Electrifying the North Sea: a gamechanger for wind power production?

Offshore wind turbines are the sails in Europe’s energy transition ambitions. The European Commission has plans for the continent to increase its current level of capacity from 12GW to at least 60GW by 2030 and to 300GW by 2050, while the UK is targeting 40GW by 2030.

The resource is proven turbine technology, which, apart from the floating kind, is mature, costs are competitive, and as the UK’s recent offshore wind leasing round shows, major players are clamouring to invest. Yet, the wider picture of achieving these targets is more complex.

Studies have determined that when offshore wind power assets are built at the scale planned, single, point-to-point connections from wind farms to the onshore grid using traditional high-voltage three-phase alternating current (HVAC) technology, as is currently standard, will be inefficient, more expensive, and potentially less environmentally friendly.

Instead, experts say a multi-country-connected offshore meshed high-voltage, direct current (HVDC) grid – which allows for much higher levels of energy transported with fewer losses – should be constructed in the North Sea. This infrastructure will enable supply to be more easily transported to demand wherever it may be across the five major players – the UK, Belgium, the Netherlands, Germany, and Denmark.

The foundations for a North Sea grid, which could also support the wider ambitions for a European super-grid, are already forming. But its realisation requires international co-operation and regulation – between governments and technology vendors – as well as technological innovation. And time is running out.

Presently, in the North Sea there are wind farms connecting to onshore substations, cables offshore linking to onshore points, but not generation, as well as several HVDC international interconnectors, which the EU has a target to increase.

However, to create a multi-terminal HVDC grid, which has only ever been done a few times onshore, two points need to be connected, while a meshed grid requires parallel transmission paths between the two HVDC points. Or as Fay Lelliott, a chartered electrical engineer by discipline and global practice leader for power transmission and distribution at Mott MacDonald, explains: “It’s not only point-to-point. [Take the example of] the London to Brighton main line; it’s possible to travel from London to Brighton by lots of different routes – a network that gives you redundancy and dual path to meet the final scenario.”

Connecting this labyrinth of burgeoning links has several key advantages. National Grid ESO, one of several transmission system operators (TSOs) to have assessed the most beneficial approaches to offshore networks, noted in its September 2020 report, that adopting an “integrated approach” for all offshore projects to be delivered from 2025 could save consumers approximately £6bn in capital and operating expenditure between now and 2050. It added that cables, and onshore landing points, could be reduced by around 50 per cent.

Dr Cornelis Plet, a principal consultant at DNV, who co-ordinated the PROMOTioN Horizon 2020 project to advance the development of meshed HVDC offshore grids, provides an example.

“In the north of the UK there are two HVDC lines coming together at the same location. Rather than having two separate links with their own converter stations, combining them can save a few hundred-million euros,” he says. “Doing this consistently across the North Sea, costs can be lowered significantly.”

Additionally, functions can be combined. Presently, there are separate point-to-point connections for transporting power to shore and power to other countries. A meshed grid would see these cables combined, reducing the environmental and community impact.

New HVDC links are continuing to be built and planned for. Hitachi ABB Power Grids is currently establishing the first multi-terminal HVDC Light system in Europe, the Caithness-Moray-Shetland link, which is expected in 2024. The Shetland link will connect to the existing Caithness-Moray ±320kV link to form a three-terminal HVDC network. Dogger Bank, the largest offshore wind project in the world, will be the first HVDC-connected wind farm in the UK.

Germany, which wants 40GW of installed offshore wind by 2040, currently has HVDC offshore substations for wind developers more than 100km from the coast. This includes the world’s first 200km direct current connection, which was built between BorWin1 wind farm and onshore.

TenneT, Europe’s largest and first ever cross-border transmission system operator, by 2029 and 2030 will build three 2GW HVDC connections for the BorWin cluster, connecting these offshore wind farms to the German mainland.

Saskia Jaarsma, head of offshore development at TenneT, says this will create functionality but there still needs to be another HVDC connection, possibly to another BorWin platform or to another country, to make it a meshed grid. “Therefore, we are developing options on these platforms to connect the platforms with each other, or to interconnect with other wind farms in the North Sea,” she explains.
From 2030-2040, the company expects more 2GW systems that are currently in the spatial planning process, including the IJmuiden Ver offshore connections it is developing for the Netherlands, expected from 2027.

However, TenneT is advocating for an internationally co-ordinated modular hub-and-spoke concept created by the North Sea Wind Power Hub, which consists of TenneT Netherlands, TenneT Germany, the Danish grid operator Energinet and Dutch Gasunie. This would combine wind power connection, energy markets through interconnection and smart integration in the onshore energy grid, for a gradual roll-out of 10 to 15GW hubs, as well as potentially power converted to hydrogen.

“We will not achieve the Paris climate change agreement with one- or two-gigawatt systems, it makes sense to combine it internationally, and this is a sufficient solution,” says Jaarsma. “The Danish are really driving this governmentally, which helps move it to the realisation stage.”

The Danish are taking a bolder approach. In February, the government gave the go-ahead to build two artificially constructed island energy hubs in the North Sea, 80km from the shore, at least 120,000m² in size. Around 200 wind turbines with a combined capacity of 3GW are expected to be installed in the first phase of the project, but there will eventually be the potential for 10GW. The building of the island will be done by a yet to be determined public-private partnership, but the state will have a majority ownership. A tender is expected to be awarded in 2023.

Poul-Jacob Vilhelmsen, the project’s chief manager at Danish transmission system operator Energinet, which is responsible for designing and installing the electrical infrastructure for connecting the wind park and bringing the power onshore or to another country, says the project is “exciting”.

“I cannot recall another offshore island where similar installation work has been performed. It will be a challenge,” he says.
Some have noted that offshore islands may not be the most environmentally friendly option. However, by optimising the hub configuration the environmental footprint can minimise the area of seabed impacted by cabling, Vilhelmsen says.

“I think the environmental impact will be smaller offshore, by concentrating the energy and electrical infrastructure and minimising the distance between different energy hubs developed in the future,” he explains.

Energinet is also working with Belgian TSO Elia. They have signed an agreement to assess by the end of 2021 whether it is possible and advantageous to develop a HVDC interconnector between Belgium and the Danish energy island. If greenlighted, the cable will pass through more than 600km of offshore waters of four different nations.

Belgium has opted for what it calls the Modular Offshore Grid approach. At the end of 2020, Elia completed construction of a power hub in the North Sea 40km off the coast, which will combine electricity generated by four offshore wind farms for onward transmission to the mainland. For the future, Belgium is considering building several platforms or an energy island like Denmark’s, depending on whether it receives EU funding from the European Recovery Fund to help reduce the cost to the taxpayer of the latter.

Ricardo Rocha, offshore wind technical director at global renewable energy developer BayWa r.e., believes that a more holistic approach would be better, however.

“When you integrate the grid element into the wind farm development there is more flexibility because a developer can ensure the connection of its project, whereas the other approach, which is to ready the grid first, limits how many projects can be built – which slows the energy transition,” he explains.

“With the energy island, most projects will be forced to connect to it whether it is the most economical way or not,” Rocha adds.
Moreover, John Olav Tande, chief scientist at independent research organisation SINTEF in Norway, suggests further offshore, beyond 60m of water and at greater depths, it may be preferable to have substations on the seabed.

“There is technology that can be repurposed from the oil and gas sector; it needs to be adapted and made cheaper, but it is a good alternative to having a floating substation,” he says.

While there appears to be stakeholder-wide consensus to develop a North Sea Grid, building such an expansive, multi-stakeholder, multi-country infrastructure, using novel technology throws up technical, regulatory and political complications.

Furthermore, the timelines for building grids are typically over 10 years. Therefore, in its assessment, National Grid ESO warns the development of such infrastructure will potentially risk meeting the target of 40GW of wind by 2030.

To accelerate the concept, collaborative planning between the key countries needs to happen now. Working without multi-stakeholder coordination could create challenges later; for example, HVDC grids with different voltages are very expensive or impossible to connect.
“We know how to lay cables, how to build converter platforms; the big challenge is coordinating the rollout of offshore wind and the offshore grid infrastructure together, so they have synergies,” says Plet.

For example, a wind farm in the Dutch economic exploitation zone may be physically closer to the UK, making a connection there more economically sensible, but politically challenging.

Jaarsma agrees. “It seems like an empty sea, but it’s really crowded with users and stakeholders – this can never be developed without a strong governmental backup,” she says.

Collaboration between technology vendors is also a key challenge. There are only three Western vendors for HVDC technology – Siemens, Hitachi ABB and GE – and manufacturers are not forthcoming in sharing information between themselves. There are Chinese vendors; however, the Huawei fiasco indicates that we are unlikely to see another Chinese company build highly critical infrastructure in Europe.

At a recent industry webinar held by the European Energy Research Alliance, Equinor highlighted some of the challenges of working with multiple HVDC converter vendors (Siemens and ABB) on the Johan Serverdrup project.

Dr Kamran Sharifabadi, chief engineer, electrical power systems and renewables at Equinor, said the process, which required an independent third party to perform tests to protect manufacturer confidentiality, was “extremely time consuming, costly and must be integrated in the overall project schedule”.

Additionally, the work is complex, requiring roughly four hours of simulation for one scenario testing, of which there are more than a thousand.

Andreas Berthou, group senior vice president, global head of HVDC at Hitachi ABB Power Grids, says that to create the necessary interoperability, an industry initiative needs to be established, along with the regulatory framework.

“We need to define an interface under each of these manufacturers so our systems can talk to each other, as well as a regulatory framework, so we know that when we build a mesh grid we can trade and manage different county’s regulations,” he says.

Furthermore, while much of the technology is developed, it still needs to be tested. For example, the modular multi-level HVDC converters required is novel technology, and experience with it is limited only to the point-to-point connections.

“The individual puzzle pieces – circuit breakers, converters – are, in principle, technically ready; the challenge lies in the system integration. So far, it’s all still a paper exercise – but it’s a technical engineering challenge, so it can be overcome,” Berthou adds.

Other challenges include a growing skills shortage within the sector and an ageing onshore grid that will likely need a replacement wave to ready it for exponentially more renewable power, possibly with more storage integration.

The costs will be high – the PROMOTioN project estimated that for the transmission infrastructure offshore only, it would cost approximately €1bn (£850m) per gigawatt.

To galvanise development of a meshed North Sea grid, for traditionally conservative TSOs, governments will need to facilitate more pilot projects for testing of the technology, says Berthou. This would help increase confidence, as well as leading to lower costs.
Despite the challenges, however, Plet says such an offshore grid is “now inevitable”, with America and China also contemplating the concept to support their own green energy ambitions.