as with so many industries in the energy transition — is at the heart of it. It may seem counterintuitive but floating wind, the most expensive form of wind power — may win out as the most economic way to produce the green gas (see panel below).
Though currently much pricier that bottom-fixed offshore — or, of course, onshore wind — floating wind-powered hydrogen plants in the world’s deepwater regions could be an industrial reality sooner than many thought, with first pilots heading for the water this year to explore floating wind as an off-grid power source.
Free from electrical connection to onshore transmission infrastructure, floating wind farms could be constructed in the 80% of the planet’s waters too deep for bottom-fixed turbines. There are obvious capital benefits in not needing a high-price, long-distance underwater export lines to transport a project’s power to shore while at the same time avoiding costly marine spatial planning complexities of building closer to land.
But what is supercharging the idea is arguably more radical: emancipation from power markets’ influence. A floating renewable energy array with built-in hydrogen production installed far out to sea could produce and store H2 on platforms similar to those used for substations, with the gas then be offloaded to shuttle tankers that would ferry it to shore.
Producing hydrogen from floating offshore wind could be a market game-changer for the sector in the future
Magnus Killingland, DNV
“Producing hydrogen from floating offshore wind at an energy island, platform or even inside the turbine itself, and then sending it by ship or a pipeline to onshore industrial clusters used for clean fuels and chemicals, could be a market game-changer for offshore wind in the future,” Magnus Killingland, a principal consultant at DNV, tells Recharge.
“With long distances to shore, that is over 200km, and high installed capacity, over 2GW, it makes economic sense to transport molecules rather than electrons onshore,” he adds, while cautioning “we still have a way to go to get to cost levels which can compete with grey hydrogen including emission costs [ie, carbon pricing]”.
“Electrolysers need as many load hours as possible, which far-offshore wind farms could provide due to the stronger, steadier winds in open sea. Still, as the chemical, refining and ammonia sectors move to green hydrogen between now and towards 2050 to meet national emissions reduction targets, they will need huge quantities, and one of the main pathways to produce low-carbon hydrogen at large scale for their use will be offshore and floating wind.”
By DNV’s calculations, the best case levelised cost of energy (LCOE) for floating wind can reach by 2030 is €40 ($47.70) per MWh. “The electrolyser-added LCOE may be in the range of €20-30/MWh, and transport €10-20/MWh, resulting in [hydrogen that costs] €2.50-3/kg, when industrial scale production is achieved,” says Killingland.
By 2040, if a hydrogen price of €2.60/kg — equal to an LCOE of €80/MWh — was reached, there could be global fleet of up to 5GW of wind-powered energy islands and floating hubs exporting hydrogen via new pipelines and converted natural gas infrastructure, DNV forecasts, with deepwater plays off countries including Norway, Japan, the UK, Italy, and the US and other deepwater locations switched on during that decade.
“Ultimately, it will make sense in many cases for offshore wind to get revenues per kilo of hydrogen rather than selling power, with increasingly low capture prices. It will be a better and better business case to be a green fuel and chemical feedstock provider, rather than selling electrons. The business case for the value of one MWh of power produced at the turbine can be higher for a MWh of hydrogen than a MWh of power in the future,” Killingland says.
Scotland — having a long history in offshore oil & gas and a pressing need to devise an industrial transition model that has offshore wind at its heart — is swiftly sizing up the bigger opportunity for hydrogen in its future energy mix.
A government report late last year pointed to the country’s “abundant” offshore wind resource being harnessable to produce up to eight times more hydrogen than needed for domestic consumption in 2032 and enough by 2045 to meet not only national demand but also that of rest of the UK and continental Europe.
What proportion of this impressive total might be floating projects was not carved out by the study, but demonstrators such as Dolphyn (see main story) or the DeepWind offshore industrial cluster’s Orion project off the Shetlands — which is exploring a 2GW development at the far-offshore NE1 auction block in the upcoming ScotWind licensing round — could be formative.
Paul O’Brien, who heads up DeepWind, reckons NE1 should be seen in the context of Orion opening up “a realm of possibilities for the development of a hydrogen-fuelled energy transition economy” in Scotland.
“NE1 is a huge site and it’s in better than 100-metre water depths, so it is definitely floating. It has great wind power potential but we haven’t seen the industry interest we might have hoped for so far because it would seem on paper to be a difficult project to deliver if you are thinking connection to grid,” he says.
“But what we want developers to consider — and here we’d hope the oil industry would be particularly alive to the opportunity — is whether hydrogen isn’t the obvious alternative to just producing electricity,” says O’Brien.
Freedom from needing a grid connection and with extensive offshore oil and marine infrastructure on Shetland — including the Sullom Voe gas terminal — are part of a “strong case” for the idea, he says.
“The NE1 site could open the door to wholly different, lower cost approach to floating wind. Sites like NE1 could help these technologies power a major hydrogen opportunity.”
The wider transition of Europe’s northern seas from offshore petroleum province to marine renewable energy basin — where some 7GW of pure-play floating wind is expected to be installed this decade — could be sped up significantly, many observers agree, by weaving in hydrogen production where suitable.
Marcus Thor, CEO of technology developer Hexicon — which is working with Spain’s Acciona on a project called OceanH2 using a twin-turbine floating platform wired together with open-sea PV to produce hydrogen on-site — tells Recharge he sees the prospects for off-grid floating wind-powered hydrogen production as “intriguing,”
“The merits are, first, of course, that being offshore there is limitless water [for use in the electrolysis process]; and second, that floating wind plants could function with no connection to the mainland, producing hydrogen for offshore loading onto shuttle tankers for onward transport to industry and also for use in the future as fuel for green shipping,” he says.
“And this would get a project out of the pressures of power pricing. The need for stable electricity prices is removed because you are not dependent on grid connections or demand centres. And you can look more freely at ‘best’ wind farm locations and not be constrained by conventional infrastructure realities.”
R V Ahilan, CEO of global marine consultancy AqualisBraemar LOC, sees hydrogen production as nothing less than “the frontrunner to deliver the deepwater energy prize that is floating wind”.
“We are on the cusp of a surge in capturing the vast untapped wind resources in harsher and deeper waters offshore using floating technology. However harsher and deeper waters also often imply further offshore, putting cost pressures on energy transmission back to shore,” he says.
‘Electricity to electricity’ has historically been seen as the optimal route to market for offshore wind energy. But this need not necessarily be so
RV Ahilan, AqualisBraemar LOC
“This raises questions about in what form that captured wind energy could be transmitted to market — as electricity, as hydrogen? Due to the proximity to shore of current offshore wind projects, ‘electricity to electricity’ has historically been seen as the optimal route to market for the produced energy. But this need not necessarily be so.”
One of the first schemes to test this logic will be the Dolphyn project. Being built by Engie-owned Tractebel with engineers ODE and consultancy ERM, the project aims to channel 2MW output from the 50MW Kincardine floating wind array off Scotland to produce hydrogen that would be pumped in to oil industry capital Aberdeen from 2024. The plan is to expand this to 4GW in the early 2030s as part of a £12bn ($16.6bn) megadevelopment.
“Directly linking the floating wind turbine to electrolysers provides the most economical way of producing hydrogen, totally removing the need for export cables and grid connection issues,” argued ERM partner Kevin Kinsella as the project was launched recently.
“Dolphyn is a completely scalable technology which, once established, can be expanded across the North Sea, providing the UK with low carbon energy as we gradually reduce our dependence on fossil fuels.”
Transitioning French energy supermajor Total is sticking a toe in the floating-wind-to-hydrogen water through a project with compatriot oil contractor TechnipFMC and Danish offshore energy technology developer Floating Power Plant (FPP), which is angling to transform Denmark’s Harald oil & gas fields into a sea-based all-energy production plant using a hybrid floating wind-plus-wave concept.
The pilot under development aims to install an FPP unit, a cross-shaped semisubmersible platform design that has been tested at scale in open ocean, outfitted with a 4-15MW wind turbine and 2-4MW of wave-energy converters (WECs) that would use surplus power to generate huge volumes of hydrogen.
“Because of the way we have designed our units, we can house 300MWh of electricity on one platform,” says Anders Køhler, CEO of FPP, which has been involved in projects exploring the use of sea-based hybrid clean-energy arrays as part of offshore oil companies’ emissions reduction plans.
“The combination of wind and wave provide better power ‘quality’ because wind and waves are dispersed in time. The combination of wind, wave and hydrogen enables us to provide near-baseload power.
“We see the opportunity presented here by hydrogen to really accelerate floating clean-energy technology [finally] after many years,” Køhler tells Recharge.
TechnipFMC — a first mover in floating wind as the fabricator of the Hywind Demo’s spar foundation — has agreed new partnerships with Norwegian developer start-up Magnora and wave energy outfit Bombora to progress the concept.
Together with Magnora, the French contractor plans to develop floating wind projects globally – starting with upcoming rounds off Scotland and Norway, with an eye on including seabed green hydrogen storage, reflecting the company’s “ambition to capture a significant position in the renewable offshore energy market”.
With Bombora, TechnipFMC has launched a two-phase project dubbed Inspire that could prove up a hybrid technology which, given the overlap of energy capture from wind and waves and the resulting increase in load hours, could well be a contender for the offshore wind-hydrogen market in the future.
The pair plan to test a demonstrator unit off Norway that bolts together an 8MW floating turbine with a 4MW WEC. Slated to be operational by the end of 2023, the concept would then be scaled up to a commercial 18MW model, targeting an LCOE of €50/MWh by 2030 and under €25/MWh by mid-century.
Hydrogen, suggests Sam Leighton, CEO of Bombora, will be a useful energy transition bridgework for an oil industry that “understands” the gas and its associated technologies.
“Oil & gas markets may exist today, but renewables is the one that is growing and [contractors such as Technip] have skillsets that are going to help them reshape their business, to reposition their pieces on the chess board, to include floating and offshore [clean-energy] and later hydrogen and so on… to transform themselves,” he says.
The steadier power production promised by floating wind-wave hybrids also matches well with the load-hour demands of electrolysis, Leighton notes.
“The really enticing thing is that we can use this wind-wave platform to produce power in volume consistently because you get 50% more [power] from your seabed lease area for a start, and, yes, if there is a risk [in hybridising] it is much smaller now and the prize is very large and larger still with [green hydrogen production] in the mix.”
The wider evolution in the industrial space has seen bottom-fixed offshore wind-powered hydrogen taking shape at a clip via giant 10GW shallow-water schemes off Europe including the oil industry-led NortH2 and Aquaventus projects, and the Deep Purple pilot. A “fully-marinised” hydrogen-producing wind turbine is also in the works, through a project being run by Siemens Gamesa and Orsted. It would appear that the tipping point for floating versions of the same concept is nearing.
“The role of the oil operators and utilities will be key,” notes Killingland. “The first [offshore wind-to-hydrogen projects] are going to be in shallower water… but some of the utilities and international oil companies we are working with are certainly trying to understand how to save the cost of the export cable and instead go all-in for hydrogen.”
“As we move further from coastlines [to build] this will become an even greater factor in the economics of floating wind-to-hydrogen.”
Though a bright future appears to lie ahead for floating wind-powered hydrogen, it still faces key challenges that could slow its progress. Topmost is cost, including how green hydrogen competes with grey without emission taxes and offshore wind power LCOE still higher than on the grid — especially true of floating today.
There is also the question of hydrogen infrastructure, “costly and not available yet”, as Killingland notes, and limited experience “with system optimisation for variable power to hydrogen without a grid connection”.
“There is a long road ahead with both technological and regulatory innovation needed. However, the planned bottom-fixed offshore wind to hydrogen projects are coming online in the North Sea gradually in 2025-30, and we currently don’t see a really good floating wind farm with integrated hydrogen production before 2035 at the earliest,” he says.
“But when you see Siemens Gamesa, Total and TechnipFMC set to soon test turbines with distributed electrolysers at or inside the turbine, and other getting involved in pilots and demonstrator projects with gigawatt-scale hydrogen production, it could suddenly get moving much faster.”
“As with learning rates and cost reductions for onshore and offshore wind, solar PV and batteries, all of which have continued to lower costs dramatically over the last 15 years, you might see a similar trajectory for offshore wind to hydrogen, first the close-to-shore wind farms with onshore or energy island electrolysers, and then the far offshore also with floating power to gas.
Floating wind is currently more expensive than bottom-fixed offshore and onshore wind, which impacts negatively on its potential for green hydrogen production. After all, the price of electricity used to split water molecules into hydrogen and oxygen accounts for about two thirds of the price of the resulting H2. So how do the companies advancing pilot projects see the economics working out for floating wind-powered hydrogen?
Green hydrogen is currently two to six times more expensive than grey H2 derived from unabated natural gas, which emits nine to 12 tonnes of CO2 for every tonne of hydrogen produced.
Many international governments are widely expected to put a high carbon price on grey hydrogen, or introduce mandates to gradually enforce its phase-out. And there are many questions around blue hydrogen, not least the fact that it is not a net-zero energy vector (see page 44 for more details). So green hydrogen’s star is on the rise.
Floating wind-to-hydrogen’s economics improve too due to the fact that the more hours per year that an electrolyser is working, the cheaper the hydrogen produced. So renewables projects with high capacity factors that channel all their output to electrolysers are the best option for cost-effective green hydrogen. Floating wind has an average capacity factor of 65%, compared to 50% for bottom-fixed offshore wind.
To replace the existing 70 million tonnes of grey hydrogen produced each year — mainly used for oil refining, ammonia fertiliser production and as a chemicals feedstock — with green H2 would require almost 900GW of dedicated offshore wind projects, an increasing number of which will be more than 200km offshore, far from land-based grid connections.
Overall, the renewables capacity required for the shift to green hydrogen in the coming decades is vast, and the fastest and easiest way to build gigawatts of clean-energy projects will be floating and offshore wind.