Published

2 years ago

March 7, 2024

Alice Rush

Weather Guard Lightning Tech

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/

Sign up now for Uptime Tech News, our weekly email update 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 Facebook, YouTube, Twitter, Linkedin and visit Weather Guard on the web. And subscribe to Rosemary Barnes’ YouTube channel here. Have a question we can answer on the show? Email us!

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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/

Renewable Energy

MotorDoc Finds Bearing and Gearbox Faults in Minutes

Published

13 hours ago

May 21, 2026

Alice Rush

Weather Guard Lightning Tech

MotorDoc Finds Bearing and Gearbox Faults in Minutes

Howard Penrose of MotorDoc joins to discuss current signature analysis, uptower circulating currents wrecking main bearings, and full drivetrain scans in minutes. Reach out at info@motordoc.com or on LinkedIn.

Howard Penrose: [00:00:00] Welcome to Uptime Spotlight, shining light on wind energy’s brightest innovators. This is the progress powering tomorrow.

Allen Hall: Howard, welcome back to the program.

Howard Penrose: Hey, thanks for having me.

Allen Hall: It’s about time everybody realizes what motorDoc can do. There’s so much technology, and I’ve been watching- Yeah … your Chaos and Caffeine podcast on Saturday morning, which are full of really, really good information about the motorDoc as a company, all the things you’re doing out in the field, and how you’re solving real-world problems, not imaginary ones- Yeah

real-world problems. Oh, yeah. Yeah, and

Howard Penrose: whatever annoys me that week. Exactly. And, and whatever great coffee I’m trying out. Yes. Except for a few. We’ve had the ReliaSquatch down our- Yes … um, a couple of times. Uh, yeah, no, I, I enjoy it, and we gotta get you on there sometime. I don’t do- I, it- … a lot of interviews other than an AI character we put in.

Allen Hall: It’s a very interesting show because you’re [00:01:00] getting a little bit of comedy and humor and s- Yeah … and a, and a coffee review, which is very helpful because I’ve tried some of the coffees that you have reviewed, that you’ve given the thumbs up to. But if you’re operating wind turbines and you’re trying to understand what’s happening on the drivetrain side, on the generator, everything out to the blades even, main bearings, gearboxes- Yeah

all those rotating heavy, expensive parts, there’s a lot of ways to diagnose them-

Howard Penrose: Yes …

Allen Hall: that are sort of like we can look at a gear, we can look at a joint, we can look at roller bearings, whatever, but motorDoc has a way to quickly diagnose all of that chain in about- Yeah … 15 seconds.

Howard Penrose: Well, a little longer than 15 sec- more like a minute.

A minute, okay. It feels like paint drying. But- Uh, in any case, yeah. Uh, uh, and, and what’s kind of funny is, um, back in the ’90s, uh, EPRI actually accidentally steered the technology away from its [00:02:00] core purpose, which was in 1985, um, NAVSEA, the US Navy, had done research on using current signature analysis for looking at pumps, fans, and compressors, the bearings, the belts, the components, all the rotating components using the motor as the sensor.

Not too much different than we are now. I mean, mind you, we got better resolution now, we’ve got, uh, more powerful– I mean, I look at my data from the ’90s, and now it’s completely different. Um, and then Oak Ridge National Lab, same thing, bearings and gears in motor-operated valves. So in 2003, we were the first ones to apply electrical and current signature analysis to some wind turbines in the Mojave Desert.

Wow. Yeah. So, um, nobody had tried it before. Everybody said it couldn’t be done. And, uh, that was a bad thing to say to me because- … it meant I was gonna get it [00:03:00] done. Right. At that time, um, we were looking at bearing issues and some blatant conditions with the, um, with the, uh, generator using a technology called Altest, ’cause I was with Altest at the time.

And, uh, I had taken an EMPath software and blended it with a, a power analyzer, and they still have that tool to this day. I was using that technology all the way through 2015. 2016, I should say. And then- And then switched over to the pure EMPath, which was more of an engineering tool. And then more recently, in 2022, uh, made the decision to ha- to take all the work we’d done on over 6,000 turbines, uh, looking at how we were looking at the data and what we were doing on the industrial side, and took a, uh, created a current signature analyzer that would do one phase of current to analyze the entire powertrain.

Allen Hall: So when you tell [00:04:00] operators you can do this magic, I think a lotta times they gotta go, “

Howard Penrose: What?” Oh, yeah, yeah. They don’t understand it because they’re used to vibration- Right … which is a point analysis system. Right.

Allen Hall: Vibration at this- Yeah … particular location. Yeah. One spot- Even if it’s- … or a couple

Howard Penrose: spots

triax, they’re reading through material, up through a transducer. Hopefully, they put it above the bearing and not in the middle of the machine like everybody is now, because everybody’s trying to sell a sensor. Right. True. They’re not selling a- they’re not selling accuracy. They’re just selling sensors.

Right. So, um- Yeah … you know, uh, I, I’ll, I’ll even talk about one of the companies here. We’ve got Onyx here, and they do it right. I mean, they’ve been doing it right pretty well because we’ve been doing some of the same towers they’re on, and we can match the data they’re getting. Oh, good. Right? Yeah. Uh, so but they get it in multiple spots, and there’s areas they can’t quite reach, so we’ll detect those areas as well.

So it’s a good melding of two technologies.

Allen Hall: Oh, sure. Sure,

Howard Penrose: sure. You know what I mean? Yeah, yeah, yeah. So when you have electrical signature and you have vibration, but in [00:05:00] cases if you don’t have vibration, we’re a direct replacement.

Allen Hall: Because the generator- I

Howard Penrose: dare say that.

Allen Hall: Yeah. Whichever–

Howard Penrose: I dare say that, um, with- Well, the

Allen Hall: generator is acting as the sensor.

Howard Penrose: The air gap. The air gap in the generator s- specifically, yes. Yeah. Generator, motor, transformer. Right.

Allen Hall: Yeah. So any of those- Mm-hmm … you can clamp onto, look at the current that’s on there. Everything that’s happening on the drivetrain, in the gearbox, out on the rotor- Yep … main bearings, all of that creates vibration.

Creates a torque. T- a, a torque. Yeah. Yes, more exactly a torque. Yeah. And that’s seen in the generator, in the current coming out of the generator. Yes. So those signals, although minute, are still there. Yes. So if you clamp onto that current coming out of the generator, you’ll see the typical AC sine wave sitting there.

But on top of that- Is all the information about how that drivetrain is doing

Howard Penrose: Absolutely, and everything else. Anything electrical comes through [00:06:00] that. So what you do is just like vibration, you do a spectral analysis. So every component has a frequency associated with it, just like vibration. It’s, as a matter of fact, I, I keep having to try to explain to people electrical and current signature analysis is no different than vibration analysis.

It’s the same concept. We use the same tools. The signature looks just a little different. It’s a little noisier, um, but you need that noise in order to see everything. But we have a time waveform, and instead of, um, inches per second or millimeters per second, whatever, you know, uh, velocity, acceleration, and displacement, uh, what we end up with is decibels is the optimal method.

You can look at straight voltage signatures at those points or, or current signatures, but the values are so small that you have to look at it from a logarithmic standpoint. Right. There are some benefits to it versus vibration, and there’s some things that aren’t as good as vibration. [00:07:00] So, you know, we, we do…

You have to… Any technology is gonna have their strengths and weaknesses. Sure. So we will see everything all at once. Load doesn’t matter. Right. Speed doesn’t matter. It’s… Only reason speed matters is the location of the frequencies. Uh, so the higher the resolution, meaning the longer you take data, the less chance you have on a lightly lo- loaded machine of blending the peaks together.

Right. Um, on the flip side, if I have two bearings turning at the exact same speed, I couldn’t tell you which one it is. Because they’re the same. Right.

Allen Hall: And the mechanical features of that bearing is w- what creates the signal that you’re measuring. Exactly. So if a bearing has five rollers versus 10, just imaginary thing.

Yeah, yeah. Five rollers versus 10 has a different electrical signature, so you can determine, like, that bearing, that 10 roller bearing- Yes … has the problem, the five is fine. Yes. Yeah. That’s the magic, and I think people don’t translate the mechanical world into the electrical world. That that’s what’s [00:08:00]happening.

They,

Howard Penrose: they don’t because, because what’s happening is they named it wrong.

Allen Hall: Yes.

Howard Penrose: A majority of our users are mechanical folks. Sure. Our vibration analysts and stuff like, ’cause they know how to look at the signatures. Right. Everybody tries to force it on their electrical people, and electrical people go, “We don’t know what this is.”

Yeah. And it’s, it’s, it’s a matter of that training and, and, you know, in the electrical world, you’re not taught to look at that. Right. Yeah. It doesn’t matter. Mechanical world, you’re taught to look at that. So our intern, we were trying to bring in electrical engineering interns and found out that just wasn’t working.

So last year, I brought in my first, uh, intern that’s, you know, he’s been with us now since I brought him in. Okay. Uh, and, uh, Amar, and, uh, you know, he’s helped us develop our vi- uh, vibration software to go along with it. Guess what? It’s the same thing. It’s the exact same sy- system Um, but we just take in a vibration signal instead.

But he picked up on it immediately as a [00:09:00] third-year college student. I can take somebody with a decade as an electrical engineer with a PhD and they can’t figure it out.

Allen Hall: Well, because you’re, you’re taking real- Because it’s different. Yeah. It’s r- well, it’s real-world components-

Howard Penrose: Yeah …

Allen Hall: creating electrical signals.

That’s hard- Well, you have- … to process for a lot of people. Yeah,

Howard Penrose: yeah. It’s

Allen Hall: just not

Howard Penrose: something that we do every day. But that’s… If they, i- if we sa- i- i- if you’re looking at vibration and you start looking at the sensor, it gets complicated too, ’cause guess what? It’s an electrical signal. Right. It’s, it is technically electrical signature now.

It’s converting a

Allen Hall: mechanical signal- Right … into an electrical signal, which is what’s happening in the generator anyway. Yeah.

Howard Penrose: Whether it’s a piezoelectric cell that’s generating a small signal- Yeah … on top of a small waveform that you then take out, you demodulate, uh, or it’s, uh… So you take that carrier frequency out, or it’s a MEMS sensor, which is the same thing.

You know, the, it just sees some slower s- It, it does more of a digital output. So you, you, you know, you have those, or you [00:10:00] have this, which just basically uses a component of the machine to, to, as its own sensor. There is one other difference between them, too, and, uh, I find this very useful when I’m going out troubleshooting something that other people can’t figure out, uh, ’cause we use all the technologies.

So in this case, it would be, uh, the structural movement. Okay? So, so say I have a generator and there’s something wrong with the structure, and the whole machine is vibrating. So y- well, if I put a transducer on it, they might think that’s vibration or something else. We don’t see it. Right. We only see directly exactly what’s happening with the machine.

Sure. So a lot of times when we go in to troubleshoot something that people have done vibration on and everything else, it’s been pro- a, a problem for them for years. We walk in, and all of a sudden we’re identifying whether it’s the machine or it’s something else right off the bat. Then we can take a look at the vibration data and [00:11:00] say, “Okay, it wasn’t the bearing or the bearing, um, structure.

It was, you know, the mounting.” Right. It wasn’t

Allen Hall: fastened

Howard Penrose: down properly. Yeah,

Allen Hall: yeah. Right.

Howard Penrose: Go tighten that bolt. Right, exactly.

Allen Hall: Well, I mean, that’s the cheap answer. Yeah. I’d rather tighten a bolt than rip apart a motor or a generator- And, and- … every day …

Howard Penrose: and that’s the whole point. Now, there are other strengths that go with it.

So for instance, on the powertrain of a wind turbine, I can tell you if you’ve lubricated the bearings correctly. Wow. Because part of what we do is we do take those electrical signatures, and we convert those over to watts. Watts is an energy conversion. Sure. So you see that as heat or some type of loss.

So whatever, whatever’s being lost there is not being sent to the customer. To the outside. Right. Making money. So, um, if I’m taking a look at, say, a main bearing, I might see watts or kilowatts of losses. So you’re gonna have some ’cause you have friction, right? But when we see it increase on, say, a roller, [00:12:00] or the rollers, or, or the cage, that’s usually an indicator that I have a lubrication issue.

Or if we only see it on the outer race, that means that they didn’t clear out all the old grease when they were lubricating it, ’cause the rollers then have to ride across it- Right … ’cause it dries up.

Allen Hall: Sure.

Howard Penrose: Uh, and will carry contaminants. So if you see that, you go up, clean it up, you’ll extend the life of the bearing.

Absolutely you will. Without having to do a lot of work. So, uh, we, we look at our technology as more so early in the, in the stage of a condition. I don’t wanna call it failure, ’cause it’s not a failure. It’s something that’s mitigable. And I made that word up. You can mitigate it. Meaning you can go up and correct it and extend the life of that component.

Sure. Uh, in gearboxes we’ll see problems with, um… Well, the, the one we’re talking about here a fair amount is all the circulating currents going on uptower. We did that research. The current signature analyzer we have is a direct result of doing wind turbine [00:13:00] research just on circulating currents uptower, ’cause we conferred everything over to, to sound at 48 kilohertz.

And so that gives me a 24-kilohertz signal. That high-frequency stuff, which we’re researching in CGRE, and IEEE, and IEC, is called supra harmonics, which I– we talked about that before. Yes, we have. Yeah. And, uh, so when you start seeing that in the, in, in the current that’s circulating uptower because the ground that goes from the top of the tower down is for- DC

lightning protection. And lightning protection, yeah. It’s not meant for, um- Not for

Allen Hall: high frequency- Yeah …

Howard Penrose: currents. Yeah. Uh, we, when we measured it, when we mapped out dozens of towers of all different manufacturers, we found that the impedance about halfway down the tower is where it ends. Sure. The, the resistance.

And then the increased, uh, the high-frequency noise turns any of your shaft brushes into resistors. And at about 15 kilohertz, no current is [00:14:00]passing through them. It’s all passing the bearing, which becomes more conductive the higher the frequency. So with 60% of main bearings failing due to electrical currents, it’s actually currents that are circulating uptower.

It’s not static. There is some static up there, but it’s not static. It’s coming from the controls, the, the generator, and everything else. Inverters,

Allen Hall: converters.

Howard Penrose: And we’ve seen up to 150 amps passing through a, through a bearing.

Allen Hall: So I– We run across a lot of operators who have been replacing main bearings, and they don’t know the reason why.

Yeah. And I always say, “Well, call Howard at MotorDoc because I would almost bet you you have the f- high frequency running around uptower in the nacelle- And the next main bearing you put in there is gonna go the same way as the- Yeah … first one you put in there. Until you cut off that circulating current and then the cell, you’re just gonna continue with the problem.

Then you haven’t eliminated the problem, you’re just fixing the result of that problem. Yes. But it takes- Yeah, you’re, you’re- How, [00:15:00] how, well, how long- You’re replacing

Howard Penrose: a fuse.

Allen Hall: Right, you’re replacing a fuse. Yeah. How long does it take you to s- to determine- An expensive fuse. Yeah. Yeah. Oh, yeah, ’cause you’re taking the rotor down.

Yeah. Well, how, how fast can you determine if you have harmonics uptower that are gonna be causing you problems? 120 seconds.

Howard Penrose: Okay.

Allen Hall: So that’s the thing. I think a lot of- I mean,

Howard Penrose: that’s of the actual data collection time. So you clamp on uptower, uh, and then you can… Well, the way we have it set up now, you just tell it you wanna collect data every five s- uh, five minutes, and then you go downtower, let it collect its data, go back up, grab it.

Um, it’s like…

It’s huge. It’s this size. So, um, and then you connect- It plugs into a laptop. Yeah. Plug it into a laptop or any type of tablet. Um, it, it’s Windows now. I’m trying to get away from Windows. We’re gonna have Linux systems, uh, as well. Uh, and then you use that to, um, just collect that data, and then you press another button.

Now it pops up, and it tells you if you’re in danger or not, [00:16:00] the amount of current passing through the bearing, and the frequencies all the way out.

Allen Hall: So the ideal is you’re gonna have this kit with you in the truck. Yeah. And as you see these problems pop up, you’re gonna clamp on uptower. Yep. You’re gonna measure these circulating currents, and you’re gonna know immediately if you have another mechanical issue, a, a lubrication issue- Oh, yeah.

It’ll look at- … some kind of alignment issue, or- You’ll get all

Howard Penrose: of this information at once. So you- Right … if you go on the power side. So certain turbines, like anything that has the transformer downtower, you don’t have to climb. Right. GE. I mean, I don’t climb. So, uh, uh, you know, th- and that was part of the, the concept behind when we started down this path because I’ve been in the wind industry since 1997.

So one of the things I always saw was, and, and we talked about even, you know, here when it was called AWEA, and we were talking always on the health and safety side about wearing out the technicians. Um, so we discovered that, you know, what was it? Almost 60% of the [00:17:00] turbines you didn’t have to climb. Right.

Oh, yeah. And even the ones you do, you go up, you set it up, and it’ll tell you where you need to focus. The other thing in the powertrain, let alone the generator, when we do a sweep of a site– Now, if we do a straight electrical signature analysis, I’d term that one as a technician’s tool. Sure. That’s more of an engineer’s tool.

Uh, a lot more data, a lot harder to set up. But even though I’m saying harder to set up, it’s still pretty easy. It’s still minutes. Right. Yeah. Most technicians will collect data with, like, a couple hours worth of training. Yeah. You g- You basically gather that data, and if you’re getting a site, so we’ll go out– I love going out in the field.

So we’ll go out in the field, especially if it’s a tower we don’t have to climb I’ll knock out, uh, well, let’s just say I’ll, I’ll, I’ll name one. Say a GE 1.6. I’ll knock out one of those every eight to 11 minutes, depending on how you get to the tower.

Allen Hall: So that’s a full diagnosis of drivetrain- Yeah … plus anything odd happening- Yep

with circulating currents and all that [00:18:00] can- Oh, no, no. Circulating- Or just- … current, that’s a- That’s a separate thing at tower … separate study that- Okay … you have to do that uptower. But anything, anything drivetrain-wise, you can be in and out- Yeah … in a couple of minutes. Yep. Okay. So there’s a lot of operators that have end-of-warranties coming up, right?

Yes. There’s been a lot of developments, so they’re kind of running into the end-of-warranty, and they don’t know the health status of their drivetrain. Same thing for a lot of operators that are in- Yep … full service agreements, and they’re questioning whether they’re getting their money’s worth or not.

Yes. I always say, “Call Howard at Motordoc. You guys can have a whole site survey done maybe in a couple of days, and you will know all the problems that are on site for the lowest price ever”. Yeah. It’s crazy how fast you can do it and how accurate it is. I talk to operators that use your system, so I hear you.

Yeah. Your podcast, listen to your podcast, I’m calling your customers to find out what they say, and they love it. Oh, yeah. They can’t believe how accurate it is. Yeah. Well, the thing about that is we as an industry need to make sure that our turbines are operating at [00:19:00] maximum efficiency. Yep. And if a simple tool like the Motordoc EMPath system exists, we need to get customers, operators in line to start doing it worldwide.

Australia- Oh … Europe-

Howard Penrose: Yeah. We- … Canada. Australia, we’re trying to get into, but right now we even have OEMs using it through North- That’s good … and South America, Asia. Good. Uh, Middle East, um, and, uh, and some of Europe. Good. So it’s, it’s, it’s really taking off. Uh, I’d say probably our biggest market right now is Brazil.

Sure. They’re going crazy. Well, the, the turbines are- They’re having a lot of problems. Yeah.

Allen Hall: Right. And the, well, those turbines have a h- high usage, right? So because- Oh, yeah … the winds are so good, they’re operating at, like, capacity factor is above 50%. Yes. It’s insane. Yeah. So there’s a lot of wear and tear.

There’s no downtime for those turbines.

Howard Penrose: Yeah. Well, and, and people think it’s all the starting and stopping. It’s not. No. It’s a grid-related issue. So we have- Sure … we have a low frequency. And you know some of the stuff I volun- I, I’m, I’ve been volunteered for- [00:20:00] Yeah … uh, including the CIGRE thing. Um, so I get to sit in the grid code committees for IEEE and put my, and our input into that, uh, and kind of watch the back of the IBR industry, right?

Mm-hmm. ‘Cause there’s a definitely bias against our industry. Um, and I also, uh, get to hear what’s going on in the grid side of things from CIGRE worldwide, and it’s all very similar, and it has to do with low-frequency oscillating currents- Yes … called subsynchronous currents- Yes … which are low enough not to damage large synchronous machines.

And they thought, and there’s books written on this, by the way, multiple books written on wind turbine impact- Uh, and they’re seeing now, um… Well, we detected it first, along with Timken. Hank, uh, and, and I went out to a site, and we detected for the first time, because of how they wanna do the testing and where the site was located, we saw the oscillating torque [00:21:00] in the air gap, ’cause that’s one of the things the technology does.

It actually measures the torque, air gap torque. Sure. So we were watching the oscillating torque as a tower started up. And so we did, we went through the rest of that site looking at the same stuff in the same way. It increased our time and data collection, and time on site. But then we started looking for it at other sites, and going to pass data because I don’t have to go back and retake data.

Right. And we’re like, “Oh my God. It’s everywhere.” 16 hertz, 21 hertz, and 50 hertz. And we found a paper that specifically identified that as the sub synchronous frequencies for 60 hertz. So we know what they are also for 50 hertz. Once we identified that and we saw how much the torsi- torque was oscillating, we worked with Shermco, who got us some information on Y-rings that were failing.

Yeah. And they were all failing… When the metallurgy was done, they were all failing from fatigue. And you’re like, fatigue how? What’s fatiguing these connections? [00:22:00] Well, the fatigue is that air gap torque- Exactly … because you’re basically causing the, the, everything to oscillate a little bit, and that causes the windings to move slightly.

It’s a living,

Allen Hall: breathing machine-

Howard Penrose: Exactly … this generator

Allen Hall: is.

Howard Penrose: Yeah.

Allen Hall: It’s not

Howard Penrose: static. It’s definitely not sta- no electric machine is static. No. Even a transformer’s not static. Right.

Allen Hall: So- There’s a little

Howard Penrose: bit of wiggle going on there all the time All the time. And it’s minute, so it takes a long time. Right. And what, uh, uh, everybody…

Well, first people thought it was a particular manufacturer, which it wasn’t. Turned out every defig’s failing the same way. Sure. You’re fatiguing it. Yeah. Every bearing is failing the same way, even in the gearbox, main bearings, and everything else. Right. All of these conditions are happening across all the OEMs, but they’re not allowed to talk.

Well, this is, this is the thing that

Allen Hall: I like watching your podcast.

Howard Penrose: Yeah.

Allen Hall: The Chaos and Caffeine. It comes out Saturday mornings. It’s on YouTube. If you haven’t- Yeah … clicked into it, you should click into it

Howard Penrose: because a lot of these issues are discussed there. It’s definitely, um… [00:23:00] Let’s just say I’ll speak Navy quite a bit.

Allen Hall: It’s a great podcast, and I think what you’re doing with the EMPath system- Yes … at motor dock is really a game changer. Yeah. I’m talking to everybody, all the operators I know. I keep telling them to call you and to try the system out because it’s so inexpensive and it does the work quickly and efficiently, and it’s been proven.

There’s no messing- Oh, yeah … around when you’re talking to MotorDoc. I…

Howard Penrose: Somebody dared tell me that there’s no standard for it. There’s ISO standards for it. Yes. There’s IEEE 1415- Yes … which I chair. Uh, and there’s other standards coming out- This is- … associated with it. And there’s a document that I also chair for Sea Gray- Called A178, which is the practical application of the technology.

So it’s well-documented. There are traceable standards for it. I need more

Allen Hall: operators to call you- Yeah … and to talk to you and get systems in the back of the trucks that they can use to check out the health of their gear boxes and their drive trains and their generators. How [00:24:00] do they do that? Where do they go?

Where, where’s, what’s- Well- … the first place they should look for?

Howard Penrose: Uh, info@motordoc.com. Okay. I get all, I get all of those as well, so do my people. Um, or, uh, LinkedIn. LinkedIn’s really good.

Allen Hall: Look up anything. Yeah.

Howard Penrose: Yeah, yeah. So, so either the company at Motordoc, or, uh, I’m, I sh- I’ll show up either searching for my name or, uh, linkedin.com/in/motordoc.

Come straight to me ’cause I’ve been in, on LinkedIn forever, so- Right, just- … I got to do that … look up

Allen Hall: Howard Penrose, P-E-N-R-O-S-E. Yep. Or go to motordoc.com is- Yep, motordoc.com … the website address.

Howard Penrose: Yep. There’s a lot of great information there. And we have partners, and we have people. We’re growing the company.

You know, talk to me. I, I’ll- Yes … I like answering the phone and talking. It’s, it’s a thing. My people go, “Can we answer the phone one?” No. Um, but, but yeah, we, we, y- when you call us, you’re not just dealing with a single person. Right. The Motordoc is far more expansive. Right now, we [00:25:00] just got our partnership with, uh, Hitachi and, and Juliet- Yeah, that’s great

and stuff like that. Uh, we’re helping them with certain things. Uh, we’re partnered with some of the big OEMs, almost all of them, um, you know, helping identify the issues, you know. And, and when users contact us, often they’ll tell us what’s going on, and we’ll, we can, uh, sometimes say, “Yeah, it’s this, and here’s how we prove it.”

Allen Hall: Yeah. That’s the, that’s the beauty- Yeah … of calling Motordoc. So I need my operators that, that watch the show- Yeah … worldwide, go online, go on LinkedIn, get ahold of Howard, get ahold of Motordoc, and get started. Yep. Howard, thank you- And- … so much for being on the podcast. Yeah. This is fantastic. I love talking to you because-

it’s, it’s like talking to, you know… Uh, no, really, it’s talking like someone who’s a real good industry expert, who’s been there a long time, and understands- Yeah … how this

[00:26:00] works.

MotorDoc Finds Bearing and Gearbox Faults in Minutes

Renewable Energy

The Fine Art of Appealing to Idiots

Published

23 hours ago

May 20, 2026

Alice Rush

The fascism of the early 20th Century taught us all the key elements of the playbook (see below).

In particular, when a leader identifies an enemy like Islam as a grievous threat and pledges eliminate it, one might think that such a position would generate suspicion, rather than adoration.

No so here in the United States, where tens of millions of uneducated Americans would happily elect Trump an absolute leader for life, in the way of Putin and Xi.