Voc VS Vmp in string sizing, temperature coefficient and 690.7

[james391]

Hey there, long time lurker, first time poster.

I've been working in solar for a while, but I've been doing exclusively microinverter based systems for the last 5 years or so and will admit to being a bit rusty on everything else at this point. Guess I've gotten spoiled with this plug-and-play stuff.

I've currently got a project to set up a DC system, which isn't a big deal for me to brush up on, but am having to defend my design decisions with the property owner. Basically, he is pressing why we design around the Voc of the panels when doing our temperature coefficient calculations and selecting our string size. Quoting code hasn't really answered his questions, and I don't really know WHY the code is as it is. Perhaps you guys could help me beef up my knowledge here and put the discussion to bed.

His position is that the open circuit voltage should not be relevant, because there is no current in that state, and if we keep our temperature corrected Vmp below the inverter max input voltage (600V) then that should be fine. If we run the numbers in that way, we can add some panels to the string and therefore reach our inverter startup voltage earlier and make better power in the hot summer months when the voltages will tend to run low. I get why he wants it to be his way, but I've always treated it as a hard limit regardless of if I like it or not.

So, assuming for the moment that you could even get a permit for such a thing....what's the worst that could happen? What are the risks of having too high of a voltage in an open circuit state if the operating voltage stays within the limits? Basically...why is this the way we do it?

Never really questioned it until now, so I'm happy to learn something here and hopefully go into the next conversation armed with some more information. Thanks.

 

[GoldDigger]

During the time between when the string inverter "wakes up" after seeing DC at its inputs and the time it has qualified the grid AC (typically 5 minutes) the DC load current will be low enough that the panel voltage is close to Voc.
Few semiconductors can tolerate overvoltage for "only a few minutes".

mobile

 

[james391]

During the time between when the string inverter "wakes up" after seeing DC at its inputs and the time it has qualified the grid AC (typically 5 minutes) the DC load current will be low enough that the panel voltage is close to Voc.
Few semiconductors can tolerate overvoltage for "only a few minutes".

mobile

Wow, quick reply, thanks!

So, a potential effect of this is that on a very cold day this would basically just perpetually trip the overvoltage protection of the inverter as it tries to start up, since it will remain over the voltage limit until the current ramps up?

 

[ggunn]

Wow, quick reply, thanks!

So, a potential effect of this is that on a very cold day this would basically just perpetually trip the overvoltage protection of the inverter as it tries to start up, since it will remain over the voltage limit until the current ramps up?

At dawn after a very cold night when the array cell temperature is at or below the ambient minimum temperature, when the first rays of the sun strike the array, the voltage will jump to the temperature corrected Voc while the available current is not enough to turn the inverter on. If it's more than the rated insulation voltage of your conductors, you could have a problem. Also, many inverters do not have overvoltage protection, and some of those have an internal register that records the highest voltage the inputs have been exposed to. If that voltage is higher than the published maximum voltage allowed by the inverter manufacturer and the inverter is ever returned for warranty work, the warranty my be declared void by the manufacturer.

Beyond that, many AHJ's will want to see your calculated temperature corrected Voc maximum, and if it's more than 600V or 1000V (depending), you will fail your inspection. That should be reason enough right there.

 

[SolarPro]

Voc is a hard stop design limit. From the inverter guide in the very first issue of SolarPro:

MAXIMUM OPEN CIRCUIT VOLTAGE

Definition: The NEC defines maximum Voc as the sum of the series connected PV module open circuit voltage ratings, after the rating is temperature corrected for the lowest expected ambient temperature.

Importance: Maximum open circuit voltage is a critical design parameter. Exceeding the inverter input voltage rating violates the UL listing of the device; exceeding 600 Vdc may also violate the NEC. (Utility owned systems operating “behind the fence” are an exception.) In some cases, there are dramatic consequences to exceeding the maximum inverter input voltage. Not only is there no way to put the smoke back into a blown capacitor, but also the inverter’s nonvolatile memory retains a permanent record of the maximum PV input voltage. Your client’s inverter is not just broken, it is also no longer under warranty. This is an expensive and unnecessary mistake to make.

While the NEC now allows for 1,000 Vdc system in non-residential applications and 1,500 Vdc systems (or higher) for PV arrays non on buildings, the residential limit is still 600 Vdc.

If you want to get nerdy about source circuit design calculations, this is a good place to start:

Array Voltage Considerations

If your customer wants the benefits of a higher system voltage—longer strings, less BOS, reduced line losses— without all the old-school calculations, then you might want to look at the SolarEdge platform. Any customer nerdy enough to get excited about PV start voltages, will likely find the benefits of module-level optimization with string-level power conversion compelling. Plus, the new HD Wave inverters from SolarEdge have a CEC-rated efficiency of 99% and are about 1/2 the size and weight of a traditional transformerless string inverter.

 

[jaggedben]

1) Won't get approved or pass inspection.
2) will void inverter warranty

Should be all he needs to hear. Tell him he can ask UL and the NPFA why.

 

[Carultch]

Voc is a hard stop design limit. From the inverter guide in the very first issue of SolarPro:



While the NEC now allows for 1,000 Vdc system in non-residential applications and 1,500 Vdc systems (or higher) for PV arrays non on buildings, the residential limit is still 600 Vdc.

If you want to get nerdy about source circuit design calculations, this is a good place to start:

Array Voltage Considerations

If your customer wants the benefits of a higher system voltage—longer strings, less BOS, reduced line losses— without all the old-school calculations, then you might want to look at the SolarEdge platform. Any customer nerdy enough to get excited about PV start voltages, will likely find the benefits of module-level optimization with string-level power conversion compelling. Plus, the new HD Wave inverters from SolarEdge have a CEC-rated efficiency of 99% and are about 1/2 the size and weight of a traditional transformerless string inverter.

The NEC recommends using the ASHRAE low temperature as a design number. Where I live, it is -21C for cold temperature and +32C for the hot temperature. I know it has been colder than -21C and hotter than +32C. What is the explanation for only designing to the middle 96% of the temperature range, and not designing by absolute records?

Also, what are the consequences of the extreme cold time when the environment goes below the ASHRAE cold temperature, and thus the system exceeds the low temperature voltage that causes voltage in excess of the 600V or 1000V limit?

 

[SolarPro]

Couple things. From a PV system design point of view, the low design temperature is (potentially) more consequential than the high design temperature. You can't damage anything if the actual temperature exceeds your design temperature and your production modeling software will account for these performance impacts.

If you grossly underestimate the low design temperature, you could potentially damage the inverter, depending on the product you are using and how close you are to the upper voltage limit. However, a temperature below the ASHREA value does not necessarily result in an over-voltage condition.

From the article:

System designers must consider three important issues when determining an appropriate design temperature. First, statistically, the record low temperature may never occur again. Second, lower irradiance conditions in winter make it even less likely that peak irradiance (1,000 W/m2) will accompany the record low temperature, which is a necessary coincidence to achieve the calculated maximum voltage based on temperature. Third, to achieve in the field the maximum voltage that is possible on paper, the PV array must be in a condition that is as good as new. The modules cannot be soiled, mismatched or degraded; the maximum voltage for each of the installed modules must equal its published rating. The statistical likelihood of these conditions occurring at the same time is low.

As Bill points out, you can use the record low temperature and reduce the risk of over voltage as compared to the ASHRAE value. In practice, you are likely eliminate more good design options than to meaningfully improve the design's margin of safety. The lowest recorded temperature at the site could very well occur after you commission the system. But after you account for irradiance levels, soiling, mismatch, aging effect and so forth, it is statistically unlikely that you will exceed maximum design voltage at the inverter if you use the AHSRAE value.

While temperature has more of an impact on Voc that irradiance, you can clearly see the impact of irradiance in the attached figure. The lowest temperature will occur as the sun is rising; by the time you reach peak irradiance, the temperature will have increased accordingly.

If this sounds highly theoretical, keep in mind that there are GWs of fielded systems. So these effects are very well documented and understood. The 2017 Code takes this all a step further and allows engineers use simulations to determine voltage and current levels for design purposes.

 

[pv_n00b]

PV cells reach about 80% of Voc at 20% irradiation. Since right as the sun is coming up is usually the coldest part of the day there is good reason to believe that the low temperature corrected Voc is easily obtainable.

Hey there, long time lurker, first time poster.

So, assuming for the moment that you could even get a permit for such a thing....what's the worst that could happen? What are the risks of having too high of a voltage in an open circuit state if the operating voltage stays within the limits? Basically...why is this the way we do it?

Never really questioned it until now, so I'm happy to learn something here and hopefully go into the next conversation armed with some more information. Thanks.

All the components in the electrical system that are energized are rated for maximum voltage. Exceeding this voltage will stress these components and if stressed often enough and with a high enough over-voltage the components will be damaged. The results can be anything from a damaged inverter to a short circuit electrical fault. Since all inverters monitor the DC voltage and record the maximum it also means that if you have gone over the maximum rated voltage for the inverter it is likely that any warranty work requested will be denied.

The NEC recommends using the ASHRAE low temperature as a design number. Where I live, it is -21C for cold temperature and +32C for the hot temperature. I know it has been colder than -21C and hotter than +32C. What is the explanation for only designing to the middle 96% of the temperature range, and not designing by absolute records?

Also, what are the consequences of the extreme cold time when the environment goes below the ASHRAE cold temperature, and thus the system exceeds the low temperature voltage that causes voltage in excess of the 600V or 1000V limit?

Since we are dealing with weather which is an unpredictable natural phenomena we have to make some assumptions. We also have to deal with the fact that longer strings save money and higher minimum temperatures give longer strings. Where does that take us? If we wanted to be very conservative we would use a minimum temperature that was unlikely to ever be exceeded. Since the new low can’t be predicted some value less than the current historical low would have to be used. If the historical low at the project site is -25°C then maybe -35°C would be unlikely to ever be exceeded. But this tracks back to being a restriction on the string length and based on my experience people really want to lengthen the strings, even if they run the risk of exceeding the max rated Voc on some cold morning. Many people in the industry are totally okay with rolling the dice on this. We get to decide if this is a good deal for the customer, because usually they don’t provide any input.

The industry standard is to use the Extreme Annual DB Mean Min temperature from the ASHRAE data. Since that is an average that means that half the time the minimum temperature was below this by some amount. Is that reasonable? Personally I use the Extreme Annual DB Mean Min and subtract one unit of standard deviation from it, this number is located just to the right of the temperature in the ASHRAE data. That means, assuming the temperature curve is a fairly standard bell curve, only 16% of the low temperatures fell below the temperature I calculated. I feel better about that. It’s not the absolute minimum that would significantly shorten strings but its not as likely to get me a damaged inverter.

I pulled an ASHRAE sheet at random as an example and here are the values:

Extreme Annual DB Mean Min: 7.7°C
Standard deviation: 1.6
My low temperature: 7.7-1.6= 6.1°C
Minimum temperature in 50 years: 3.6°C

If I use 6.1°C I feel more protected but I’m not taking the hit being under 3.6°C would give me.

 

[electrofelon]

The article posed by solarpro is a good one. The author acknowledges that his method is a little less conservative than what others might use, and he gives very good justification for it. Irradiance is a big one. For some reason many dont seem to view irradiance is a valid factor to consider.

 

[ggunn]

The article posed by solarpro is a good one. The author acknowledges that his method is a little less conservative than what others might use, and he gives very good justification for it. Irradiance is a big one. For some reason many dont seem to view irradiance is a valid factor to consider.

We all consider irradiance, just for different things. For Voc maximum it's not that important because voltage depends much more on temperature, and assuming 100W/m^2 for Voc yields a slightly more conservative design, although the minuscule contribution of irradiance would seldom if ever result in a different maximum string length.

 

[SolarPro]

...the minuscule contribution of irradiance would seldom if ever result in a different maximum string length.

I'm not convinced that will prove to be the case.

To determine maximum system voltage, the NEC has long relied on Table 690.7 or manual calculations based on STC ratings and manufacturer-provided temperature coefficients. In the 2017 NEC a PE is allowed to use simulations to determine this maximum voltage for systems over 100 kW. Compared to the crude tools we use today, simulations use 20-year datasets that account for temperature and irradiance and model performance based on some 30 different coefficients, basically accounting for voltage (and current) at every minute of every hour of every day. My guess is that modeling maximum voltage will have a noticeable impact on string length, in terms of routinely allowing some designs that Table 690.7 does not.

The bigger impact is likely on the current side of things, since that's what drives conductor costs. <i> NEC 2017 <i> also allows PEs to model the maximum 3-hour current average and, within limits, use this for design purposes. While the design value cannot be less than 70% of 125% of the parallel-connected string Isc, that's a big margin of difference. Simulating current is likely a significantly more cost-effective way to design large-scale systems.

These simulation allowances apply to systems over 100 kW. I suspect you'll notice the differences, both in terms of allowable string sizes and conductor costs. But I'm just making an educated guess, I haven't compared any designs side by side. (That would be a cool article.)

 

[Anode]

Regarding what the owner is pushing for, like others have said, warranty issue and code. You will do the right thing by calculating everything and delivering the best design, which is also code compliant.

Of course Voc cannot be ignored. Voc is a key variable in establishing the max number of modules allowed in a string, and Vmp is key in establishing min per string. There are obviously a number of other variables.

I should preface this by saying I 100% support knowing and practicing the principles of calculating manually high TcVoc for code, and adjusted TcVmp low to ensure system operation during usually the peak point, a hot day in summer; but if you want to double check your math when you calculate everything, then you can download a Renewable Energy Associates string sizing tool here: http://renewableassociates.com/design-tools/ You can enter in custom inverters and modules if those aren't in selection, as they haven't updated this in some time. To be honest, I never use these tools, everything is always done by hand, but to hopefully ensure you don't make any mistakes, this tool should help.

Here is another article from solar pro on string sizing:
http://solarprofessional.com/articl...ray-to-inverter-matching?v=disable_pagination

Also in general I would recommenced Mike Holt's 2014 Understanding Requirements for Solar Photovoltaic Systems, which will cover the voc calcs as well, and I think the low vmp also

 

[Carultch]

While the design value cannot be less than 70% of 125% of the parallel-connected string Isc, that's a big margin of difference. Simulating current is likely a significantly more cost-effective way to design large-scale systems.

Where did 70% come from?

Also, do simulations account for a "super sun" of irradiance, in the event that clouds, snow, or other background reflective objects cause the irradiance to exceed the nominal 1000 W/m^2?

 

[SolarPro]

The 70% comes from the Code.

(1) Photovoltaic Source Circuit Currents. The maximum
current shall be calculated by one of the following methods:

(1) The sum of parallel-connected PV module–rated short circuit currents multiplied by 125 percent

(2) For PV systems with a generating capacity of 100 kW or greater, a documented and stamped PV system design, using an industry standard method and provided by a licensed professional electrical engineer, shall be permitted. The calculated maximum current value shall be
based on the highest 3-hour current average resulting from the simulated local irradiance on the PV array accounting for elevation and orientation. The current value used by this method shall not be less than 70 percent of the value calculated using 690.8(A)(1)(1).

Informational Note: One industry standard method for calculating maximum current of a PV system is available from Sandia National Laboratories, reference SAND 2004-3535, Photovoltaic Array Performance Model. This model is used by the System Advisor Model simulation program provided by the National Renewable Energy Laboratory.

What are the design impacts of transient "super sun" conditions? As you can see, the Code is concerned about a 3-hour current condition or the Isc at STC. In other words, short-duration transients in a current-limited system aren't meaningful for design purposes.

 

[SolarPro]

If you want to get excited about enhanced irradiance, you should be looking at bifacial modules. NRTLs certify these at STC, but rear side irradiance can boost power and current well above the nominal values.

 

[Carultch]

The 70% comes from the Code.

Ok, thanks for clarifying. So if you put the array in an absolutely ineffective location, and your simulation yields no more than 50% of Isc at STC for 3 hours or more, you still cannot take credit for any lower than 70% of Isc at STC.

What are the design impacts of transient "super sun" conditions? As you can see, the Code is concerned about a 3-hour current condition or the Isc at STC. In other words, short-duration transients in a current-limited system aren't meaningful for design purposes.

I suppose in concept, a "super sun" condition could persist for longer than 3 hours, where its effects are actually steady state and not transient.

 

[GoldDigger]

I suppose in concept, a "super sun" condition could persist for longer than 3 hours, where its effects are actually steady state and not transient.

Like being on a mountaintop.

 

[Zee]

For some reason many dont seem to view irradiance is a valid factor to consider [in max V calculations].

Exactly.
Many PV installers and designers memorized the mostly true maxim that irradiance affects current, but temperature affects voltage.
I for one learned something today from SolarPro. At the very low current levels near Voc, the weaker irradiance at dawn does have a considerable lowering effect on V .:thumbsup:

 

[SolarPro]

I learned that because we have a very hands-on AHJ here in Austin. For a while, the dedicated solar inspector would measure Voc at the time of inspection in order to verify string length. That's all we'll and good, but if your inspection occurs shortly after sunrise, you're not going to see anything like Voc at STC. In that case, you need to refer to the chart showing Voc at 200 W/m^2, estimate that value then multiply it out by the number of modules in the string.

I think I taught the inspector something that morning. (To be fair, he taught me plenty too.)