This is a transcript from the webinar Power Performance Measurements: Cheaper Faster Better. Click here to watch the full webinar.
Paul :
Hello, everyone. Welcome to this wind power engineering and development webinar, Power Performance Measurements: Cheaper, Faster, and Better. I’m your host, Paul Dvorak, editor of Wind Power Engineering and Developments magazine. Thank you for joining us. Now, before we begin, I’d like to cover a few housekeeping items. At the bottom of your audience console, you’ll see several application widgets for your use. For instance, as questions come to you during the webcast, and I would encourage you to ask questions, click on the Q&A widget and type them in there. We’ll try to cover as many as possible before our time is up. If the question calls for a fuller answer or we run out of time, it’ll be answered later by email. We do capture all the questions. Now, a copy of today’s slide deck and additional materials are available in the resource list widget. It looks like a green folder at the bottom of your screen.
You can expand your slide area by clicking on the maximize icon at the top right of the slide area, or by dragging the bottom right corner. Now, if you have difficulty, please click on the help widget, the one with a question mark icon. Information there covers technical issues. An on-demand version of the webcast will be available about the day after the live presentation and can be accessed using the same audience link that was sent to you earlier. Now, of course, not everyone that wanted to attend today’s webinar could be here. You can help them learn from it by tweeting the key points and the takeaway that you think important. In your tweets, be sure to include the hashtag #windwebinar. After the presentation, I’ll read the questions that you in the audience have submitted. I suggest not waiting until the end of the presentation. Type your questions in as they come to you. We’ll try to answer as many as possible before our time is up.
Now, let me tell you a little about our speaker, Dan Bernadett. Mr. Bernadett has over 20 years of experience in the wind industry. Throughout his tenure at AWS Truepower, Mr. Bernadett has assembled a formidable base of experience and expertise in specialized areas, ranging from diagnostics of plant performance issues to turbine performance measurement. Mr. Bernadett is an expert on turbine technical issues, plant design, and resource assessment. The extensive range of industry experience gives him a unique ability to solve the diverse problems that can affect operational performance and project profitability. With that, let us begin. Dan, the microphone is yours.
Dan:
Great, thanks, Paul. Like Paul mentioned, we’ll be talking today about power performance measurements. Many of my clients ask me, “Why isn’t my plant performing the way I expected it to?” Well, there are many reasons for plant under-performance, but the largest one and the easiest one to get a handle on the magnitude and the reasons for it is turbine under-performance. Now, turbine power performance measurements have traditionally been conducted using the existing IEC standard for this, but there’s a draft standard that will be adopted soon that has many different aspects to it. We’re going to talk today about how to make that new standard work for us to allow us to make cheaper, faster, and better measurements of power performance.
Paul covered some of the housekeeping items, so we can skip through those. Thanks, Paul, for that good introduction. I also want to thank Ellie Weyer from AWS Truepower for all her work on this presentation and all her work conducting power performance measurements at AWS Truepower. A few words about AWS. Many of you are clients. You know us well. You know that we do the energy production estimates for about half of the projects that are financed in the US. You may not know that we do about half of the projects in India as well about a third of the projects in Brazil. We have a strong and growing due diligence group that’s working all over the world to make sure plants avoid risk and exceed their expectations. Today, we’re primarily going to be focusing on power performance measurement. This is an area of strong growth for AWS Truepower. Last year, we tested 36 turbines. 24 of those were GE turbines, but we also tested 10 Vestas and 2 Gamesa turbines. This is an area that’s received a lot of scrutiny lately because of some under-performance issues that have been detected. We’re working to make sure those are addressed and resolved.
Power performance measurements can be a complicated issue that’s a contractual and technical issue, but it can also be seen very simply. We measure the wind speed. We measure the power output. We plot the power versus the wind speed, and we compare that to the warranted curve. I want to frame that in simple terms because the details can get quite complex.
When we measure the wind speed, it’s not just putting an anemometer up and getting the readings. We’re making sure that the terrain and the obstacles to aerodynamic flow don’t affect those measurements. The IEC has a very constrained method of determining the valid wind direction sector, so those wind speeds only from those directions are used in the test. The anemometer is selected very carefully for highest accuracy. It’s mounted on the tower very carefully so that the aerodynamic influences of the tower and the booms don’t affect the readings.
We’re not just measuring wind speed. We’re measuring temperature and pressure as well so we can make air density corrections. Essentially, those, we don’t want to treat the performance of a turbine at sea level the same we would a turbine at 2,000 meters where the air density is very different.
We’re also making measurements of turbulence or the axial changes in the wind speed over time. We’re measuring shear too, change in wind speed with height. We’re also measuring incline flow or the angle of the flow to the horizontal. Sometimes the turbine’s supply agreement will require that the data be filtered for these factors.
It’s important to distinguish, though, that these factors are required by the turbine supply agreement or by the manufacturer. They’re not part of the IEC. The IEC requires wind direction … vectors are carefully controlled, but it doesn’t include filters for turbulence or shear.
Measuring the power output might also sound very simple, but there are important logistical and safety issues that need to be considered. We’re showing a picture here of current transducers measuring the current in the power conductors of each of the 3 phases. This is a cabinet that can’t even be opened without the pad mount transformer being de-energized because the arc flash potential from this could be hazardous or fatal.
We also are measuring at low voltage. If the turbine transformer is up-tower, that means that all our measurements and all of our personnel work has to be conducted up-tower, so there are logistical factors to this. Also, we are measuring the power at a very different location, some hundreds of meters from where the wind speed is measured, so we’re going to synchronize those data streams by synchronizing the clocks between the power and the wind speed measurements.
Then once we finally get back to plotting power versus the wind speed, we’re filtering that data very carefully, directions according to the IEC and other factors according to the turbine supply agreement, like curtailments for grid, environmental issues like noise or icing, any reason that the turbine might not be fully available to produce its rated power. Then finally, uncertainty is a key issue, especially when the uncertainty is part of the warranty conditions. We want to make sure that we allocate that uncertainty properly. The IEC has a framework to assign uncertainty, but the selection of those uncertainty values is part of the process and needs to be conducted carefully.
With that background, we’re going to jump in now to the main topic of this webinar … and we have talked about how power performance measurements are really crucial to making sure that your turbine and your plant performance meet your expectations. Now, the current standard requires hub height met towers, which can make measurements time-consuming and expensive.
In this webinar, we’re going to talk a little bit about the old standard. We’re going to talk about the new standard, and then talk about what that change means for you and how you can make the draft standard work to your advantage and pitfalls in the draft standard that you have to be aware of to make sure that it doesn’t work against you.
Now, there are opportunities in the draft standard. The most interesting opportunity is that it allows shorter met towers, essentially, shorter, cheaper met towers. They can be as short as the bottom sweep of the rotor. I’ve just illustrated here that the bottom sweep of the rotor, with today’s large rotor diameters, can be quite a bit lower than the hub height. For illustration, a 100-meter rotor on an 80-meter tower has a bottom tip sweep of 30 meters, so theoretically, a tower as short as 30 meters could be used under the draft standard.
This is another way of looking at this. Now, if I have a 60-meter met tower that isn’t hub height but it exceeds the lower limit of the blades, we’re going to talk a lot today about how remote sensing devices like SODAR or LIDAR that measure across the entire rotor disc could be used to characterize the flow across the rotor disc in conjunction with a shorter met tower.
There are a lot of things to think about. I’ve made this matrix to try and explain the different applications and considerations with that. Essentially, the draft standard, you can think of it as it allows you to do 4 different measurement configurations. We’re going to talk first about the first one, which is the same as the old standard. Using a hub height mast. You can’t normalize for shear. You can’t correct for veer or the change in wind direction with height. The draft standard would say because you’re not able to normalize for sheer or veer, there’s going to be added uncertainty. Now, a different measurement configuration allowed under the draft standard is to use the hub height mast and a remote sensing device like LIDAR or SODAR. That remote sensing device now allows us to measure the sheer or the change in wind speed with height and adjust for that. It allows us to measure the veer, or the change in wind direction with height and adjust for that. Consequently, there would be no added uncertainty in the draft standard.
Probably a more interesting option is to use that remote sensing device with a non-hub height mast, a shorter mast. Again, because we’re using a remote sensing device, we can normalize the sheer across the rotor disc, we can correct for veer, and we would have no added uncertainty. Of course, a fourth option is to use a met mast that is as tall as the whole structure that’s above hub height, but that is a much more expensive alternative.
Then there’s limitations to our application. Essentially, in the old standard and with the new, we can use a hub height mast. The draft standard would say, “Yep, a hub height definition of wind speed can be accomplished with a hub height mast in simple or complex terrain.” If we add a remote sensing device to that, we can use what we call rotor-equivalent wind speed, where we measure at multiple heights using our remote sensing device and weight those measurements by the cross-sectional area of that portion of the rotor sweep to create what we call a rotor-equivalent wind speed. The draft standard would say, “Yeah, we can do that in simple terrain.”
We can do a hub height or a rotor-equivalent wind speed definition with a shorter tower too, a non-hub height mast, but only in simple terrain. That’s important to keep in mind, that the opportunity here to make this draft standard-allowed cheaper measurements is only for simple terrain. If we want that rotor-equivalent wind speed in complex terrain, we would need a structure height mast, I’ll call it, that’s above hub height. The takeaway there is the short towers are only in simple terrain.
Now, with the old standard, we used hub height towers, and this is a picture looking down from a hub height tower. You can see the massive crane at the bottom looks like a toy. This is a big construction activity. It’s expensive. It has a lengthy permitting process, and there’s a lengthy procurement process. The tower is a custom-designed pIECe of equipment. It’s made to our specifications. It may have a 6-10-week lead time because it’s built after the order is placed. It’s dipped in galvanizing, it’s painted, it’s welded, it’s cut. There’s a whole construction process that goes into building the tower. Then when you get it to the site, you have to excavate, pour concrete, wait for it to cure, so it’s a lengthy process.
In the new standard, there is an opportunity to use a shorter met tower that’s the height equivalent of the lower blade sweep, and this could lead to a shorter tower, which is cheaper, has shorter permitting times, and has a faster procurement time. Potentially, these are off-the-shelf components, which are manufactured before the order is placed, so all the cutting, welding, galvanizing, and painting is done before we even place the order. They’re off-the-shelf components, which have more like a 6-10-day lead time rather than weeks. Then construction is faster too. There’s no excavation and no concrete once the towers are taken to the site.
I’m going to run a little cost comparison here to illustrate things, but just to lay some groundwork when I flash costs up on the screen, these costs are meant to include the foundation materials, labor, and mobilization for those crews as well as the tower materials, the booms and the hardware materials as well, and labor to install those, FAA lights to protect the towers from aviation hazards, and the power supply for those off-grid lights, which are quite expensive, the H-frame to mount our equipment, rental of excavators, cranes, as well as paint for the tower. There’s a number of things that go into it. This is not just steel and concrete.
In this illustration, just for example purposes, we’re going to say that a self-supporting 80-meter lattice tower costs $160,000 installed. A guyed lattice tower is quite a bit cheaper because there’s less steel and less concrete, so the same height tower might be $100,000. A tilt-up tubular tower, which is typically meant to be a temporary structure, might be even cheaper yet. If we use an even shorter tubular tower, the price comes down quite a bit.
Now, if you’re going to use a shorter tower, you’re going to need a remote sensing device, and I’ve put in here a 3-month LIDAR rental example cost of $30,000 and $10,000 to ship and commission that LIDAR. If we sort of construct a scenario example comparison, scenario 1 might be, okay, I decided to use a tilt-up tubular 80-meter tower that cost me $75,000 installed. The result of that is that I have higher uncertainty because I’m not able to normalize the sheer for my measurement. I’ve made them at hub height measurement, but the draft standard says since you weren’t able to normalize the sheer by measuring across the rotor disc, you have higher uncertainty. Now, if I want to reduce that uncertainty without increasing my cost, I might use a 50-meter tilt-up tubular tower that cost me maybe $35,000 installed and rent a LIDAR for 3 months. Maybe that cost me $30,000. Even with commissioning, my total is the same, but I’ve reduced the uncertainty because now I can measure across the rotor disc and normalize for the sheer.
If using a tubular tower was compared to a guyed lattice tower or a self-supporting tower, there would be cost advantages as well as uncertainty advantages to those choices. It’s not just about cost. Sometimes we find that schedule is a major driver for our projects. A self-supporting met tower might have a schedule that looks like 12 weeks. Most of that is the tower needs to be ordered, welded, cut, galvanized, painted, shipped to the site, excavations need to be opened, concrete needs to be poured and cured, so the schedule for that might look like 12 weeks. The schedule for a tilt-up met tower might look more like 4 weeks because all of that tower construction work is done before the order is placed, and so what we do is order the tower, it’s quickly available, it gets shipped to the site, and it gets installed with no concrete or excavation. If schedule is a driving factor, that could be important as well.
What about accuracy? We can’t just let cost or schedule drive things. This needs to be as accurate as cup anemometers, and we think that it can be. The remote sensing annex in the new standard has extensive validation procedures to make sure that remote sensing is just as accurate as cup anemometry and whatever uncertainty is there we can quantify and include in the process.
Now, the new standard isn’t just better; it allows us more options. There are disadvantages that can occur. Using the new standard can result in higher uncertainty. Essentially, the new standard says you need to add uncertainty if you’re not able to normalize for sheer. Also, the new standard is just more complicated. For instance, the definition of the wind speed can change. The draft standard allows us to define wind speed as the rotor-equivalent wind speed. Again, measuring at multiple levels across the rotor disc and weighting those measurements by the area in that slice of the rotor. It’s just a whole different way of looking at wind speed. If you don’t measure at your site and determine what the rotor-equivalent wind speeds at the site are and get a power curve from the manufacturer that defines the wind speed to be a rotor-equivalent wind speed, then you can’t verify that at the site. You have to have consistent definitions throughout your development period and have all those documents in place and in your measurements consistent with your documents with your contracts in order to have a valid power curve warranty under the new standard.
We at AWS Truepower think it’s really important to prepare for this new standard. We are conducting measurements with remote sensing in parallel with power performance measurement in preparation for this new standard. We’re using profiling LIDAR the way the new standard would require. We’re also looking at other ways that the marketplace will be measuring power performance, including nacelle LIDAR. Now, nacelle LIDAR is not covered under the draft standard. It would be covered under a different IEC standard, which is under development. That’s important to remember that nacelle LIDAR is not in the 61400-12-1 draft standard. It would be covered under a different standard.
We’re preparing for that. We’re working with TI correction. Essentially, the draft standard allows you to adjust the power curve. Essentially, it rotates the power curve to correct for the effect of turbulence so you can correct a warranted curve, let’s say, that’s defined at 10% turbulence to adjust to your site conditions, which may be 14% turbulence, so you can reshape the power curve according to the site turbulence. Like we talked about, the draft standard allows us to use a rotor-equivalent wind speed to redefine the wind speed at your site.
The draft standard allows you to correct for veer. It includes a formula to correct for the change of wind direction with height. We’re also putting much more emphasis on inclined flow. That isn’t a big change in the draft standard, but it’s an area of increasing scrutiny that we’re paying a lot of attention to.
We’re getting ready for the new standard, and we think that you should too because it can result in faster measurements. Essentially, if we can correct for turbulence, correct for sheer, we don’t have to filter out as much data, so we can accept more data and get to the end result faster. We can get to the end result cheaper by using shorter towers, and I think we can come up with the same uncertainty if we manage the process very carefully. We can get a better result.
If we don’t manage the process carefully, we can end up with a higher uncertainty and a much more complicated process of verifying performance that may not result in the conclusion that we’d like to see.
That’s the end of my presentation. I’m really looking forward to see what kind of questions that we can get here, and I wanted this to be interactive to see what the audience has to say.
Paul :
All right, great, Dan. Thank you very much.
Dan:
Thank you, Paul.
Paul :
Nice presentation. Okay, great. Good presentation. Good pictures. Good food for thought as we say. Okay, we got a number of questions coming in. Let me start with Pablo’s. Let’s see. He asks, “When you mention the new standard, is this the IEC 61400-12-2?”
Dan:
Actually, it’s not. I might have needed to be more specific. This is the 61400-12-1, version 2. It’s a new version of the existing standard that covers power performance measurements using met towers and allowing us to use remote sensing. The -2 is a nacelle anemometer standard, and what I was saying about nacelle LIDAR is that the nacelle LIDAR would be treated under revisions of the -2, but I don’t think that the -2 has a set schedule. The -1, version 2 is a committee draft for voting. I expect it to be a final draft international standard next year and then be implemented thereafter. It’s on a track, whereas the -2 is not.
Paul :
Okay, very good. Maya asks this: “What are examples of remote sensing devices, and what type of calibration is necessary for the standard?”
Dan:
That’s a great question. What I’m going to say are examples of remote sensing devices are LIDAR and SODAR. Now, that’s a very simple answer. I mean, there are some different LIDAR technologies, but essentially what we’re talking about here is profiling devices. Profiling LIDAR rather than a nacelle LIDAR. Actually, we’re not actively engaged in using scanning LIDAR to perform this function. Essentially, this is a relatively simple function for LIDAR, just to profile the rotor disc and look at the sheer profile.
Calibration is key. The unit needs to be calibrated. Typically, that’s conducted by the manufacturer by placing the LIDAR next to a calibrated unit and tracing that back to a met tower calibration.
Paul :
Okay, very good. [Grestavo 00:27:32] asks, and I think this is in reference to something early in the presentation, “Is electric power measured from the generator output or after it’s treated and ready to send to the grid?”
Dan:
That’s a great question. Essentially, we are measuring after the generator. I’m not sure what you mean by “treated.” Let me try and clarify. We’re trying to measure the power as close as possible to when the low voltage is sent to the transformer. We want to measure after the converters so that converter efficiency is included in the power curve, but we’re measuring before the turbine transformer such that … This is all done in conjunction with our energy estimates. The electrical losses in a pre-construction plant report include the turbine transformer, so we don’t have the turbine transformer losses in the power curve. They need to be covered, but they should only be covered in one place. The one place that the turbine transformer’s covered is in the energy report for the plant.
Paul :
Okay, very good. Oliver asks, and you’ll have to read into this a little bit, “What about the power performance measurement using nacelle-mounted LIDAR?”
Dan:
Now, that’s a great question. Nacelle-mounted LIDAR is not covered under this version 2 of the -1 standard. Nacelle-mounted LIDAR would be covered under any future revisions of the -2 nacelle anemometer standard.
Paul :
Okay, very good. Let’s see. Sharon asks, “Well will the draft standard be formalized or released?”
Dan:
Well, that’s a good … that’s again a great question. I sound like a broken record on that, but these are all really good questions. Of course, I don’t control that process. We just observe like everyone else, but the way I understand it is the -1, version 2 is a committee draft for voting. I understand that most countries are expected to approve it, at which point it will be become a final draft international standard. I expect that process will be completed early next year, at which point I expect the industry to start adopting, if you will, or paying close attention to it because once it’s a final draft international standard, it’s on a very clear track to become an international standard and become adopted.
Paul :
Okay, good. Gail wants you to look into the future here a little bit. She says, “Are you treating the accuracy of LIDARs and SODARs equally?”
Dan:
We don’t. Just sort of a priori, everybody has to prove their accuracy levels, and essentially a LIDAR has certain advantages in accuracy, although SODARs can be quite accurate. Essentially, every device needs to be evaluated on its own merits and the uncertainty assigned based on test results.
Paul :
Okay. All right. Jim asks, let’s see. “A question occurred to me. Where can I get a copy of the draft standard?”
Dan:
Well, the good news is I can send you a copy of the draft standard because it’s an international discussion, right? If you ask me to send you a copy of the current standard, I would say I can’t send it to you; you have to buy it from the IEC, but the draft standard, Jim [Salmon 00:31:17] could just send me an email, and I could send it to him.
Paul :
Okay, very good. Let’s see. R. Scott asks, let’s see, “Any expectation as to the adoption time frame for 61400-12?” I think the new standard.
Dan:
Yeah, actually, we just covered that, right? I mean, the adoption time frame would be … It’s a committee draft for voting now, and so what I expect … What we’re doing and what we expect the whole rest of the industry to be doing is preparing for it but not implementing it and that adoption to me would be implementing it, and I don’t expect that until next year.
Paul :
Okay. Carlos asks, let’s see, listen carefully now, “Are manufacturers ready for the new standard in terms of REWS and power curve wind speed?”
Dan:
That is a good question. I would answer no. We have not received any power curves that are defined in terms of rotor-equivalent wind speed. You know, are they ready? Well, they may be getting ready. We don’t know what contractual terms the manufacturers will offer next year. We haven’t seen anyone offer contractual terms using rotor-equivalent wind speed. They may be ready, but I haven’t seen it. On the other hand, I wouldn’t expect to see it because it isn’t a final draft international standard, so it’s still in voting.
Paul :
Okay, very good. Jose asks, “Will these new procedures,” the lower towers it seems like, “will they apply to off-shore projects?”
Dan:
You know, that’s a good question. I wouldn’t expect that it would be implemented that way, right? A short tower … When I gave costs, those were strictly land-based simple terrain costs. Offshore has a very different cost structure. If I were measuring offshore, I wouldn’t use the approach that I described here. I would use something like a LIDAR mounted on the transition section of the tower or nacelle LIDAR, and those would be different approaches. I think the transition section wouldn’t be in conjunction with a met tower, so both of those would be exceptions to this draft standard and would have to be treated in sort of a custom discussion with the manufacturer in regards to warranty terms.
Paul :
Okay. Very good. Another question here. We have a lot of questions, too, which is great. Thank you very much, everyone. The question reads, “When we calculate the rotor-equivalent wind speed, is the IEC recommending the met tower anemometer configurations because wind sheer’s going to play more on the REWS?” Should I read it again?
Dan:
No, I’m reading it in front of me.
Paul :
Okay, all right.
Dan:
I’ve got the language. I’m sort of struggling with how to answer this. Let me just talk about it. When we calculate the rotor-equivalent wind speed, the IEC recommends that at least 3 measurements are made throughout the rotor disc, I’m sorry I don’t have the numbers right in front of me, but it does recommend where they’re located. Let’s say, you know, you can’t just measure 1 meter above hub height and 1 meter below hub height and call that 3 measurements. There’s a spread that we’re trying to do. Essentially, you’re trying to characterize the whole rotor, so you really want those measurements spread. You need at least 3 measurements, but with remote sensing devices, there’s no reason you can’t make 5 or 10 measurements across the rotor disc. There are some recommendations on the measurement locations and met tower anemometer configurations.
Okay, the draft standard did a lot of things, right? They didn’t update this for, I don’t know, how many years, 6 or 8 years, and there’s a lot packed into this. There’s things that I didn’t cover in this presentation, and one of those would be met tower anemometer configurations, how the booms are structured. How the anemometer is placed relative to the tower is different in the new standard. There are new requirements, and you need to pay attention to those, and it’s really a separate topic from the rotor-equivalent wind speed.
Paul :
Okay, very good. All right, Sharon-
Dan:
I hope that answers your question.
Paul :
… asks, “How are the …” Okay. All right. Sharon asks something of a leading question here. I think she could get some argument from the LIDAR and SODAR manufacturers. She says, “Will the unreliability of LIDAR and SODAR on clear days possibly prolong tests relying on this information to measure sheer?”
Dan:
No, that’s a great question. Everybody has their own experience base. We find that LIDAR and SODAR are quite reliable. There is a lower data recovery rate due to possibly lack of aerosols in the air during certain atmospheric conditions. Let’s say you reduce your data recovery rate by 10%, but let’s say you increase your ability to fill the bins by 100% because now because you can characterize the sheer profile, the manufacturer has opened up the sheer filters dramatically because they feel like they can correct for the effects of sheer instead of throwing them out, so you may actually be better off … You may actually have a faster measurement in the new standard rather than prolonging the measurement, but only if you manage the process carefully.
Paul :
Okay, very good. John asks, and he wants more information on SODAR and LIDAR. “What are some of the pros and cons in considering SODAR versus LIDAR in terms of both performance and cost?”
Dan:
Wow. [crosstalk 00:37:30]-
Paul :
That sounds like a long answer.
Dan:
I’m not going to …
Paul :
You want to take it offline? That’s another presentation … That’s a whole another webcast.
Dan:
It’s a whole another presentation. I’ll say some things about it, but we can talk offline about it. Essentially, you know, the IEC is sort of agnostic to what device you’re going to use, but the user needs to be careful about data recovery, altitude performs, certainly cost of the unit that they’re using. Yeah, any more than that, we could have a whole another webinar on that.
Paul :
Okay. All right. Marcos asks an excellent question here. “With the current practice of manufacturers offering boost upgrades to their machines, is there a point in performing such tests in your view given that they may be boosted temporarily during the power performance test?”
Dan:
Well, that is a great question because the wind turbine is not a static machine. Really, the industry’s changed since I joined AWS 22 years ago. The turbines now are not … It’s not just a single turbine, right? A lot of times the performance is a function of the temperature, the turbulence intensity, the conditions of the site, and so they may be, like the question says, boosted temporarily, but the point is to identify a control algorithm under which the turbine is tested. If that means disabling the boost, then that is what’s agreed upon so that … I think it is important to define what the performance is going to be and verify that that is what is occurring in the field. If that means disabling the boost or making sure the boost is there and sort of controlling the performance of the turbine to be consistent through the test period, then I think it is a valid process.
Paul :
Okay. Very good. All right. Christian asks, “For the turbulence normalization procedure, should we have turbulence measurements from the met mast at hub height? I ask this because LIDARs and SODARs measure turbulence in different ways than the met mast does.”
Dan:
That is a great question. What I would … I don’t have the answers to everything, actually, but what I would suggest is that the turbulence correction procedure is a difference procedure. If we measure consistently, then the difference in turbulence can be adequately characterized. I realize that SODARs and LIDARs measure turbulence different than a met tower, and they may come up with a small difference in absolute magnitude, but you put that aside for a second and say, “If I measure my turbulence with a LIDAR, and that’s how my power curve is defined according to the manufacturer, and I measure that turbulence with a LIDAR at the site and that’s how my turbulence is defined, then I make a difference between those measurements and correct,” then I would submit that that’s a valid process. If those are inconsistent definitions, let’s say the manufacturer defined it with a cup anemometer and you measure it with a LIDAR, then you do need to understand the difference in how turbulence is measured, given those 2 different devices.
Paul :
Okay. Jim wants you to look into the future again. “Do you expect there to be any differentiation between the way SODAR and LIDAR data are treated in the version 2 standard?”
Dan:
I don’t expect any fundamental differentiation. Again, the draft IEC is agnostic to the device that’s used. However, each device has to … Essentially, the user has to assign an uncertainty based on the device, and that needs to be assigned based on the performance test statistics for that device. There may in fact be a differentiation between a certain SODAR device and a certain LIDAR device.
Paul :
Okay, and [inaudible 00:41:44] asks, “What’s your view of using LIDAR alone for power curves without a met mast at all?”
Dan:
Well, that wouldn’t be allowed under the draft standard. If the turbine supply agreement with the manufacturer requires use of the new standard, then that wouldn’t be allowed, but our view is that in the evolving marketplace, as long as the 2 parties contractually agree to what the ground rules of the test are, they can do anything they want, essentially. Using LIDAR alone is a reasonable option. Let’s say you were offshore. I wouldn’t try to put a short met tower upwind of the turbine. I’d probably put a profiling LIDAR on the transition section of the tower. As long as the manufacturer and the owner agree to the test plan, I think that could be very successful.
Paul :
Okay, very good. Robert asks, “You mentioned that it’s important to work with the manufacturer to define REWS. Can you elaborate on that a bit more?”
Dan:
We have to remember, okay, so rotor-equivalent wind speed is … let’s say it’s measuring at 10 levels and weighting the top level very little because it has this little slice of the rotor, and the middle measurements have a larger weighting because they have a big, wide section. It’s a different way of defining wind speed. Essentially, the power curve needs to be defined using that same definition as your measurements do. The manufacturer has to give you a power curve that says, “This is consistent with using rotor-equivalent wind speed, and in order for you to be able to verify according to that power curve.”
Paul :
Okay, very good. Bruno asks, “How does the new standard handle the greater uncertainty of the RSD measurement as we go above ground? Does this not counteract the added uncertainty of the sheer measurements?”
Dan:
Well, that’s a good question. Of course, Bruno has a lot of experience with this, and I don’t have a simple answer to that. I would just say that we have to assign the certainty of the remote sensing device according to its test requirements and weigh that against the added uncertainty that the IEC would suggest if we’re not able to correct for sheer. My feeling is, based on the preliminary data that we’ve looked that, is that the penalty if you will in the IEC for not treating the sheer normalization is pretty stiff, and we think that we can do better than using remote sensing devices.
Paul :
Okay. Thank you. Let’s see. Boy, these guys want to know more about SODAR and LIDAR. Jim asks, “Typically SODAR and LIDAR return diminishes with increased height. How would the difference in data return with height be treated in the data processing?”
Dan:
Yeah, and this is one of the thorny issues of remote sensing devices. Someone touched on this earlier, that you can not only, and this is a sort of 2 sides of the same coin. You can have reduced data recovery with remote sensing devices, but really what we mean there is that you can have a diminished altitude performance. Essentially, if the altitude performance, if we’re not able to gather valid data throughout the rotor disc, if the top section is invalid, then we probably have to throw those data points out, and that’s how I would treat that, is that we would invalidate the data if it’s not valid across the whole rotor disc. That’s probably how we would treat it.
Paul :
Okay. We seem to have an inquisitive audience here. There’s still more to go here. All right, a gentleman asks, “Could you be more specific on horizontal turbulence intensity measurement when using a remote sensing device? Would it be advisable to still use a hub height mast and anemometer?”
Dan:
Well, we’re getting at the same issue that we got at before. We need to start out by remembering that a remote sensing device and a cup anemometer measure turbulence differently, and they can end up with slightly different results on a mean basis. I don’t think, you know, when we go back to my previous answer, I would submit that if you measure with a consistent technology, let’s say the power curve turbulence is defined with a LIDAR, for instance, and you measure with a LIDAR, then using a difference between the turbulence intensity gives you a valid way of correcting for that turbulence intensity. To me, I wouldn’t see that you would need a hub height mast and a cup anemometer because you should be able to identify how, from sort of performance statistics, how cup anemometers measure differently from the LIDAR. That’s sort of a separate issue that you can apply if you need to because your definitions are inconsistent. If you have consistent definitions, then you should be able to just apply a difference between the LIDAR measurements from the manufacturer and the LIDAR measurements from your site that define the power curve versus your site conditions.
Paul :
Okay. I think we went there. All right, thank you. Here’s a good one from Gilles. “Did AWS perform any comparison of power performance measurements with the old and new drafts? If yes, what differences in the result are expected?”
Dan:
Okay. No, that’s a great question. We are planning to do that. We have lined up a research program for this summer to do exactly that, essentially. We’ve done some preliminary work to look at how these things are going to play out, but we think we really need to dig into that and sort of investigate all the sensitivities to different factors and how this is going to play out at a number of sites. That’s what we plan to do, is run a number of sites through the old and the new standards and see how the uncertainties would change and what we can do to mitigate that.
Paul :
Okay, very good. All right, another interesting question. “Can we compare a warrantied PC,” meaning, I think, a power curve issue … “Can we compare a warrantied power curve issued without mentioning the REWS to a power curve using the REWS?”
Dan:
Yeah, I would say no. The reason I would say no is that the manufacturer would not honor that, essentially. I’m just speaking for the manufacturers, and I’m just giving my opinion of what I would expect, but I would expect the manufacturer would say, “No, the power curve that we advertised last year had certain conditions on it. It was constructed under the assumption that hub height measurements would be used and that the turbine supply agreement would have strict filters on the turbulence and sheer and inclined flow.” I would expect the manufacturers may actually possibly have a different power curve that says, “Oh, we assume that you’re going to use rotor-equivalent wind speed to verify this power curve,” and it may have different filter requirements on sheer and turbulence because there is an assumption that those will actually correct it.
It could be different. I would say you certainly can’t use it without talking to the manufacturer, but there’s also another scenario here that the manufacturer will look at their power curve, look at these new standards and say, “We will honor the exact same power curve using the rotor-equivalent wind speed versus the hub height definition,” but again, we have to remember that we’ve changed the definition of wind speed. We can’t assume that that power curve will be honored by the manufacturer.
Paul :
Okay, excellent. Kyle asks another good question here. “Would you elaborate on what remote sensing or mast combinations are viable or acceptable in complex terrain?”
Dan:
Well, we did go over that in the presentation, so we could possibly jump back to that slide. Let me know if this seems to work. I just tried to push that slide back to the audience on the live camera. Did that come through?
Paul :
Which number was it?
Dan:
Slide 15 out of 28, so I tried to push that back, but if people can’t see it, that’s fine. It’s not critical. I’ll try and go over that topic again. Essentially the takeaway here was that short towers can only be used in simple terrain. If we want to use rotor-equivalent wind speed, of course you need a remote sensing device or a hub height met tower. Yeah.
Paul :
Okay. All right. All right, here’s a question I think you’ll have to … you’ll answer. “Does the new standard draft contemplate any changes to IEC compliance criteria to avoid sites’ calibration?” I’m not sure what that’s asking.
Dan:
Yeah, it’s a little unclear what’s being asked here, but I purposefully didn’t cover site calibration in this presentation because I felt like that’s a whole another presentation, but the way I see the draft standard, there aren’t any big changes in how a site calibration is determined or what you have to do to avoid it, or when you have to do it. Site calibration isn’t … Whether you have to do it or not, I don’t think changes, but how you do it changes dramatically because you can now use the short towers with remote sensing devices. When we talked about cost savings or things, that’s double. We have to do site calibration because now I can not just save 1 tower, but I can save 2 towers’ cost. This is even more important when applied to site calibration, but it doesn’t change whether we have to do it or not, just how much it costs us when we do.
Paul :
Okay. All right, here’s one from Nelson. “If the masts for complex terrain have to be above hub height and you can’t use a remote sensing device, how much above hub height do the masts have to lower uncertainty at complex sites?”
Dan:
Well, trust Nelson to ask a really tough question. There’s a lot in there to talk about. I don’t have any simple answers. I’ll have to grab Nelson offline and try and nail this down.
Paul :
Yeah, that’s fair enough.
Dan:
Yeah, I don’t have a simple answer to that one.
Paul :
Okay, we’re getting down to the stretch, now. Robert asks this. “What PPT configuration hub height mast or low tip mast with remote sensing device is recommended in complex sites?”
Dan:
Well, yeah, I think we talked about that. Essentially, for the draft standard, in order to not have additional uncertainty, you would need essentially a structure height mast to, in complex terrain, to use the rotor-equivalent wind speed.
Paul :
Okay. Let’s see.
Dan:
I think that’s what’s being asked there.
Paul :
Okay, let’s see. Pablo wants to know, “Will the new standard only apply if the manufacturer agrees to be measured against it, or will it eventually become an obligation for everybody?”
Dan:
Well, I think the answer to that one is clear, that things are only relevant if both parties contractually agree to them. The new standard is only relevant if both the seller and the buyer agree to that as a contractual metric. I don’t think that this draft standard is going to be sort of universally adopted and everybody will just go exactly by the book because actually the book is quite a bit more open now. I think that we’ll see in the future a greater diversity of methods, both within the standard and outside it.
Paul :
Okay. Carlos asks again, “How would the rotor-equivalent wind speed power curves affect the annual energy production on a pre-construction assessment? Is the power curve based on rotor-equivalent wind speed coming only at contractual stage and proposed by manufacturer?”
Dan:
Well, this is a great question, and it’s not a new question. It’s not like we haven’t thought about this before, and when we’ve thought about it previously, we’ve included it in our planning on our energy side. When we reconstructed open wind and our site wind process, we made sure that we had multi-height wind resource grids so that you can create a rotor-equivalent wind speed in a pre-construction method. We have the methods in place to use rotor-equivalent wind speeds in a pre-construction assessment on our side.
What we’ve been lacking there is a power curve issued by a manufacturer that is specifically intended to be used in a rotor-equivalent wind speed framework. Now, if we assume that they’re the same, fine, we can use our processes to do that, but we don’t have those issued by the manufacturer. When we come to the point, which I expect to happen next year, when people start talking about, “Oh, well, this is in my contract. This is in my draft contract. How are we going to verify this?” Then at that point, we can build those into our pre-construction estimates.
Paul :
Here’s our last question, ladies and gentlemen. Christian asks, “How much potential for cost-cutting of the LIDAR measurements do you see in the next few years?”
Dan:
Well, we showed some examples there of how we think that LIDAR can reduce costs. One thing that maybe I didn’t do is talk about tower heights are growing. We sort of focused on 80 meters, but when the hub height is 100 meters or 120 meters, the cost savings to use LIDAR is even greater. I think that LIDAR and other remote sensing devices are going to be a really important part of the future of power performance measurements.
Paul :
All right. Very good. Thank you, Dan. We’re at the end of our allotted time, ladies and gentlemen. Once again, this webcast will be available for reviewing at windpowerengineering.com. One final message, you can follow Wind Power Engineering on Facebook, Twitter, and LinkedIn. This concludes our program. I want to thank Dan for the fine presentation and everyone else for their attention and their great questions. From the staff here at Wind Power Engineering and Development and from AWS Truepower, we wish you all a good and productive day.
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