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Inside Power Curve Testing with ArcVera Renewables
Allen and Joel discuss power curve testing with John Bosche, co-founder of ArcVera Renewables and member of the IEC technical committee that sets the global 61400-12-1 standard. He breaks down the nitty-gritty details and complex requirements for accurately measuring a wind turbine’s all-important power performance. Visit https://www.arcvera.com/
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Allen Hall: Welcome to the special edition of the Uptime Wind Energy Podcast. I’m your host, Allen Hall, along with co host, Joel Saxum. A wind turbine’s power curve is key to a revenue generating wind farm. We have not discussed power curve measurements on the podcast before, even though we do. Run across them all the time.
And we thought it was due time to bring in an expert. And our guest today is John Bosch, co founder and president of ArcVera Renewables, who represents the U S and as an expert on the IEC tech committee, which maintains the IEC 61400 12 1 standard for power performance testing, John also participates on the IEC.
Tech advisory group that votes on us positions regarding all standards and John has spent a long career in the wind industry. He’s worked in wind since 1990 and. Back in 2001, he founded Chinook Wind up in Washington State, and Chinook merged with VBAR Greg Poulos, in 2017 to form ArcVera Renewables that everybody knows.
John, welcome to the program.
John Bosche: Hey, thanks, Allen. Thanks, Joel. It’s good to be here with you today.
Allen Hall: So we’re trying to understand the power curve. So we talk about it all the time, but we’ve never been involved in a measurement of it. And I know when we travel around and go visit wind sites, everybody just assumes that, Oh, a power curve is this, and there’s a plot and we get it from GE or Vestas, whoever we get it from.
And here’s this magical thing. And all our lives depend on it and that the wind turbines are producing this amount of power with that amount of wind. But how is, I would like to learn, like, how is that created and how is that validated? Because those are two things I just don’t understand yet.
John Bosche: The power curve in some ways really is the most important part of the power curve.
It’s what at ArcVera, we say the arc in arc vera is connecting the meteorology part, which is what Greg does to the the power curve, which turns that meteorology into energy. And and I, not just the power curve, but the machinery in general, so the power curve really is that important bridge of, converting the wind into.
Into energy. It edits. At its heart, it’s a very simple concept. At a given wind speed, there’s a certain amount of power you expect and, at different, at the next higher wind speed, it’s a little more power and up until you hit rated power. It’s, you could say it’s equivalent to the EPA mileage when you buy a car you expect it’s going to get whatever 36 miles to the gallon or something.
And of course then your mileage may vary and there’s never a guarantee or a warranty on the mileage with the car. With wind turbines, you do get a warranty from the turbine vendor. They guarantee the power curve. But in order to enforce that guarantee, you have to actually go measure the power curve.
If you don’t measure it, then it’s just deemed that the wind turbine meets that power curve. And if you’re disappointed later down the road, five years or something. You’re just out of luck because you didn’t measure the power curve. So that’s the reason why companies often often measure, measure, spend the money to measure a power curve.
Joel Saxum: Let’s talk on this one. So now this brings to something to mind and it will show a lot of people something. And this is one I, we talked about with another expert in the field the other day and they said, XYZ turbine company makes like. 200 different variants. When we say a Vesta’s V100, everybody assumes it’s the Vesta’s V100.
However, for different wind resource locations, different blades, so this is why you see different turbines that may be the same model, but they have shorter blades, or longer blades, or different model blade and they’re rated for different wind speeds, but it’s the same nacelle type, but in a different area.
So there, you could have a a GE15, but that GE15 may have. 10 different iterations of it based on, are you in a high wind speed, are you in a low wind speed, are you in turbulent winds, are you this or that and that changes the power curve for every one of those. It would be like you said the car thing, right?
It would be like if you had a certain model of car with a different, different motor in it, or different tires on it, or different arrow on it, or something of that sort. Each one of those, will each one of those sub models have a different type of power curve? And you test against that?
John Bosche: Yes and no. For a given wind turbine model, there’s generally a power curve though there will be multiple power curves for different air densities. There also are different power curves for different operating modes, for example low noise mode, or maybe a load reduction mode.
But those are usually special cases. Generally, for a given turbine model and a given air density, there’s just one, one power curve. The one exception is GE does publish low, medium, and high turbulence power curves. And so you want to make sure you’re using the correct turbulence value in the, in selecting the power curve.
Normally, as you say, if you change the rated power or extend the blades a little bit, that usually results in a new turbine model. That has to be recertified with a new type certificate and a new power curve. For example, the GE, you mentioned the GE 1. 5, it also was available as a GE 1. 6. That was officially a different turbine model than the GE 1. 5. And then it became a GE 1. 7 and, et cetera. And so those are, those iterations are generally considered a new turbine model with some minor variation, you can maybe. have a small change in rated power without requiring a new certification.
One thing that will vary on a wind turbine is maybe the supplier of the blades. So maybe a GE turbine can have TPI blades or LM blades and those blades have different aerodynamic properties. So The turbine actually performs slightly different with those two different blades, but GE doesn’t publish they don’t publish a TPI power curve and an LM power curve, it’s just one power curve.
And that is that is a little sometimes it seems like they, there should maybe be two different power curves, but. They have to, pick a power curve that maybe goes down the middle between those two blades, or hopefully the two blades perform approximately similarly.
Allen Hall: I didn’t know that!
Okay, so that’s fascinating.
Joel Saxum: Okay, so let’s go baseline here. Let’s go I just installed a wind farm. We’ve commissioned date, it’s February 14th, Valentine’s Day 2024. I’m calling you guys to make sure that it’s correct. What is the process? How does it work?
John Bosche: The first thing you have to do is evaluate the terrain.
So if the terrain is flat, and there’s a mathematical description of flat terrain, and it’s way flatter than you would think if you have a little, gully through the site for, rain runoff, that can change it from flat terrain to not flat terrain.
And but you, so there’s a mathematical formula that’s prescribed in the IEC standard. You just evaluate the terrain. If it’s flat terrain then that’s a much simpler procedure. If it’s not flat terrain, if it’s considered complex, you have to actually start maybe six months or a year before the wind turbines ever get installed.
And you install a temporary met tower at the location where the turbine will be and a permanent met tower that’s upwind, a bit upwind of either upwind or off to the side, generally two between two to four rotor diameters away from the turbine location, and you collect data from those two towers for a period of time.
And then you can create kind of wind speed ratios between the Met Tower location and the turbine location. Then when you’ve removed the temporary tower and put the turbine in, you can adjust the wind speed from the permanent tower to reflect the wind speed conditions at the wind turbine location.
So that’s called a site calibration. Once you’ve done the site calibration, or in the case of flat terrain, you don’t have to do a site calibration. So you have this permanent met tower that’s upwind of the turbine again, two to four rotor diameters. And then you collect data from that tower simultaneously with collecting power data from the wind turbine and you’ve been the wind speed and the power data and that do some density corrections and some filtering.
And that creates the power curve. It’s a very simple process except that there are a thousand details that can, that have to be attended to carefully. So The type of anemometer you use is important. It has to be calibrated the, all of the calibration, not only all of the sensors, temperature, pressure, everything have to be calibrated.
Not only calibrated, but they have to be an IEC 17025 calibration, which you don’t always automatically get when you buy sensors. You have to ask for that specifically, and then how they’re actually mounted on the tower their requirements, how long the boom has to be. Diameter of the boom and the, distance of the anemometer from the boom.
The height, the height has to be within plus or minus 2 percent of the hub height and, then same thing with the power measurement equipment, there are requirements for calibration and accuracy of those sensors and so yeah, there’s as I say, there, it’s the reason why there are, there, there’s a standard that’s 300 pages long or whatever it is cause there are a lot of details to attend to.
Joel Saxum: Your use cases for you guys.
Okay. ArcVera gets a phone call. Is it usually always we’re looking to develop this wind farm? Yeah. Can you get involved in that, that basically pre feed stage or what is it? What is your business? What does the business look like when you get engaged from an operator?
John Bosche: Yeah, it can be a, and of course we do much more than just power curve testing.
So often our engagement starts with the wind resource assessment, which might be years before the project gets built. We might work on the independent engineering report for the project. Maybe the project changes hands somewhere along the way, we might do some due diligence. You never know where our involvement picks up.
Sometimes it picks up at the time when the power curve is done. There might be a power curve RFP that’s sent out by a developer, and we respond to that and get selected to do the power curve measurement. It’s a variety of when we get involved.
Joel Saxum: Okay, so the next question I have for you, and this is going in a different direction.
You’re a part of on, you’re on that IEC standard. That has to deal with power curve testing and power curve items in general. I’ve seen power curves used as basically investigative tools for turbine failures, for blade failures, for rotating equipment failures. Do you guys get involved in that side of things and, or have you ever had an operator come to you and say, Hey, we got 100 turbines out here’s a bunch of SCADA data, can you tell us where we can do things to optimize, which ones are not running well, which ones are, is that a thing you guys do too?
John Bosche: Sure, we do that a lot, we’ll do, we call it an operational assessment, so we look at how a wind farm is operating, and all of the, generally when we’re involved in that, it might be a, an underperforming wind farm, so we’ll look at the power curves, we look at all of the individual power curves for, All of the turbines on the site, generally using the cell anemometers looking for kind of outlier turbines, and we can calculate the weight loss for the project and, um.
See if that matches how that matches up with the Pre construction estimate for the weight loss. We can look at, project availability. We can look at electrical losses. There’s. There, there are, a dozen or so different components that may add up to that overall underperformance of the project when it comes to if there are component failures occurring we do that as well.
So that would be a root cause analysis and we we often do we definitely look at SCADA data as part of that root cause analysis, whether we would look at the power curve specifically, maybe we wouldn’t sometimes for example, a loop. A turbine overperforms its power curve.
It’s a, a three megawatt turbine, but it’s producing power up to 3. 3 megawatts or something. So that can add extra loads to the blades and, the yaw system, everything. And so that might, that could be a source of of root cause for the failure. Usually not, but it could be.
We also see that weird things like often wind turbines have wind sector management, so they have to shut down during certain wind conditions when the wind is from a certain direction and a certain wind speed, and those parameters often get entered incorrectly, or perhaps they were originally entered correctly, and then later during maintenance, they get re entered incorrectly, so now the turbine is shutting down From a wind direction that it doesn’t need to shut down, but it doesn’t shut down from the direction it does need to.
And so that first of all hurts production, but also can lead to, a lot of damage from the wake induced turbulence of the neighboring turbines.
Allen Hall: And all these power curve measurements and all the wake measurements, what are we talking about in terms of percentages here? Like, how accurate is the power curve measurement?
Is it plus or minus 1%, 5%? And where does it fit into all the discussion about lost energy?
John Bosche: Probably the 5 percent is pretty close. And it depends on several things, the terrain, how close the Met tower is to the turbine, et cetera. So that range is maybe three to 7 percent for the uncertainty on the overall power curve test.
And one thing that’s interesting most I don’t know if I’d say most, certainly many warranties are written where. The power curve guarantee is the published power curve minus the uncertainty of that test. If there’s say a 5 percent uncertainty, they’re really guaranteeing 95 percent of the power curve.
Many wind farm developers and owners are using this decide not to do a power curve test because it’s pretty unusual to see a wind turbine underperformed by more than 5%. So you might see more commonly, 1 or 2 percent underperformance that doesn’t lead to a warranty claim and they decide, because of this Because of this 5 percent allowance, it’s not worth their money and the effort to test the power curve.
On the other hand, um, sometimes they do underperform by more than 5%. And it’s usually, it’s often, developers who’ve been burned in the past with underperforming turbines that choose to spend the time and effort and money to do the power curve test. The other reason they do it is if generally it’s, it would be the tax equity investors that.
Make, make that a requirement that they have to do a power curve test.
Joel Saxum: Yeah. The financial services sector I see as being something that you could use you guys so much in that, like the due diligence phases. Okay. So let me look at it this way in a different light. If you’re a business investor and you’re going to go buy a business, if you can see that there’s a little bit of degraded performance in the business and immediately see where you could fix it.
And you got numbers on that. That’s a win. That’s a business. I would want to buy a wind farm. I would want to buy. Oh, we can squeeze a little more performance of us because we engage shark bear. They told us what was going on out here. And now if we do a little bit of corrective maintenance and get things moving.
John Bosche: Yeah, leading edge erosion is a huge issue.
It can definitely degrade, the performance by. By many percent, in, in severe cases, I don’t know more than 10 percent reduction in performance. And okay. That needs to be taken care of on a regular basis and I’d say it’s a, it’s an, generally it’s an investment that’s well worth spending to keep the production up.
Joel Saxum: John, what is your opinion, then, being a power curve expert, on some of the solutions in, out in the wild, out in the wind industry market, of erosion and telling people what their AEP performance loss is?
John Bosche: You can measure directly the power curve and determine how much, it’s been degraded from so that’s one of the benefits of doing a baseline power curve test.
When the project is new, then you can remeasure down the road to look for degradation. You can also do actually more accurate than doing that is do a side by side. Repair the leading edges on one turbine and don’t repair the leading edges on the neighboring turbine and see how much the relative difference in performance.
That’s probably the best way to, to evaluate changes, whether it’s from vortex generators, leading edge repairs any other kind of, blade upgrades. But the other thing with leading edge erosion is not only does it degrade performance, but it also degrades the structural reliability of the blade.
And eventually, if it gets bad enough, moisture can ingress into the blades and That that creates its own problems when it freezes also potentially creates lightning, lightning issues when there’s extra moisture inside of the blade. There’s, there are a lot of good just reasons for the structural health of the blades to keep the leading edges repaired.
Joel Saxum: One of the things we always talk about leading edges go bad, aerodynamic performance suffers, creates tip, creates vortices and dirty air behind it. It’s bad for lightning as well. So like leading edge erosion is something that the world definitely needs to be TA taken care of.
John Bosche: Yeah, leading edge erosion is a whole separate topic. I’d love to talk, I can talk for hours about that, but there’s even what causes leading edge erosion is really, an interesting topic of ongoing research and it’s a, it’s really a fascinating topic, actually, in the old days, when wind farms were mostly in Palm Springs and in the ultimate past.
We thought it was blowing sand that caused the leading edge erosion. Now, it turns out it’s more, it’s water droplets actually that causes it.
Allen Hall: I was just over at the leading edge erosion conference last week at and yeah, it’s this huge topic and it all revolves around power loss and what that power loss isn’t.
I know that’s one of the questions that was a big discussion point. In fact, we spent about an hour in discussion about what is the likely losses there and what kind of range are we talking about? And I think one of the problems is that we don’t go out and really measure it. And I’m not sure why that is, but it does seem like measuring the power curve or doing side by side measurements would be a really good solution to it, to quantify it because different parts of the world have different levels of erosion and different effects.
What, how long does it usually take to do that, to do the side by side or to do a power curve measurement? Was it a six month process, a year process, a two year process to really get fine enough data?
John Bosche: In that case, you’re not doing an IEC standard power curve test. You’re doing maybe more of an informal power curve test.
And you can take as long, as little, as much or little time as you want, really. I, if you have, if you do it during the, a good wind sea, high wind season, Probably a month is enough time for collecting data to really do a, if you’re doing, for example, a side by side test during the wind season a month, I would say would be long enough.
If you really want to, fill all of the wind speed bins for the IEC standard, you probably need to allow for 3, 3 months or 4 months But but for these informal tests, you don’t, you’re not required to fill all of the bins and meet all of the IEC requirements.
Allen Hall: What’s the error bars on those kind of tests?
Because I hear the side by side tests of just from power curve discussions and adding a VG or something of that sort to blades and they try to do side by side. Using SCADA data, really rough data. It doesn’t seem it’s all that accurate. If you’re looking for a percent or two, those, isn’t that sort of hard to find?
And do you need to do an IEC type of measurement to really get the resolution that you need to determine if that condition works?
John Bosche: Yeah. And something like evaluating VGs, again, you’re, the good thing is you’re not going for absolute accuracy. Let’s say the test is off by 3%. If it’s off by the same 3 percent before and after, then you don’t really care that much.
What you’re looking for is a relative change in performance after the bleed improvements are made.
Allen Hall: And there must be a lot of discussion at the IEC level about. These measurements, this is all about money at the end of the day and generating power. Is there a lot of discussion at the IEC committee at the moment?
And I know there’s a new revision issued about a year or so ago. What’s, where’s the IEC committee and what’s the next steps there?
John Bosche: The most recent substantive update of the IEC -12-1 was in 2017. The 2022 document, which is edition three. Doesn’t really change and change it in a substantive way.
It really just reorganizes the document and it has to do with all of the details of how you measure the wind historically have lived in that dash 12 dash 1 document. And so now there are many other standards dash 15, for example, needs to refer to wind measurements. Even, the acoustics measurements or loads measurements standards need to refer to how to measure the wind.
So instead of those standards, all referring to dash 12 dash one, that’s been pulled out, it’s in 50 dash one now. And it really is just pulling some of those details out. Into standalone documents.
Allen Hall: Yeah, we’re getting finer and finer on the measurements and there’s more and more measurements to make.
You mentioned acoustics and I was thinking the same thing. Acoustic seems to be a big player at the moment. We were just talking to an operator, an offshore wind farm. We had acoustic treatments offshore, which sounded weird. Like, why would the ocean care what the noise is? But. Yeah, there’s a lot of work going on at Acoustics.
Joel Saxum: The fishermen like to fish in peace.
Allen Hall: Clearly they do. And that’s part of that IEC spec though, like trying to standardize all these measurements is, must be, you guys must meet what, once or twice a year to, to go over these discussions.
John Bosche: Generally, IEC standards go through what’s called maintenance cycles in which, they’re updated, say from.
Version 1, Edition 1 to Edition 2, and those those update cycles can last anywhere from a year to sometimes 7 years it just depends how complicated it is and how extensive when a maintenance cycle is active, the group probably generally meets several times a year, maybe 3 4 times a year, and then in between, like right now on the -12-1, we haven’t been meeting regularly since 2017.
And we’re just about to embark on a new we have embarked now on a new maintenance cycle. So for the next couple of years, we’ll meet quarterly and and address kind of the, changes in the state of the art of how you would do power curve measurements.
Allen Hall: And What’s the latest in the state of the art?
John Bosche: So LIDAR was addressed in addition to, for ground mounted LIDAR. And then actually more recently, there was a dash 50 dash three standard. That addresses nacelle mounted LiDAR and I was also involved in that effort, and it’s actually, at the moment, it can only be used in flat terrain, again, as defined by this set of equations in the IEC standard, but it really, it, it does away with the need for a MET tower, and I think, and it seems to be quite accurate, so it’s I think it’s It’s an exciting new advancement for our industry.
Allen Hall: Yeah, we’ve seen a lot more action on the Nacelle metal lidars. And just curious where the direction was there, because it does seem like an advancement and just haven’t seen it implemented all that much.
John Bosche: An interesting thing that we’ve seen on a bunch of different power curves we’ve done at different sites and different turbine models is that despite the fact that, following the IEC standard, we adjust for air density and even can adjust for Wind shear and turbulence.
Even with those adjustments, we’ll see sometimes a very big difference in the power curve from summer to winter, sometimes 5 or 10 percent from summertime to winter time. And so it’s something for, project owners and developers to be aware of is. Actually, when you measure the curve, power curve matters as much, if not more than, the details of the measurement.
If you measure if you measure in the summer, you’re going to get a worse looking power curve. If you measure in the winter, you’re going to get a good looking power curve. There can be sometimes a game played, between the turbine vendor and the and the project owner as to when you start the test.
Joel Saxum: Yeah, it makes sense to me based on the flexibility of the blades. You’re losing power when blades flex.
Allen Hall: And the air is denser, right?
John Bosche: That’s right. The density, yeah, I hadn’t thought about the stiffness aspect. That could be a good area to investigate. My best theory is that in the summer when the air density is lower, that affects the Reynolds number of the wind flow over the blades.
And lower Reynolds number brings you closer to a stall condition. Blades often are operating near or even in stall near the root of the blade. And so it’s just a question of how much of the blade root is in a stall condition. And maybe in the summer, there’s a little bit more of the blade that’s in a stalled condition and affects the performance.
That’s my best theory.
Allen Hall: Yeah. It’s something as an operator, you wouldn’t think about all that much, but you’re right, John. That’s totally part of the power curve is right temperature, density, and as Joel pointed out, things about the turbine itself, right? We’ll make a difference in the power curve.
So it does matter. And I know there’s a lot of discussion in the industry about trying to maximize power curve and get the energy up and do all those great things. And this is why people need to call ArcVera right? They need to get ahold of you to ask these questions, to get some answers, need an expert.
John Bosche: But importantly, if the power curve is measured for sort of these winter ideal conditions, and you measure the power curve in the winter, you think everything’s fine, but half of the year, it’s the turbine could be significantly underperforming. If you didn’t account for that in the pre construction energy estimate.
Then then you can get significant underperformance just because of this seasonal variation in the power curve. And so it’s worth thinking about. And and for us, for we consultants who do the pre construction energy estimates it’s something for us to consider in our calculations.
Allen Hall: Yeah, absolutely. So how do people find out about ArcVera? How do they get ahold of you, John? Because you’re a wealth of knowledge here. Where do they go?
John Bosche: Well, arcvera.com is our website. It has lots of information and bios and white papers. And we publish monthly anomaly maps for for how, whether the wind is higher than average or lower than average for the, all of the U S and Brazil, South Africa, and India, which are other countries that we operate in.
A lot of our clients find those to be quite interesting. And if anyone wants to reach out to me, my email addresses. john.bosche@arcvera.com.
Allen Hall: John, it’s been great to have you on the program, and we need to have you back. Thanks, guys.
John Bosche: It’s been a pleasure.
Allen Hall: We’ll see you at some of the conferences coming up.
John Bosche: I’m looking forward to it.
https://weatherguardwind.com/inside-power-curve-testing-arcvera-renewables/
Wind Industry Operations: In Wind’s Next Chapter, Operations take center stage
This exclusive article originally appeared in PES Wind 4 – 2025 with the title, Operations take center stage in wind’s next chapter. It was written by Allen Hall and other members of the WeatherGuard Lightning Tech team.
As aging fleets, shrinking margins, and new policies reshape the wind sector, wind energy operations are in the spotlight. The industry’s next chapter will be defined not by capacity growth, but by operational excellence, where integrated, predictive maintenance turns data into decisions and reliability into profit.
Wind farm operations are undergoing a fundamental transformation. After hosting hundreds of conversations on the Uptime Wind Energy Podcast, I’ve witnessed a clear pattern: the most successful operators are abandoning reactive maintenance in favor of integrated, predictive strategies. This shift isn’t just about adopting new technologies; it’s about fundamentally rethinking how we manage aging assets in an era of tightening margins and expanding responsibilities.
The evidence was overwhelming at this year’s SkySpecs Customer Forum, where representatives from over 75% of US installed wind capacity gathered to share experiences and strategies. The consensus was clear: those who integrate monitoring, inspection, and repair into a cohesive operational strategy are achieving dramatic improvements in reliability and profitability.
Takeaway: These options have been available to wind energy operations for years; now, adoption is critical.
Why traditional approaches to wind farm operations are failing
Today’s wind operators face an unprecedented convergence of challenges. Fleets installed during the 2010-2015 boom are aging in unexpected ways, revealing design vulnerabilities no one anticipated. Meanwhile, the support infrastructure is crumbling; spare parts have become scarce, OEM support is limited, and insurance companies are tightening coverage just when operators need them most.
The situation is particularly acute following recent policy changes. The One Big Beautiful Bill in the United States has fundamentally altered the economic landscape. PTC farming is no longer viable; turbines must run longer and more reliably than ever before. Engineering teams, already stretched thin, are being asked to manage not just wind assets but solar and battery storage as well. The old playbook simply doesn’t work anymore.
Consider the scope of just one challenge: polyester blade failures. During our podcast conversation with Edo Kuipers of We4Ce, we learned that an estimated 30,000 to 40,000 blades worldwide are experiencing root bushing issues. ‘After a while, blades are simply flying off,’ Kuipers explained. The financial impact of a single blade failure can exceed €300,000 when you factor in replacement costs, lost production, and crane mobilization. Yet innovative repair solutions, like the one developed by We4Ce and CNC Onsite, can address the same problem for €40,000 if caught early. This pattern repeats across every major component. Gearbox failures that once required complete replacement can now be predicted months in advance. Lightning damage that previously caused catastrophic failures can be prevented with inexpensive upgrades and real-time monitoring. All these solutions are based on the principle that predicted maintenance is better than an expensive surprise.
Seeing problems before they happeny, and potential risks
The transformation begins with visibility. Modern monitoring systems reveal problems that traditional methods miss entirely. Eric van Genuchten of Sensing360 shared an eye-opening statistic on our podcast: ‘In planetary gearbox failures, they get 90%, so there’s still 10% of failures they cannot detect.’ That missing 10% represents the catastrophic failures that destroy budgets and production targets. Advanced monitoring technologies are filling these gaps. Sensing360’s fiber optic sensors, for example, detect minute deformations in steel components, revealing load imbalances and fatigue progression invisible to traditional monitoring. ‘We integrate our sensors in steel and make rotating equipment smarter,’ van Genuchten explained.
Other companies are deploying acoustic systems to identify blade delamination, oil analysis for gearbox health, and electrical signature analysis for generator issues. Each technology adds a piece to the puzzle, but the real value comes from integration. The impact of load monitoring alone can be transformative.
As van Genuchten explained, ‘Twenty percent more loading on a gearbox or on a bearing is half of your life. The other way around, twenty percent less loading is double your life.’ With proper monitoring, operators can optimize load distribution across their fleet, extending component life while maximizing production.
But monitoring without action is just expensive data collection. The most successful operators are those who’ve learned to translate sensor data into operational decisions. This requires not just technology but organizational change, breaking down silos between monitoring, maintenance, and management teams.
In Wind Energy Operations, Early intervention makes the million-dollar difference
The economics of early intervention are compelling across every component type. The blade root bushing example from We4Ce illustrates this perfectly. With their solution, early detection means replacing just 24-30 bushings in about 24 hours of drilling work. Wait, and you’re looking at 60+ bushings and 60 hours of work. Early detection doesn’t just prevent catastrophic failure; it makes repairs faster, cheaper, and more reliable.
This principle extends throughout the turbine. Early-stage bearing damage can be addressed through targeted lubrication or minor adjustments. Incipient electrical issues can be resolved with cleaning or connection tightening. Small blade surface cracks can be repaired in a few hours before they propagate into structural damage requiring weeks of work.
Leading operators are implementing tiered response protocols based on monitoring data. Critical issues trigger immediate intervention. Developing problems are scheduled for the next maintenance window. Minor issues are monitored and addressed during routine service. This systematic approach reduces both emergency repairs and unnecessary maintenance, optimizing resource allocation across the fleet.
Turning information into action
While monitoring generates data, platforms like SkySpecs’ Horizon transform that data into operational intelligence. Josh Goryl, SkySpecs’ Chief Revenue Officer, explained their evolution at the recent Customer Forum: ‘I think where we can help our customers is getting all that data into one place.
The game-changer is integration across data types. The company is working to combine performance data with CMS data to provide valuable insights into turbine health. This approach has been informed by operators across the world, who’ve discovered that integrated platforms deliver insights that siloed data can’t.
The platform approach also addresses the reality of shrinking engineering teams managing expanding portfolios. As Goryl noted, many wind engineers are now responsible for solar and battery storage assets as well. One platform managing multiple technologies through a unified interface becomes essential for operational efficiency.
The Integration Imperative for Wind Farm Operations
The most successful operators aren’t just adopting individual technologies; they’re integrating monitoring, inspection, and repair into a seamless operational system. This integration operates at multiple levels.
At the technical level, data from various monitoring systems feeds into unified platforms that provide comprehensive asset visibility. These platforms don’t just display data; they analyze patterns, predict failures, and generate work orders.
At the organizational level, integration means breaking down barriers between departments. This cross-functional collaboration transforms O&M from a cost center into a value driver. Building your improvement roadmap For operators ready to enhance their O&M approach, the path forward involves several key steps:
Assessing the Current State of your Wind Energy Operations
Document your maintenance costs, failure rates, and downtime patterns. Identify which problems consume the most resources and which assets are most critical to your wind farm operations.
Start with targeted pilots Rather than attempting wholesale transformation, begin with focused initiatives targeting your biggest pain points. Whether it’s blade monitoring, gearbox sensors, or repair innovations, starting with your largest issue will help you see the biggest benefit.
• Invest in integration, not just technology: the most sophisticated monitoring system is worthless if its data isn’t acted upon. Ensure your organization has the processes and culture to transform data into decisions – this is the first step to profitability in your wind farm operations.
Build partnerships, not just contracts: look for technology providers and service companies willing to share knowledge, not just deliver services. The goal is building capability, not dependency.
• Measure and iterate: track the impact of each initiative on your key performance indicators. Use lessons learned to refine your approach and guide future investments.
The competitive advantage
The wind industry has reached an inflection point. With increasingly large and complex turbines, monitoring needs to adapt with it. The era of flying blind is over.
In an industry where margins continue to compress and competition intensifies, operational excellence has become a key differentiator. Those who master the integration of monitoring, inspection, and repair will thrive. Those who cling to reactive maintenance face escalating costs and declining competitiveness.
The technology exists. The business case is proven. The early adopters are already reaping the benefits. The question isn’t whether to transform your O&M approach, but how quickly you can adapt to this new reality. In the race to operational excellence, the winners will be those who act decisively to embrace the efficiency revolution reshaping wind operations.
Unless otherwise noted, images here are from We4C Rotorblade Specialist.
Contact us for help understanding your lightning damage, future risks, and how to get more uptime from your equipment.
Download the full article from PES Wind here
Find a practical guide to solving lightning problems and filing better insurance claims here
Wind Industry Operations: In Wind’s Next Chapter, Operations take center stage
Weather Guard Lightning Tech
BladeBUG Tackles Serial Blade Defects with Robotics
Chris Cieslak, CEO of BladeBug, joins the show to discuss how their walking robot is making ultrasonic blade inspections faster and more accessible. They cover new horizontal scanning capabilities for lay down yards, blade root inspections for bushing defects, and plans to expand into North America in 2026.
Sign up now for Uptime Tech News, our weekly newsletter on all things wind technology. This episode is sponsored by Weather Guard Lightning Tech. Learn more about Weather Guard’s StrikeTape Wind Turbine LPS retrofit. Follow the show on YouTube, Linkedin and visit Weather Guard on the web. And subscribe to Rosemary’s “Engineering with Rosie” YouTube channel here. Have a question we can answer on the show? Email us!
Welcome to Uptime Spotlight, shining Light on Wind. Energy’s brightest innovators. This is the Progress Powering Tomorrow.
Allen Hall: Chris, welcome back to the show.
Chris Cieslak: It’s great to be back. Thank you very much for having me on again.
Allen Hall: It’s great to see you in person, and a lot has been happening at Blade Bugs since the last time I saw Blade Bug in person. Yeah, the robot. It looks a lot different and it has really new capabilities.
Chris Cieslak: So we’ve continued to develop our ultrasonic, non-destructive testing capabilities of the blade bug robot.
Um, but what we’ve now added to its capabilities is to do horizontal blade scans as well. So we’re able to do blades that are in lay down yards or blades that have come down for inspections as well as up tower. So we can do up tower, down tower inspections. We’re trying to capture. I guess the opportunity to inspect blades after transportation when they get delivered to site, to look [00:01:00] for any transport damage or anything that might have been missed in the factory inspections.
And then we can do subsequent installation inspections as well to make sure there’s no mishandling damage on those blades. So yeah, we’ve been just refining what we can do with the NDT side of things and improving its capabilities
Joel Saxum: was that need driven from like market response and people say, Hey, we need, we need.
We like the blade blood product. We like what you’re doing, but we need it here. Or do you guys just say like, Hey, this is the next, this is the next thing we can do. Why not?
Chris Cieslak: It was very much market response. We had a lot of inquiries this year from, um, OEMs, blade manufacturers across the board with issues within their blades that need to be inspected on the ground, up the tap, any which way they can.
There there was no, um, rhyme or reason, which was better, but the fact that he wanted to improve the ability of it horizontally has led the. Sort of modifications that you’ve seen and now we’re doing like down tower, right? Blade scans. Yeah. A really fast breed. So
Joel Saxum: I think the, the important thing there is too is that because of the way the robot is built [00:02:00] now, when you see NDT in a factory, it’s this robot rolls along this perfectly flat concrete floor and it does this and it does that.
But the way the robot is built, if a blade is sitting in a chair trailing edge up, or if it’s flap wise, any which way the robot can adapt to, right? And the idea is. We, we looked at it today and kind of the new cage and the new things you have around it with all the different encoders and for the heads and everything is you can collect data however is needed.
If it’s rasterized, if there’s a vector, if there’s a line, if we go down a bond line, if we need to scan a two foot wide path down the middle of the top of the spa cap, we can do all those different things and all kinds of orientations. That’s a fantastic capability.
Chris Cieslak: Yeah, absolutely. And it, that’s again for the market needs.
So we are able to scan maybe a meter wide in one sort of cord wise. Pass of that probe whilst walking in the span-wise direction. So we’re able to do that raster scan at various spacing. So if you’ve got a defect that you wanna find that maximum 20 mil, we’ll just have a 20 mil step [00:03:00] size between each scan.
If you’ve got a bigger tolerance, we can have 50 mil, a hundred mil it, it’s so tuneable and it removes any of the variability that you get from a human to human operator doing that scanning. And this is all about. Repeatable, consistent high quality data that you can then use to make real informed decisions about the state of those blades and act upon it.
So this is not about, um, an alternative to humans. It’s just a better, it’s just an evolution of how humans do it. We can just do it really quick and it’s probably, we, we say it’s like six times faster than a human, but actually we’re 10 times faster. We don’t need to do any of the mapping out of the blade, but it’s all encoded all that data.
We know where the robot is as we walk. That’s all captured. And then you end up with really. Consistent data. It doesn’t matter who’s operating a robot, the robot will have those settings preset and you just walk down the blade, get that data, and then our subject matter experts, they’re offline, you know, they are in their offices, warm, cozy offices, reviewing data from multiple sources of robots.
And it’s about, you know, improving that [00:04:00] efficiency of getting that report out to the customer and letting ’em know what’s wrong with their blades, actually,
Allen Hall: because that’s always been the drawback of, with NDT. Is that I think the engineers have always wanted to go do it. There’s been crush core transportation damage, which is sometimes hard to see.
You can maybe see a little bit of a wobble on the blade service, but you’re not sure what’s underneath. Bond line’s always an issue for engineering, but the cost to take a person, fly them out to look at a spot on a blade is really expensive, especially someone who is qualified. Yeah, so the, the difference now with play bug is you can have the technology to do the scan.
Much faster and do a lot of blades, which is what the de market demand is right now to do a lot of blades simultaneously and get the same level of data by the review, by the same expert just sitting somewhere else.
Chris Cieslak: Absolutely.
Joel Saxum: I think that the quality of data is a, it’s something to touch on here because when you send someone out to the field, it’s like if, if, if I go, if I go to the wall here and you go to the wall here and we both take a paintbrush, we paint a little bit [00:05:00] different, you’re probably gonna be better.
You’re gonna be able to reach higher spots than I can.
Allen Hall: This is true.
Joel Saxum: That’s true. It’s the same thing with like an NDT process. Now you’re taking the variability of the technician out of it as well. So the data quality collection at the source, that’s what played bug ducts.
Allen Hall: Yeah,
Joel Saxum: that’s the robotic processes.
That is making sure that if I scan this, whatever it may be, LM 48.7 and I do another one and another one and another one, I’m gonna get a consistent set of quality data and then it’s goes to analysis. We can make real decisions off.
Allen Hall: Well, I, I think in today’s world now, especially with transportation damage and warranties, that they’re trying to pick up a lot of things at two years in that they could have picked up free installation.
Yeah. Or lifting of the blades. That world is changing very rapidly. I think a lot of operators are getting smarter about this, but they haven’t thought about where do we go find the tool.
Speaker: Yeah.
Allen Hall: And, and I know Joel knows that, Hey, it, it’s Chris at Blade Bug. You need to call him and get to the technology.
But I think for a lot of [00:06:00] operators around the world, they haven’t thought about the cost They’re paying the warranty costs, they’re paying the insurance costs they’re paying because they don’t have the set of data. And it’s not tremendously expensive to go do. But now the capability is here. What is the market saying?
Is it, is it coming back to you now and saying, okay, let’s go. We gotta, we gotta mobilize. We need 10 of these blade bugs out here to go, go take a scan. Where, where, where are we at today?
Chris Cieslak: We’ve hads. Validation this year that this is needed. And it’s a case of we just need to be around for when they come back round for that because the, the issues that we’re looking for, you know, it solves the problem of these new big 80 a hundred meter plus blades that have issues, which shouldn’t.
Frankly exist like process manufacturer issues, but they are there. They need to be investigated. If you’re an asset only, you wanna know that. Do I have a blade that’s likely to fail compared to one which is, which is okay? And sort of focus on that and not essentially remove any uncertainty or worry that you have about your assets.
’cause you can see other [00:07:00] turbine blades falling. Um, so we are trying to solve that problem. But at the same time, end of warranty claims, if you’re gonna be taken over these blades and doing the maintenance yourself, you wanna know that what you are being given. It hasn’t gotten any nasties lurking inside that’s gonna bite you.
Joel Saxum: Yeah.
Chris Cieslak: Very expensively in a few years down the line. And so you wanna be able to, you know, tick a box, go, actually these are fine. Well actually these are problems. I, you need to give me some money so I can perform remedial work on these blades. And then you end of life, you know, how hard have they lived?
Can you do an assessment to go, actually you can sweat these assets for longer. So we, we kind of see ourselves being, you know, useful right now for the new blades, but actually throughout the value chain of a life of a blade. People need to start seeing that NDT ultrasonic being one of them. We are working on other forms of NDT as well, but there are ways of using it to just really remove a lot of uncertainty and potential risk for that.
You’re gonna end up paying through the, you know, through the, the roof wall because you’ve underestimated something or you’ve missed something, which you could have captured with a, with a quick inspection.
Joel Saxum: To [00:08:00] me, NDT has been floating around there, but it just hasn’t been as accessible or easy. The knowledge hasn’t been there about it, but the what it can do for an operator.
In de-risking their fleet is amazing. They just need to understand it and know it. But you guys with the robotic technology to me, are bringing NDT to the masses
Chris Cieslak: Yeah.
Joel Saxum: In a way that hasn’t been able to be done, done before
Chris Cieslak: that. And that that’s, we, we are trying to really just be able to roll it out at a way that you’re not limited to those limited experts in the composite NDT world.
So we wanna work with them, with the C-N-C-C-I-C NDTs of this world because they are the expertise in composite. So being able to interpret those, those scams. Is not a quick thing to become proficient at. So we are like, okay, let’s work with these people, but let’s give them the best quality data, consistent data that we possibly can and let’s remove those barriers of those limited people so we can roll it out to the masses.
Yeah, and we are that sort of next level of information where it isn’t just seen as like a nice to have, it’s like an essential to have, but just how [00:09:00] we see it now. It’s not NDT is no longer like, it’s the last thing that we would look at. It should be just part of the drones. It should inspection, be part of the internal crawlers regimes.
Yeah, it’s just part of it. ’cause there isn’t one type of inspection that ticks all the boxes. There isn’t silver bullet of NDT. And so it’s just making sure that you use the right system for the right inspection type. And so it’s complementary to drones, it’s complimentary to the internal drones, uh, crawlers.
It’s just the next level to give you certainty. Remove any, you know, if you see something indicated on a a on a photograph. That doesn’t tell you the true picture of what’s going on with the structure. So this is really about, okay, I’ve got an indication of something there. Let’s find out what that really is.
And then with that information you can go, right, I know a repair schedule is gonna take this long. The downtime of that turbine’s gonna be this long and you can plan it in. ’cause everyone’s already got limited budgets, which I think why NDT hasn’t taken off as it should have done because nobody’s got money for more inspections.
Right. Even though there is a money saving to be had long term, everyone is fighting [00:10:00] fires and you know, they’ve really got a limited inspection budget. Drone prices or drone inspections have come down. It’s sort, sort of rise to the bottom. But with that next value add to really add certainty to what you’re trying to inspect without, you know, you go to do a day repair and it ends up being three months or something like, well
Allen Hall: that’s the lightning,
Joel Saxum: right?
Allen Hall: Yeah. Lightning is the, the one case where every time you start to scarf. The exterior of the blade, you’re not sure how deep that’s going and how expensive it is. Yeah, and it always amazes me when we talk to a customer and they’re started like, well, you know, it’s gonna be a foot wide scarf, and now we’re into 10 meters and now we’re on the inside.
Yeah. And the outside. Why did you not do an NDT? It seems like money well spent Yeah. To do, especially if you have a, a quantity of them. And I think the quantity is a key now because in the US there’s 75,000 turbines worldwide, several hundred thousand turbines. The number of turbines is there. The number of problems is there.
It makes more financial sense today than ever because drone [00:11:00]information has come down on cost. And the internal rovers though expensive has also come down on cost. NDT has also come down where it’s now available to the masses. Yeah. But it has been such a mental barrier. That barrier has to go away. If we’re going going to keep blades in operation for 25, 30 years, I
Joel Saxum: mean, we’re seeing no
Allen Hall: way you can do it
Joel Saxum: otherwise.
We’re seeing serial defects. But the only way that you can inspect and or control them is with NDT now.
Allen Hall: Sure.
Joel Saxum: And if we would’ve been on this years ago, we wouldn’t have so many, what is our term? Blade liberations liberating
Chris Cieslak: blades.
Joel Saxum: Right, right.
Allen Hall: What about blade route? Can the robot get around the blade route and see for the bushings and the insert issues?
Chris Cieslak: Yeah, so the robot can, we can walk circumferentially around that blade route and we can look for issues which are affecting thousands of blades. Especially in North America. Yeah.
Allen Hall: Oh yeah.
Chris Cieslak: So that is an area that is. You know, we are lucky that we’ve got, um, a warehouse full of blade samples or route down to tip, and we were able to sort of calibrate, verify, prove everything in our facility to [00:12:00] then take out to the field because that is just, you know, NDT of bushings is great, whether it’s ultrasonic or whether we’re using like CMS, uh, type systems as well.
But we can really just say, okay, this is the area where the problem is. This needs to be resolved. And then, you know, we go to some of the companies that can resolve those issues with it. And this is really about played by being part of a group of technologies working together to give overall solutions
Allen Hall: because the robot’s not that big.
It could be taken up tower relatively easily, put on the root of the blade, told to walk around it. You gotta scan now, you know. It’s a lot easier than trying to put a technician on ropes out there for sure.
Chris Cieslak: Yeah.
Allen Hall: And the speed up it.
Joel Saxum: So let’s talk about execution then for a second. When that goes to the field from you, someone says, Chris needs some help, what does it look like?
How does it work?
Chris Cieslak: Once we get a call out, um, we’ll do a site assessment. We’ve got all our rams, everything in place. You know, we’ve been on turbines. We know the process of getting out there. We’re all GWO qualified and go to site and do their work. Um, for us, we can [00:13:00] turn up on site, unload the van, the robot is on a blade in less than an hour.
Ready to inspect? Yep. Typically half an hour. You know, if we’ve been on that same turbine a number of times, it’s somewhere just like clockwork. You know, muscle memory comes in, you’ve got all those processes down, um, and then it’s just scanning. Our robot operator just presses a button and we just watch it perform scans.
And as I said, you know, we are not necessarily the NDT experts. We obviously are very mindful of NDT and know what scans look like. But if there’s any issues, we have a styling, we dial in remote to our supplement expert, they can actually remotely take control, change the settings, parameters.
Allen Hall: Wow.
Chris Cieslak: And so they’re virtually present and that’s one of the beauties, you know, you don’t need to have people on site.
You can have our general, um, robot techs to do the work, but you still have that comfort of knowing that the data is being overlooked if need be by those experts.
Joel Saxum: The next level, um, commercial evolution would be being able to lease the kit to someone and or have ISPs do it for [00:14:00] you guys kinda globally, or what is the thought
Chris Cieslak: there?
Absolutely. So. Yeah, so we to, to really roll this out, we just wanna have people operate in the robots as if it’s like a drone. So drone inspection companies are a classic company that we see perfectly aligned with. You’ve got the sky specs of this world, you know, you’ve got drone operator, they do a scan, they can find something, put the robot up there and get that next level of information always straight away and feed that into their systems to give that insight into that customer.
Um, you know, be it an OEM who’s got a small service team, they can all be trained up. You’ve got general turbine technicians. They’ve all got G We working at height. That’s all you need to operate the bay by road, but you don’t need to have the RAA level qualified people, which are in short supply anyway.
Let them do the jobs that we are not gonna solve. They can do the big repairs we are taking away, you know, another problem for them, but giving them insights that make their job easier and more successful by removing any of those surprises when they’re gonna do that work.
Allen Hall: So what’s the plans for 2026 then?
Chris Cieslak: 2026 for us is to pick up where 2025 should have ended. [00:15:00] So we were, we were meant to be in the States. Yeah. On some projects that got postponed until 26. So it’s really, for us North America is, um, what we’re really, as you said, there’s seven, 5,000 turbines there, but there’s also a lot of, um, turbines with known issues that we can help determine which blades are affected.
And that involves blades on the ground, that involves blades, uh, that are flying. So. For us, we wanna get out to the states as soon as possible, so we’re working with some of the OEMs and, and essentially some of the asset owners.
Allen Hall: Chris, it’s so great to meet you in person and talk about the latest that’s happening.
Thank you. With Blade Bug, if people need to get ahold of you or Blade Bug, how do they do that?
Chris Cieslak: I, I would say LinkedIn is probably the best place to find myself and also Blade Bug and contact us, um, through that.
Allen Hall: Alright, great. Thanks Chris for joining us and we will see you at the next. So hopefully in America, come to America sometime.
We’d love to see you there.
Chris Cieslak: Thank you very [00:16:00] much.
Hillsdale College is a rightwing Christian extremist organization that ostensibly honors the United States Constitution.
Here’s their quiz, which should be called the “Constitutional Trivia Quiz.”, whose purpose is obviously to convince Americans of their ignorance.
When I teach, I’m going for understanding of the topic, not the memorization of useless information.
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