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Ryan, nice job. Why do we keep using slang terms in our instructing? I have not found the term sub- panel in the nec. They are distribution fedder panels. Slang helos conguse things and you do such a great job explaining everything..thoughts?
That's a fair point. We do our best to use Code language whenever possible but we sometimes slip in substitute terms if they are commonly used in the industry.
Thank you for the video! NEC 2020 705.12(B)(3)(1) Question....looking to do a solar/battery grid interactive system. Our home has a meter main setup with a 200A breaker. That leads to an interior MLO panel with a 225A busbar. The meter main is a Siemens MC0408B1200RGA. The inverter/charger we are looking at EG4 12KPV and it's output is rated at 33.3A@240VAC | 38.5A @208VAC and it's nominal output is 8000W. Which figure would we use for the 125%? 33.3A for 41.6A? For the busbar rating number do we use the outdoor meter main (200A) or the interior MLO panel (225A)? I would presume the meter main panel? So, we would have to derate the main breaker there to 150A? So, after the above is determined I can use what ever breaker size I want for the backfeed? This inverter has an 80A pass through and I want to take advantage of that.
33.3A would be the value to start with. The calculation would result in 33.3 x 1.25 = 41.6A for the minimum OCPD, which would be the value to use for applying the busbar rules. You are correct that you need to apply that to both panels, so in this case, it would work for the sub-panel, but the main panel would need to be addressed. Downsizing the main to 150A would be a way to make that inverter's output comply with the busbar rules.
I've watched the full interview a few times now, and by a wide margin, it answers the most questions I had about the testing methods vs NEC requirements than any other resource I've found. This one highlight says so much about the divide between what manufacturers are testing for vs what the AHJ wants to see from the tests. Great input here from all sides.
Thank you for the kind words! Battery fire safety/testing is an evolving issue. We were grateful to be joined by other industry experts for the webinar. Keep an eye out for more updates from us over the next few months.
The word propagate is used when talking about spreading or promoting an idea or theory, not a physical fire or anything tangible. Please use a different word when talking about the simple spread of fire or a physical tangible substance. Thank you kindly. I love your work. Keep it up!
Hi Angel, the word "propagation" has many definitions, including transmitting something in a particular direction or through a medium. The UL 9540A standard discussed in the webinar is titled "the Standard for Test Method for Evaluating Thermal Runaway Fire Propagation in Battery Energy Storage Systems" which is why we use that language when referencing the test method and its goals. www.ul.com/services/ul-9540a-test-method
@MayfieldRenewables okay, well, it's spelled "propagation", not "propogation". And, sure if thats what the code states, but aren't we speaking about a tangible substance here? Sound, light, and waves can be argued to be tangible, but either way, there's nothing in the propagate definitions that will allow you to use it when speaking about fire.
@@AngelAnthony. Codes and standards semantics are important for our industry. We encourage you to share your thoughts about changing the 9540A title and language with UL.
I'm in the process of leveling up my skills and understanding to take on large microgrid projects. The resources provided by Mayfield are so nice to have. Thank you! Hats off to your team that creates visuals and design diagrams. These visuals really are a work of art in showing complex ideas in simple manners.
Great video. I'm doing digging into proper conductor and OCPD sizing when integrating transformers into 480v inverters and interconnecting at 208v. I've seen instances where solar design firm #1 will calculate the OCPD based on the calculation "(Inverter VA)(VOLT x 1.732) * 1.25" on both solar and grid side of a transformer. Solar design firm #2 will calculate the grid side different, calculating the OCPD for the size of the transformer instead of the connected inverter capacity. According to code, what is the best approach? For example, I've got an 480v 80kW inverter with a 112.5 kVA 480 to 208 transformer. Thanks in advance. Great content.
The scope of Article 706 includes all energy storage systems with capacities greater than 1 kWh, regardless of where the system is installed. You will always need a means to disconnect your ESS from the rest of the system. Some specific requirements will only apply to residential, namely: “For one-family and two-family dwellings, a disconnecting means or its remote control shall be located at a readily accessible location outside the building.” This is from the 2020 NEC, 2023 clarified the language but kept the specific location for one and two-family dwellings.
That's right, PV module voltage will increase at lower temperatures and decrease at higher temperatures. That's why the maximum dc voltage for a PV source circuit is based on the *lowest* expected ambient temperature.
Hi Ryan, could you explain? why Lower capacity of inverter has max fault current contribution (1 cycle rms) is more than high capacity of inverter of max fault current contribution (1 cycle rms) For example a. CPS inverter model name CPS SCA 36 ktl-DO/US-480 has fault current contribution (1 cycle rms) is 73.2 A (1.68 PU),, while b. CPS inverter model name CPS SCA 60 ktl-DO/US-480 has maximum fault current contribution (1 cycle rms) is 64.1 A (1.6/0.88PU).
This is an excellent question. We do not have enough information on those inverter models to give you a thorough answer. We recommend contacting CPS's engineering department, who should be able to share more details.
Hi Bryan, great question. The lack of a utility connection does not change RSD requirements under the NEC. You'll still need to follow NEC 690.12 language.
Thank you for putting together this video. A certificate of compliance is not a certificate of listing, can you please explain why these are acceptable instead of a certificate of ‘listing’; code requirements is that they be listed.
ru-vid.com/video/%D0%B2%D0%B8%D0%B4%D0%B5%D0%BE-b6kC1K__vBU.html The dashed red line showing the effective ground fault current path should really be drawn all the way back through all the panels until it reaches the inverter's ground fault detection circuit.
That's correct - technically, the module frame would be energized from the fault and the inverter GDFI would pick this up. The dashed red line was chosen for ease of illustration and to show the fault path through earth.
I understand the concept of not having two different grounding electrodes. And having the ground mounted pv racking grounded with the ground rod. But how would you keep the two different grounding electrodes separate. If the EGC goes directly to the inverter, the inverter is physically bolted to the racking which then would be bonded. Also, typically you have multiple inverters mounted to the racking and a AC distribution panel at the array to feed each inverter. Being bolted together assembly they are all bolted together and bonded. Seems difficult to separate those to different grounding electrodes i.e. the ground rod at the array and the ground rod at the service. What are your thoughts? And thank you for the informative videos!
For systems with multiple grounding electrodes, it's considered best practice to bond them directly underground to ensure both electrodes are at the same electrical potential. For example, imagine you have two grounding electrodes on opposite ends of a large ground-mount site. If the electrodes are bonded underground, they have a direct low-resistance path for current to flow between them and for the voltage between the two electrodes to equalize. On the flip side, if the electrodes were only connected by the aboveground EGCs and bonding jumpers, the path for current to flow to equalize the voltage across both electrodes would go through the inverter, array, and other onsite power electronics. Ideally, we want all electrodes to remain at our reference "ground" voltage, which is best accomplished by bonding them together.
Typically the service/GEC are hundreds of feet away from the ground mounted PV array. Seems easier said then done with tying the two GEC together. @@MayfieldRenewables
Great stuff! The other thing to keep in mind, all the reported information that is used in the detailed analysis is also subject to change. Either through load creep or just stacking of estimates. I think the best possible outcome is actually educating the customer on how all these variables interact so they can understand the dynamic nature of microgrid performance.
Excellent point. Education is a huge part of the feasibility study process. It's the key to happier customers and optimal long-term system performance. We talk more about client education in the full webinar, linked here: ru-vid.com/video/%D0%B2%D0%B8%D0%B4%D0%B5%D0%BE-ipFlK7T7TRw.html
That's correct. The example diagram shows a supply-side connection, but what we're focused on for this video is the breaker in the AC combiner panel. In this case, we cite 705.12 rules to properly size the breaker (800A) to not exceed the combined amperage of all loads AND sources on that busbar (750A of source + 40A of load).
Very good video. I see that you didn't address the possibility of using 705.12(B)(3)(3) for protecting the busbar in the supplying panelboard even though the code allows it.
Does UL 9540 apply to off grid hybrid inverters that never feed power back to the grid? You mention UL 9540 applies to grid tied inverters. looking to use EG4 6000XP off grid inverter. With this hybrid off grid inverter will the ESS have to be in a metal enclosure or is the listed ESS able to have a plastic shell?
Excellent question! The UL9540 listing certainly can apply to off-grid systems, but it is not required. NEC articles 706 (Energy Storage Systems) and 710 (Stand-Alone Systems) call out equipment listings, but there are multiple ways to comply. If a manufacturer has listed the *entire system* to UL9540, as it looks like this manufacturer has done with some products, then yes, all the listing requirements would be applicable. The updated standard does require the ESS to "employ an enclosure of non-combustible materials." Essentially requiring metallic enclosures. It would be up to the listing agency to deem what enclosure that applies to (cell, module, or unit). Therefore, the case holding all the modules may not be required to be metallic if the individual units are in a non-combustible material and properly evaluated for (lack of) fire propagation. It is also possible to use a non-UL9540 system by installing listed components together by complying with Articles 480 and 705 for an off-grid system (as well as other articles as applicable).
Thanks for asking this! Of the 20+ cut sheets submitted to my AHJ the solar plan reviewer noticed the EG4 6 space rack spec sheet was missing. I asked EG4 and there is indeed a manual. Hopefully the AHJ is okay with this “metal enclosure” - it’s only “listed with” in ESS context for UL9540 the 18kpv but I’m using two 6000XP. I guess this means it’s not a listed ESS. But is it okay without the rack? Seems very dangerous. The code is so confusing. My suspicion is that it was driven by profit and not safety. Tesla and utility lobbyists have their hands all over the code and it’s becoming a problem.
We built an off grid cabin, we are having a bad time trying to find a system that is certified. We are in ontario Canada and we can seem to get a straight answer from anyone including the inspector. Feeling lost.
For 705.12(B)(3)(1) and 705.12(B)(3)(3), as I understand that we can place the breakers of the PV inverters anywhere in the bus for both codes. So when should we apply 705.12(B)(3)(1) or 705.12(B)(3)(3)? I am thinking to apply both codes and then select the lower bus rating (for cheaper price)?
705.12(B)(3)(1) is applied when the sum of the two sources (PV and the grid) does not exceed the busbar rating. E.g., a 225A rated busbar protected by a 200A main overcurrent device. This would allow you to put up to a 25A solar interconnection breaker anywhere in the panel. 705.12(B)(3)(3) is applied when the sum of all the breakers (both sources and loads) does not exceed the busbar rating. E.g., a 225A rated busbar with ten 10A breakers installed. Now you have space to install up to a 25A solar breaker, since the sum of ALL breakers would not exceed the busbar rating.
For 705.12(B)(3)(3), does it matter to the 80% rated and 100% rated breaker? For example, if the inverter output current is 100A. Then we can use either 100A 100% rated breaker or 125A 80% rated breaker. And if a panel board has 5 inverters and 1 load of 40A, then in the case of using 80% breaker, the bus is >= (5*125+40)=665A. In the case of using 100% rated breakers, then the bus is >= (5*100+4)=540A. So, can we select 550A bus if using 100% rated breaker?
Code doesn't differentiate. Default to the rating of the breaker: if it's a 100A breaker, use that in your calculations. If it's a 125A breaker, use that instead.
Thanks for the video, I would like to see NEC 2020 690.31(C)(4) and the corresponding Table 690.31(C)(4) explained further in regards to the code's intent of the word "connected" in that section.
Thank you for the suggestion! We will add this to our list of Code Corner topics to cover in 2024. Subscribe to our channel or follow Mayfield Renewables on LinkedIn to get updates whenever we post a new episode.
Hello Sir, I find your videos very interesting. I also watch your blogs on the website. I just wanted to know if there is any chance to work with you. Like I have 4+ experience in the US solar designing field.
We do not have checklists, but we recently partnered with Megger on an Electrical Testing Standards Guide which overviews some of the key tests performed during commissioning, inspection, and O&M. You can download the guide here: us.megger.com/promotion/download/electrical-testing-standards-guide
Is PVC schedule 40 conduit allowed to be used inside a home from roof to central inverter? I have a HO who is a contractor and he said that PVC is allowed in code.
Thanks for the comment. The new exceptions are also specific in eliminating some of the conductors we must control. The first one eliminates circuits within free-standing structures from the entire 690.12 requirement. The second exception then goes on to say for circuits from those free-standing structures that remain outside a structure, we are not required to control those conductors. So, as long as we don't enter the building with those PV circuits, we'll meet the 690.12 requirements under the 2023 language.
So, explain how megohm meters work on THHN/THWN-2 or XHHW-2 insulated conductors in PVC raceways. If everything is "Insulated" and non-conductive. Would love the explanation.
Thank you for the suggestion! We typically focus our content on our areas of expertise - solar PV, energy storage, and their relevant codes and standards. You can find more of our content on our website: www.mayfield.energy/technical-articles/
