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The MT Interview: Sonja Chirico Indrebø

Editor’s note: As part of developing the April 2022 issue of (mt) magazine focused on metocean, (mt) Editor Douglas R. Kelly and (mt) April issue lead Brian Cheater spoke with Sonja Chirico Indrebø, vice president of floating offshore wind at Norway-based Equinor. The conversation provided insight into how metocean conditions impact the design and deployment of offshore wind facilities. Here we present that conversation as exclusive bonus content for the readers of (mt).


Sonja Chirico Indrebø. Photo by Ole Jørgen Bratland.

Sonja, in the world of offshore wind, what are the differences, if any, between the met-data that’s gathered for engineering purposes and the data that’s gathered for long-term resource assurance?

SONJA CHIRICO INDREBØ: We see this difference between areas where we have long-term measurements like in the North Sea and to more unknown areas where we buy hindcast data for early phase developments and also perform LIDAR measurements for wind farm detail design. The engineering focus is on design parameters such as extreme winds and turbulence while resource assessments require high accuracy measurements of wind speed over time at several heights. We can derive wind speed data for both purposes from floating LIDARs and also, turbulence intensity can be derived from met masts (a met mast, short for meteorological mast, is basically a floater with a mast on top that has meteorological equipment to measure wind, wave, pressure, all these things) or from hindcast models. Therefore, advance analyses of wind turbine wakes parameters characterizing atmospheric stabilities are required and these are also usually derived from hindcast data.


KELLY: What kind of models and analyses do you rely on to ensure you’ll have an accurate picture of the long-term wind resources at a site?

INDREBØ: We normally use LIDAR measurements and build our wind models for designing wind farms. Then the preferred solution is for us to apply techniques such as linear regression to long-term correct hindcast data with measurements from sites.


KELLY: What can you do to mitigate the risk that’s associated with long-term wind resource prediction? What types of criteria would you use to assess this?

INDREBØ: For us, the onsite wind measurement is the primary way to reduce uncertainty and wakes generated by other wind farms…existing and future are known to reduce the wind resource and we can assess this through modeling. We have seen little evidence that climate change will cause large changes in wind resource in the near future. These are the kinds of ways we work on “de-risking” the data.


KELLY: How might climate change affect the design of floating wind and fixed bottom wind farms? Are there any factors that we can’t design around?

INDREBØ: One of the unknowns is, of course, sea level rise and that could potentially be a risk for bottom-fixed wind farms, depending on how much we’re talking about. But that is not a risk for floating, because the benefit of a floater is that they will just float a little higher, like it goes with the waves currently. And I guess that climate change could impose more frequent extreme conditions.


BRIAN CHEATER: Yes. That’s my understanding…while we’re going forward, the biggest change will not necessarily be an increase in temperature, even though that will be a part of it. The biggest factor will be an increase in the variability that we have to live with, and the shift between one extreme and the other.

KELLY: Variability…meaning the unpredictability?

CHEATER: The unpredictability of it. That’s right. It’s dealing with conditions that could change very quickly and on a more extreme basis than they do today. How much data do you guys like to collect before you go in and say that you have a certain wind resource at a site? Is there a certain period of time that you like to collect data for? Do you like that record to go back 5 years, 10 years, 20 years, or is it all based on the onsite measurements you do using your met mast or LIDAR?

INDREBØ: We haven’t got any thresholds here…it’s “the more, the merrier.” We always try to find what we can, basically.


KELLY: Sonja, how do hurricanes affect the design process?

INDREBØ: Floating wind farms are designed for hurricanes and also 500-year conditions. In addition, we perform robustness checks in the design, and all this is based on requirements and international standards for floating offshore wind. It’s the technical specification, IEC 61400-3-2.


CHEATER: Ultimately, I guess it comes down to a matter of, what is a comfortable position from a business perspective, the degree of assurance versus the cost of implementing the measures. Would that be correct?

INDREBØ: Yes. You could always add more in a lot of areas. It’s finding what is resilient and safe.


CHEATER: Yes, to find that crossing point.



KELLY: Sonja, it’s been observed on real platforms in the Gulf of Mexico that conditions quickly change and sometimes drastically. Brian pointed out that the Chevron Typhoon TLP saw a 180-degree swing in 2-½ hours. How would a turbine react to those kinds of conditions?

INDREBØ: The turbine yaws, so it turns on its own, 360 degrees. So, it can turn quite quickly and it’s not a problem. It doesn’t sound like 180 degrees in 2-½ hours is a problem.


KELLY: Okay. What do you think is the best design philosophy for mooring design? Is it to increase the reliability and robustness of each mooring line and have less of these, or to have more lines for redundancy with perhaps smaller dimensions?

INDREBØ: For Equinor, we design our floating wind farms with three mooring lines and according to the requirements and the standards and with sufficient robustness, and that’s with reference to the standard that we already mentioned. We do believe this is giving the necessary resilience and that it’s safe to do so and that’s where we’re focused.


CHEATER: We ask because this has been a subject of discussion, particularly, in floating wind. It’s focused on the cost of additional mooring lines and anchors versus the degree of assurance you get by adding those extra lines, and there are different camps. Some believe that just a simple three-point mooring system with no redundancy is the way to go, for economic reasons. Other people believe that adding additional lines to provide that degree of assurance is important.

INDREBØ: We are basing our perspective on many years of experience. We also have tension-leg platform structures in our oil and gas portfolio but for us, this is ensuring that we are always operating safely. Even if one of our lines goes, the turbine will be safe. We will probably power it off. So, it’s more about production than it is about any safety issue.


CHEATER: What would be the concerns with the mooring system failing, for example? Would you be concerned about the platform possibly drifting and impacting other platforms? Would that be a major consideration or are there other factors that would play into that?

INDREBØ: I’ve been the plant manager the last three years for our Hywind Scotland, the wind farm off the east coast of Scotland. There, we have used three-line mooring and we do have a GPS on it, so we do have equipment in case it should drift. But it would take, really, three lines, basically breaking up before it starts moving and it would then become like a floating vessel. It was originally dragged across the North Sea when it was put in place. So it can float perfectly well even without the mooring lines in the design we have. There are many considerations involved in making it safe, but also worst-case scenarios are always considered. Our maintenance is, of course, key here and making sure that you’re always on top of that. We do regular ROV inspections of the mooring and ensure that everything is in good order.


Equinor’s Hywind wind farm, off the coast of Scotland. Photo courtesy Signal2Noise.

KELLY: It’s a maturing market, but there’s still room for unexpected development. What are you and your team anticipating as we move forward?

INDREBØ: We believe that what’s necessary is scale, we think there is a lot of room for improvement especially on having large and commercial-sized wind farms. We see that there are more opportunities in the way we’re optimizing the floater. In Equinor, we have two solutions at the moment. We have a spar and then we have a semi-submersible solution, so we believe there are more improvements to be had there. There are technical improvements but, again, on size, we’ve seen cost come down when we have fewer turbines. So, with even bigger wind turbines you need less of them. All of these are very much opportunities that are still to come.


CHEATER: How big do you think these turbines can get?

INDREBØ: That’s a very good question. I’ve been on our six-megawatt turbines, which are the ones with floaters. It’s very impressive when you’re on top of them, how tall they are and how it looks. It doesn’t seem like there has been a limit reached yet. I’ve heard talks about 27-megawatt turbines. That is, of course, enormous, but I think the good thing about the floater is that you will be able to assemble these near shore or at a port, and then you can drag them out. You’re not dependent on any craning happening in the water and that, I guess, is one of the main benefits from its competition with bottom-fixed, where you have to do the in-situ assembly in the water.


CHEATER: Conventional wisdom has always sort of been the transition between bottom fixed and floating wind turbine is somewhere between 60 to 70 meters, somewhere in that range. Do you see floating wind moving into more shallow water?

INDREBØ: The main advantage for bottom-fixed is its simplicity with regards to the monopole, and it’s hard to beat that and come up with solutions that are even better. My belief is that, the more you can use a monopile, that will be the preferred solution. We will use floating where that’s not an option and it becomes more a competition with the jack-up rig type of solution. That’s where the borderline lies. But, of course, with more efficiency in the floaters, you could see it taking a bit more of that in the immediate space but for the time being, we’re looking at 80 meters, mainly.


KELLY: Eighty meters is kind of the changeover depth.

INDREBØ: Yes. Because before that, you could kind of have something that can work on very long thin legs. It depends on the conditions of the seabed, as well—how easy it is to place something on the seabed. I think the exciting piece for floating is that they can go to very large depths. We’re of course looking at California and other areas where there are very deep waters and where floating is an exciting solution for something which is 1,000 meters deep.


CHEATER: The mooring cost will go up with water depth, of course. How do mooring costs scale with water depth? Do they start to dominate at some point?

INDREBØ: Yes. The longer the chains or the fiber ropes are, the more it becomes a part of the bigger picture. We’re looking at innovations and how you could share these…not having just a singular solution but actually working in a mesh and how that can provide similar robustness and resilience but at a lower cost of material. Also, on the Hywind Tampen, which is our floating wind farm that’s currently being built in Norway, is an 88-megawatt wind farm and so it’s got 11 turbines of 8 megawatts each and there, we do share anchors. That had to reduce, of course, that cost as well. So, there are optimizations that can be done by looking at making it easier. The same goes for the substation because, of course, in those kinds of depths, when you have a larger wind farm, you need floating substations. But another possibility is to do what we’ve done in oil and gas, and that is to put the equipment on the seabed, so they’re potential seabed substations.


CHEATER: What kind of anchors are used on Hywind Tampen? Are they drag embedment anchors or piles?

INDREBØ: I’m pretty sure they’re suction anchors. They’re 40, 50 meter-tall type of structures.


CHEATER: You mentioned monopiles earlier. Some of these XXL monopiles are getting massive. I’ve seen monopiles that are, like, 2,500 tons, just for the monopile. As we get into deeper water depths, of course, to maintain the structural strength and the stiffness required, you have to really increase the size of these things. Do you see that being a limitation? Everybody seems to keep busting through the limits…where we thought we were five years ago, they just burst through that and we just keep going up.

INDREBØ: I’m not an expert on structural design, but what I’ve seen is that we tend to find solutions and what we couldn’t really see and envision for this year, in a couple of years, we have found solutions for that. I’m an optimist when it comes to technology and solving for those. But as you say, it’s about optimizing these and finding the threshold where scale doesn’t become the challenge in itself.