Offshore wind was the source of 10% of the UK’s electricity last year and is fast becoming one of the country’s main energy sources. By 2030, the UK government is targeting 40GW installed capacity - four times what we have today.
The Crown Estate (TCE) and Crown Estate Scotland (CES) both have seabed leasing rounds open, which will likely shape the types of projects we expect to see to achieve the ambitious 40GW deployment target. So, to answer the question that I’m surely not the only one asking, what will a 2030 offshore wind farm look like?
2030 Reference Site
I’ve built a hypothetical project based on the common characteristics of CES ScotWind and TCE Round 4 seabed leasing zones and expected technology breakthroughs, shown in Table 1.
In summary, wind farms of 2030 are expected to be bigger, with larger turbines, in deeper water farther from shore with higher wind conditions and using state of the art operations & maintenance (O&M) technologies. Sites like these may require some new thinking, and I’ve considered a few challenges and opportunities I see coming from pushing the limits of technology:
The average turbine rating five to ten years ago was 4MW, compared with an average turbine rating of 7MW for turbines in 2019 and 9.5MW for projects under construction. We’re expecting 15MW turbines to be standard by 2030. Larger turbines may be more expensive on a per MW basis, primarily due to heavier components, which require reinforcement in the nacelle and tower. However, they enable cost savings by reducing supporting infrastructure, faster installation time per MW and operating cost reductions through maintenance of fewer units. They also produce a higher average energy output, which reduces cost on a per MWh basis. At what point will the costs of fabricating and lifting these larger components outweigh the benefits listed above?
With one column versus three or four, a monopile will likely always be cheaper than an equivalent jacket in the same water depth. The depths in which monopiles are being deployed are rapidly increasing – new designs are being tested for 15MW turbines in 65m water depth. At the same time, we expect the UK’s first commercial-scale floating wind farm may be in operation, or at least in construction, by 2030. It will be interesting to see how the future share of foundation types may shift from what we’re used to.
Wave conditions affect the accessibility of a site, increasing vessel costs, and the time it can take to install turbines and perform repairs. In a harsh site, with an average significant wave height (Hs) of 2 metres, which is beyond the environmrent that turbines are deployed in to date, the levelised cost of energy (LCOE) is estimated to be 9% higher than a mild site with 1-metre Hs. Remote and automated O&M solutions will open up these sites to be more economically viable if fewer vessels are required.
The distance to an operations port has a significant impact on cost due to the frequency of vessel operations over the project life. This impact is more noticeable at a site that uses daily transfers of crew transfer vessels (CTVs) than at a site that uses service operating vessels (SOVs), which are stationed on-site for a longer period. As the transfer duration tends towards a full working day (i.e. a full 10-12 hours are spent travelling to and from the port to site), the use of CTVs becomes unfeasible.
As well as the distance to an O&M port, the decision to use CTVs or SOVs is also driven by project capacity. There is more value in using an SOV on a large site with many turbines to maintain than a small project that will have fewer site visits. The combined impact of the two parameters indicates what may be the preferred strategy at different sites. For projects that fall between, an operator may bring an SOV on-site for a summer campaign for the bulk of their O&M activity and use CTVs at other times in the year.
Most projects currently installed in the UK are connected to the grid via a high voltage alternating current (HVAC) transmission system. However, for large projects, far from shore, the cost and electrical losses become prohibitive. A high voltage direct current (HVDC) transmission system requires additional offshore converter stations, which are very expensive for small projects, and unlikely to be economical for the level of electrical losses incurred in nearshore projects. However, they may be the preferred solution for larger projects, far from shore.
Based on the site and technology parameters presented in Table 1, project costs have been estimated using ORE Catapult’s internal offshore wind cost model, shown in Table 2 to Table 5. The Levelised cost of energy (LCOE) is given in 2012 terms, consistent with strike price announcements to date and based on a pre-tax real weighted average cost of capital of 4.5%.
The LCOE follows the trajectory that we expect to see towards less dramatic cost reduction in future projects than we’ve seen over the last decade. This is in line with our high level estimations that I’ve shown in Figure 1. The need for innovation is greater than ever to keep costs going down whilst tackling increasingly challenging sites. Even so, an offshore wind fleet with an average LCOE under £40 per MWh would still bring down the average wholesale electricity price quite considerably, with the next challenge being how to incorporate increasing proportions of intermittent electricity on the grid. Any takers?
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