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0:08
I will give this just a moment, then we'll get started.
0:25
All right, we're at the top of the hour. So thank you, everyone, for coming to our technical share here. Our monthly event honor. Today's topic will be Short Circuit Back to the Basics with Madison Stark and Ian Hutt.
0:45
As you go ahead and advance the slide and we'll get started.
0:48
All right, so back to basics. Just a quick rundown for Madison. Madison is a five-year engineer at Commonwealth. She's got a background in physical design and in system studies. And she's going to go over our short circuit calculations and just kind of do like a refresher reminder for those that Haven't had a lot of experience in this area. And we'll take questions in that polls as we go through. So with that, Madison, take it away.
1:18
Thanks, Ian. So just a quick intro to what we're going to go over today. This is really hitting back on, or for some people for the first time, on what is a short circuit? What are the faults both electrically and physically? How do these faults impact current and voltage in the system? And then how does that impact the equipment, both interrupting equipment and non-interrupting equipment? And then
1:46
overview of generator short circuit contributions, and then also a little bit of insight into short circuit studies, what they are and why we do them.
1:59
So just right off the bat, getting into the super fundamentals of what is a short circuit fault. So power system faults exist in two categories. You have open circuit faults and you have short circuit faults or closed circuit faults. Open circuit faults are discontinuities, short circuit faults or unintended popularities, and then those branch out into symmetrical faults and asymmetrical faults, and then each of those categories has some types in them as well.
2:31
So today we're going to be focusing on short circuit faults. We're not really going to touch on open circuit faults.
2:42
So, at its core, a short circuit fault is when you have an electrical current from your circuit that travels along an unintended path to ground with no or very low electrical impedance compared to the system as it did. So key points of this definition is that the electrical current from your circuit is traveling on a path that you do not intend for it to travel on, hence the fault, and that this path is of a lower impedance or resistance to ground than the rest of the circuit.
3:16
So there's four main types in order for most to least common. You have a single line to ground fault, a line to line fault, a double line to ground fault, and then a three-phase fault or three-phase to ground fault. We'll get into each of these a little bit later. So these are different from open faults, which is the other category of faults in the system. Open faults is when you have a break in your circuit and the current can do a longer flow. Short circuit faults is when you have an
3:45
additional line in your circuit that you don't want the current flowing so long. So that's the difference there. We're only puddling short circuits today.
3:54
In that short circuit, you have asymmetrical and symmetrical faults or unbalanced and balanced faults. A balanced or symmetrical fault is when the fault current is the same across all phases of your system. An unbalanced or asymmetrical fault is when you have phases that have higher fault currents than other phases, and the reason why it's broken down this way is the calculations for short circuit values are different based on the symmetry of the fault itself.
4:28
So that's why they're divided up that way. Of note, the faults we're going to be talking about today are for three-phase systems. We operate mostly in the three-phase world, so that's where we're going to be spending most of our time.
4:41
So the first fault is a single line to ground fault. This is by far the most common fault that you'll see. 70 to 80% of all faults are in this category. So this is the heavy hitter. And it is exactly what it sounds like. A single phase in your circuit connects to an unintended electrical path to ground. This is typically the lowest fault current that you see of all the different types of faults, but the actual magnitude of the fault is
5:10
very dependent on the impedance to ground and the new electrical path, as well as the system's overall grounding and configuration. This is the first in the unbalanced fault category, and it's unbalanced because you only have the one faulted phase. So that one phase that connects to ground has the highest fault current value, and the other phases don't really see that fault current.
5:36
Oh. So electrically, this is what it looks like. You have your to orient you to my to my graph. You have your one, two and three phases with two neutral. So this is a three phase system with a neutral. And then a single line to ground fault. You have a point of continuity through some impedance. to ground and this right here is your fault. That's it. Pretty straightforward. Just a connection to ground outside of your circuit configuration.
6:07
A line to line fault is the next one. This is the next most common accounting for 10 to 15% with the faults. So this is when two phases of a three phase circuit connect unattentionally. There's no ground component to this fault. It's just two phases. This is also an unbalanced or asymmetrical fault. because the two faulted phases are the only two that experience that fault current on the higher fault current magnitude. The unfaulted phase does not see that fault current.
6:37
You also get the voltage drop that you see in fault conditions on the faulted phases and not so much on the unfaulted phase.
6:46
This is a pretty straightforward one. Electrically, what this looks like on our same circuit is that you have a continuity between two phases that is outside of your planned circuit continuity. So this is your load. I. This is where you want them to connect, but here you have it.
7:04
elsewhere. This does not have to be between phases two and three. A line to line fault can be between any two phases. So one, two or three in any order or combination. What it is not is a fault to neutral. Because the neutral is not considered a phase, it's a separate part of the system that would not be aligned to line fault, that would be aligned to
7:31
The next fault is the two line to ground fault, which again is exactly what it sounds like. This is just two phases of the three-phase circuit that connects unintentionally and then they also connect to an unintended electrical path to ground. This frequently can start as a line to ground fault that then escalates to a second phase. or even as a line to line fault, but then connects to ground.
7:57
These are typically higher fault lines than what you see in a line to line or line to ground fault. But again, it can really vary in magnitude based on the system grounding configuration and the impedance of the fault itself. This is an unbalanced asymmetrical fault. Similarly to the line to line fault, the only phases that will see that fault planning are going to be your faulty phases. So...
8:27
They will see the fault, and then your unfaulted phase will not see the fault.
8:35
and electrically.
8:37
It looks like this looks very similar to the 2 line, the line, the line fault, and it also looks like the underground fault where you have 2 phases connected, and then that in turn connects to an unintended ground.
8:51
So pretty straightforward. Again, it can be any two phases connected to a ground. It doesn't have to be phase two and three.
9:01
And then the last fault that will cover is a three base fault. So a three base fault and a three base to ground fault are technically slightly different, but in the case of a three phase symmetrical fault, the ground component has minimal to no impact on fault current magnitudes. So, these phases, these these three phase faults in the study are generally treated as what I'm going to say. This is the balanced fault. This is the balanced fault.
9:32
All three phases see the same fault for it. So it's easiest to do the math for, honestly, because it's balanced. But this is the worst case fault scenario. The three phase fault typically sees the highest full current values, which is why obviously generally a limiting factor for equipment and system ratings.
9:56
This type of bolt in particular can cause significant voltage drop and even voltage collapse in the system. Thankfully, they're relatively rare, really only about 2 to 3% of all faults typically fall into this category, which is good because it's the worst case scenario, so we don't want it to happen the most. That would be disastrous. Yeah, this is the easiest one to do math course, so you love that. And this is what it looks like electrically. So you have the tie between phase one,
10:27
three and two or one, two and three. Can hit the neutral, doesn't have to hit the neutral, can hit ground, doesn't have to hit ground. The biggest Part of identifying A three-phase fault specifically is that all three faults, all three phases are faulted.
10:48
So what does this look like in the real world? Well, it could look like many, many, many different things. There are an unlimited number of things that can cause faults. The one that I like to use the most for describing what a fault looks like and what fault conditions look like is a tree falling.
11:07
This picture right here highlights a really good example of a single line to ground fault. So the tree fell, which is a three-phase power system. You have phase one, phase two, phase three, not necessarily in my order. And the tree fell on one of the phases, creating that unintended plastic out. You can see that the current is running through the tree because the tree is on fire. Ohh. But this also shows how faults can escalate from one fault to multiple
11:33
faults. So if this tree were to fall just a little bit more and touch that second line, well, now you're going from a single line to ground fault to another line to ground fault. If the tree had fallen across the lines in a way that it only touched two of the lines, well, then it would be a true line fault. If it had felt perfectly across all three phases, then it would be a three-phase fault.
11:59
Another really common example of what causes faults, especially in transmission systems, is lightning strikes. So that can be a direct strike on the power system, or it can even be a near miss that can cause a fault. As the lightning ionizes the air, this allows for a decreased inflammation in the air, which allows current to travel from the exposed conductors to ground. So even if a lightning strike doesn't directly hit cables or conductors,
12:28
it can still cause a fault in the system, which is why lightning production is so important.
12:35
Another truly common example of what causes faults is insulation damage in cables. So 2 main ways that this can happen. One is just breakdown over time and in austere conditions. So weather, time, water, sun, all cause breakdown on cable insulation. over time, if that installation wears down enough, it can create an unintended continuity either between 2 cables or between a cable and ground, which it's a call.
13:08
Another way that this can happen is through damage to the insulation. So if you have underground cables and someone digs, the damaging of that insulation and causing that conductor to then be exposed to the earth or to another conductor is what causes the actual fault.
13:27
When you're wondering why you have to call before you dig, this is why.
13:32
And like we were talking about with the tree scenario, a single fault can cause fault escalation. So part of why it's important to clear faults quickly is if I have a single lined and round fault, say this tree for example, and this causes the tree to burn and then that top part falls apart. part from the bottom part, now it bridges those two conductors. Well, now I'm on a two phase bolt rather than a single phase bolt.
14:02
With the cable damage example, if I have insulation that breaks down and then that single conductor starts carrying a fault and that causes higher operating conditions, it's going to cause more rapid breakdown than the insulation neighboring to it, which might eventually cause both of those cables to fault and be connected. So just because you start with a single fault doesn't mean you're going to stay with a single fault.
14:27
So it's important to understand how these faults work in the real world and how to prevent them from escalating further. And that's why the protection system is important.
14:37
All right. First learning objective, the first check on learning, Ian.
14:43
Yeah, let's go ahead and ask a question. So which of the following is not a short circuit fault? A three-phase fault, line to generator fault, a fault, or a line to line fault? Please select your answers and hit submit.
15:11
Alright, so I think this one was pretty straightforward.
15:14
So we've got a line to generator fault is the overwhelming response. And Madison, I believe that's correct. Yes, absolutely. Your line should go to your generator. If your line doesn't go to your generator, you probably have bigger problems in your system. But these other three are all examples of faults, and then the last fault would be your two line, the ground fault. So good job, everyone.
15:39
So how do these short circuit faults actually impact the system? What is the impact that we see?
15:48
So, the first part of analyzing how it impacts the system is analyzing what it is electrically, and a short circuit fault is a nearly instantaneous change in the system conditions through the introduction of a low impedance path to ground or to another phase. This introduction of the low impedance path. then causes a change in the
16:13
and the potential difference in the system, creating a path to ground with a lower potential difference than the overall system. That potential difference that you're talking about is your system voltage. So as that potential difference goes down, well, now you're going to see the correspondence increase in your system voltage. So there's two parts that you see coming out of the short circuit fault. You're going to see increase in current, and then you're going to see a decrease
16:38
in your system voltage.
16:41
This change that you're going to see is going to occur on your faulted phases a little bit.
16:48
Now, this short circuit current that you see is going to be comprised of a steady state component and a transient component. So the steady state component is considered the AC component or the alternating current component. And then the transient component is the DC component or the direct current component.
17:06
When you put those two components together, you get the total asymmetrical fault front. We just talked about symmetrical and asymmetrical faults. This is not to be confused with that. This is something different entirely. So this is asymmetrical fault current and symmetrical fault current components. Those are symmetrical faults.
17:26
A little note down here. If you're not real familiar in the electrical world, impedance is how much the circuit closes the flow of current and system.
17:38
So this is what a fault waveform looks like graphically. And here you can see your asymmetrical component is this red triangle Two.
17:45
highlighted, and then the symmetrical component is this envelope in the blue boundaries.
17:52
With a non-faulted AC system, the voltage and current waveforms are going to be symmetrical about the X-axis. This is your X-axis. Your positive peak and your negative peak are the same, which is why it's considered symmetrical. With the introduction of a fault, you have a system that is opposing change, and that the opposition to change is what drives the DC component of the fault, and that creates this asymmetrical offset.
18:27
So it's not even necessarily that this waveform is bigger, can be, but the bigger part of this is that the waveform shifts vertically on the axis, which then creates a positive or negative peak depending on where the fault hits. But it creates a magnitude of current that is higher than what the system would see. So this right here is the asymmetrical component, and that's what creates that initial very high peak of default current.
19:03
What influences it? There's a number of, there's a lot of things that influence it, but some of the key components that you're really looking at or what influences short circuit. The first is the system X / R ratio, which is the ratio of system reactants to system resistance. In a system that has a high X / R ratio, you're going to see higher and longer asymmetrical fault print. So that asymmetrical current component is that DC component,
19:33
that offset that you see. And that is really heavily impacted by the X over RR ratio.
19:41
Now, on the other hand, the system impedance is just the overall system impedance, the combination of the reactance and resistance. The higher that impedance is, the lower your symmetrical current component.
19:56
So to go back to this other graph, this blue part right here, the width of that blue part is impacted by your system impedance. The height and the length of this red component is impacted by your system X or RR or your reactance to resistance ratio.
20:16
Another key component that can impact, especially ground faults, is how you ground your system. A solidly grounded system is going to have higher ground fault currents. An alternate grounding system, like a delta configuration or a mutual grounding reactor, or you know, high means ground. can reduce ground fault currents. These can be used together in combination with other themes. They can be used to reduce the fault current a lot or little depending on the system configuration.
20:47
But a solidly grounded system is going to see higher ground fault grounds than a non-solidly grounded system. Of the people.
20:57
Other variables.
20:59
And the last one, that's a pretty big influential factor, it's pretty straightforward, system voltage. The higher your system voltage, typically the higher your fault current. Your system is starting out with a higher potential difference. So as your system falls to ground, it falls to another phase and that potential difference closes, your system can reach higher ground. just the three correlated in that way.
21:25
And this is getting them to the actual waveforms. So when we're talking about, we're looking at our system, our system has a fault. What is actually happening to those waveforms as the fault occurs? So all the way to the left here, this is your three phase steady state voltage and this is your three phase steady state frame. Right at this line right here is where the fault occurs. So we have a fault that pits. This is a single line to ground fault like that tree branch in the picture.
21:58
And this faulted phase, which is the B phase, the voltage plummets. It goes way down as that difference to ground closes. And then it also pushes higher fault current because now it is pushing all that current through that min path to ground and the current of that phase sees goes way up.
22:16
And if you notice, the other two non-vaulted phase, A& C in this case, kind of remain unchanged. They don't really see like a big impact from that fault.
22:30
This is a line to line fault. This is actually the second half of that previous graph. So what you see.
22:37
Here is.
22:41
You have two faulted phases, which are going to be your A and B phase, the pink and the yellow, and then your current as well, the red and the yellow. So your current is going to increase in both faulted phases and your voltage is going to decrease in both faulted phases.
22:58
And then right here, if you're wondering why it goes to zero, this is when we're protecting the by strips.
23:07
This is a double line to ground fault. Now, if you notice, this is your current up top and abilities. This is incredibly similar to the waveforms that you see on a line to line fault. very similar on the double blind ground fault. The actual change in magnitude within these two different types of faults is Yeah.
23:26
really going to depend on the system grounding and the impedance of the fault itself.
23:34
And that's really what's going to impact the magnitude. The grounding faults in general, the magnitude of those faults is more heavily influenced by a system configuration than the more face-to-face faults.
23:47
And then this is a three-phase fault. So what you see here is this voltage is actually taken further away from where the actual fault occurs. So in your current, you have pretty much symmetrical rise and current across the three phases. And we can see here what's happening is this is the fault and then the fault is ending.
24:08
And then your voltage, as the fault occurs, your voltage drops, and then as the fault is cleared, your voltage fits back up. So this isn't actually at the fault site itself. This is what's happening somewhere else in the system when there is a fault on the system.
24:22
So it's interesting perspective to see. But the big thing about three-phase Yeah.
24:26
faults is that you see all of the phases are responding evenly and symmetrically to the fault as it is those.
24:35
Okay, learning objective two, check on learning.
24:40
All right, next question, Amy will answer all.
24:45
questions that are in the chat and the Q&A at the end. So just a heads up, we will make sure you address those. Question #2, in short circuit fault conditions, the voltage blank and the current blank. So does it increase or decrease? Select your answer and post in the chat. I post in the the poll. Thank you.
25:13
All right, answers are coming in.
25:17
Overwhelmingly, the voltage decreases and the current increases. Presten.
25:24
That is right. That is exactly what happens in the system.
25:30
Perfect.
25:31
OK, now short circuit equipment ratings.
25:39
The first part of understanding short circuit equipment ratings is understanding what part of the short circuit fault these ratings are referencing.
25:48
There's 3 different short circuit values that we generally talk about. We have your instantaneous. This is your red block right here. And this is a half cycle. This is the peak magnitude of short circuit fault. This is the highest fault current that you're going to see on this fault. Then you have the magnitude. So this is one to three cycles after the onset of the fault. Excuse me. This is when you're seeing a partially decayed asymmetrical current, but it most likely has not fully decayed.
26:16
And then you have your short time current, which is 5 to 30 cycles, so up to about half a second. And this is almost exclusively the symmetrical current value. By the time you're getting into your short time, you have decayed your asymmetrical current and you are just at that short time steady state fault.
26:36
For interrupting equipment specifically, you have two main ratings that tie back to those parts of the fault. So the first is the interrupted rating and this is given as typically given as a symmetrical RMS current. Can be provided as asymmetrical or both. Um, but we're almost always gonna see the Simmonds to go on.
27:01
This is really talking about how much current can this interrupting device interrupt, basically. So the terminals of the interrupting device have to open in order to separate the fault, and this is how much symmetrical RMS the device can interrupt without having parking or other failures in the system. Sure.
27:24
You then have the second rating, which is the closing latch. The closing latch is the maximum asymmetrical peak current. So peak current, not armist, that the breaker can close onto and remain mechanically latched. In layman's terms, this is the highest first cycle current or that half cycle peak value that the breaker can physically survive. If it sees higher than this current, this close and latch rating at that peak current value, most likely the breaker will mechanically fail.
27:59
Of note, the RMS, or the root mean square, is the peak wave value divided by its square root of 2. And it's a DC equivalent power rating to an AC waveform. The reason why we use it is it gives you a single value to work with that encompasses the power of the waveform. rather than having to deal with like a time birth or for this mathematically it works out. So these are the two ratings that you're seeing. This interrupting rating is going to be
28:31
given typically in symmetrical RMS and then this close and match is going to be your symmetrical peak.
28:39
For non-interrupting equipment, you have to. You have your momentary withstand and then you have your short giant stand. So your momentary withstand really relates back to that closing lap rating or the instantaneous momentary peak break. This is the maximum asymmetrical peak. current of the equipment can survive during that first cycle. Again, you're protecting against mechanical failure of the equipment. So when you have that really high first inrush current,
29:11
you have that current causes magnetic fields. The equipment is generally made out of metal. So when you have a really high magnetic field forming from this really high inrush current, it can physically bend the metal of the equipment. Now, the manufacturers know this. and the equipment is built to withstand it, but this momentary withstand rating is the amount of magnetic force, basically, that it can withstand.
29:40
The short time withstand is the maximum RMS current that the equipment can carry for a specified duration. So this is RMS, not peak current value, and the time it must be specified. So the typical times for regulation are generally from a half second to three seconds, and this short time withstand is designed to protect against thermal damage from prolonged high current.
30:04
Current going through conductors causes heat. It generates heat through the resistant losses in the conductors or the equipment. When you're overloading your equipment, it can only handle so much before the equipment is going to overheat to the point of failure. And that's what the short time withstand is addressing. The key component of the short term withstand is that the time is defined.
30:28
It's not a thermal rating of the equipment. It's a short time to come at the rating of the equipment.
30:34
Why that matters is when you get into these two ratings. So for ratings that don't, for equipment that doesn't really fall into either the other two categories or they just don't typically provide those ratings, you have your thermal withstand and your mechanical withstand. So your thermal withstand really goes hand in hand with that short time, where you're talking about the allowable temperature rise for a defined period of time, Two.
30:57
or over a period of time, how a defined period of time, that a piece of equipment can withstand. And this is based on the heating from the current and the resistance. So this is R squared of all our heating. Again, the point of the thermal withstand is to protect the thermal limits of the equipment.
31:16
The mechanical withstand is very similar to the closing line training and to that momentary rating where you're looking at the maximum instantaneous peak current. That peak current correlates the magnetic field. The magnetic field is what's going to bend your equipment or warp your equipment.
31:35
So this ties back to the equipment, structural integrity, the physical construction of the equipment and how that relates to the current.
31:49
So this is just a quick summary of what equipment is going to see, what ratings and what you're looking for, equipment or what you're going to have to specify for your equipment.
31:59
So this is general, this is typical. For breakers, you're going to have interrupting and close a match. Both of those are important to be evaluated for your system. For fuses, you're really only going to have your interrupting. There's not like an amount of current that you need your fuse to survive. It's really, you need your fuse to trip, basically, and then that's for your fuse. Switch gear, you should have both a momentary and a short time that goes for switchboards as well. Um...
32:25
Excuse me, both of those are important. The momentary actually is really important and then the short time for your profile protection for your buses in your first year. Your disconnect switches, you're typically only going to get a momentary rating for them, which is like the magnetic field component of them. They're not typically going to see a short time. You can see a short time, which is great. If you have that short time data, like absolutely compare it and validate it, but really
32:50
What you see through them is typically the momentary rating.
32:55
Transformers, you should get both a mechanical withstand and another oil stand. It's important to evaluate both of them. You don't typically get the actual short time rating on your material rating for them, but you still need to understand how that overcurrent affects the thermal capabilities and the mechanical capabilities of the transformer. And then conductors. Conductors typically only come with a thermal withstand, and this is going to be related to the installation of the conductor.
33:19
and how much of that over plan it can handle and the follow.
33:25
But those frequently come in very different ratings. You might see 24 hours, you might see 12 hours, you might see 30 minutes, you might see 2 minutes.
33:35
So it depends on the conductor for that one.
33:38
All right. Learning objective three.
33:42
All right, for the next one, the momentary rating of equipment refers to equipment's ability to withstand which of the following? The maximum asymmetrical peak current first cycle, the maximum RMS symmetrical current, high operating temperatures, or temporary overvoltage? Submit your answers in the poll.
34:14
Answers are coming in.
34:25
All right, we're a little split on this one, but it looks like the maximum asymmetrical peak current for the first cycle is the leading response. Madison? That is correct. So momentary rating, if you think about it and you're thinking of a way to remember it, momentary, short term, very short. What is the peak current, the absolute max value for a really short period of time that this equipment needs to withstand? When you're looking at your maximum RMS symmetrical current,
34:57
that's when you're looking at your short time withstand or the duration. For high operating temperatures, that's a completely different conversation. Could relate back to thermal withstand, but it's really a different conversation. And then temporary overvoltage is actually kind of the opposite of what we're looking at here were short current faults probably voltage drops. So we don't have to worry about that right now.
35:23
All right, generator short circuit contributions.
35:28
Why is this needed? So this is a question that me as a baby engineer, I was like, short circuits are bad. You don't want to higher short circuit values. You want to lower short circuit values. So these generators pushing current, well, that must be bad and we want to limit that. And that would be incorrect as my power teacher. So finally informed me. So short circuit currents cause voltage drops. When you have that increased current, your voltage in the system is going to drop. Your equipment,
35:58
both generators and loads, does not want to operate outside of nominal voltage. So they have a range that they're defined to operate up, and that's all they want to do. So when you have these currents causing voltage drops, you can start to have stuff drop offline. So your generators will drop offline to protect from the voltage. You may have large loads drop offline to protect from the voltage. So the generators then When they push current and they're forcing that current into the system,
36:30
what they're doing is they're helping prop up the voltage. And they're propping up the voltage for long enough that the system remains online and those faults can kind of get controlled, either removed or shut off or alleviated.
36:46
And what this does is it allows the grid to remain synchronized and connected. What we're really trying to prevent with that is cascading blackouts. So 2003 is the most famous one. This is really the birth of a lot of New York regulations in general, which govern all of this conversation, but.
37:06
How this happens is I have a short circuit fault. Oh, my voltage drops. Okay, well, this generator that's right next to the fault sees the worst of the voltage drop. Well, now he's going to drop offline. Okay, but now because he dropped offline and he's not pushing current anymore, the voltage drops further. And then the next generator drops offline. And you see that cascading, that domino effect, And by having generators push current for a period of time,
37:30
you can prop the system up just enough that the fault can be remediated and the grid doesn't have this cascading failure effect.
37:39
And a different note, higher fault clients can also help improve coordination and protection. So if I have a fault that's only 10% higher than my nominal current value, that's going to be really hard for my system to detect. It's really hard to know, is this a fault? Is this a motor coming online? Is this...
38:00
somebody plugged their charger in like what exactly is happening here? I don't know. Now, if I have a fault current that's 410 * 20 times my nominal current rating, then well, I know that's a fault and all my protective systems know I gotta trip. I gotta protect this. I gotta get that fault off the system. So Having those kind of fault points allows for easier identification of faults as well as appropriate zoning. So if I have a fault that high fault
38:27
current here, well, this relay is going to see it first, it's going to trip, and then I don't have to worry about cascading. With much smaller faults, it's harder to differentiate, and that can cause confusion or muddling.
38:40
In the coordination.
38:44
So synchronous generators, how do they play into this? They have historically been the heart of our generation system. So their contributions are based on the transient and sub-transient reactance of the generator, and that is a physical property of the generator.
39:00
They tend to have high X over R ratios, which allows them to have a very large DC offset with a very high asymmetrical peak current. So bring your thoughts back to that graph that we looked at earlier, that first peak is going to be very high for a synchronous generator. So it can reach up to 4 to 8 times the per unit. Um, nominal reading with the generator.
39:24
Which is very good. Now, after that initial push, that big symmetrical peak current instantaneous value, you have the AVR or the automatic voltage regulator working in the generator. And what that voltage regulator is going to see is that the system voltage is dropping. So It is, in turn, going to push excitation current, which is how we control the output of the generator, and that excite that rising excitation current,
39:50
that pushing excitation current is going to force the generator continue output current into the fault.
39:57
So this is going to occur also on a short-term basis. This is the transient rate of default, so three to 30 cycles.
40:05
By the end of that 30 cycles, which is around a half a second, the generator really needs to return to steady state operation to protect its own physical capabilities. So when we're looking at this and we're looking at how this contributes, we also have to understand that the generator protective equipment, so everything between the generator and the grid, the breakers, relays, transformer, transformer protection needs to be able to withstand the grid fault client should that come get pushed in,
40:32
as well as a generator fault client getting pushed out to the grid, which can be pretty significant and can require significant short circuit ratings for those generator systems.
40:45
This is what the output of a synchronous generator might look like during the fault condition. So, this is that very high, almost 8 per unit amplitude that you see, and then this increased waveform that kind of drops back down to that that symmetrical or steady state fault value. This is from the AVR pushing for it back to the. Then you look, this is about 1/2 a second. It's about 30 cycles duration of the whole fault before it goes back into just
41:15
normal steady state operation. You see there's a drop off here, but then it resumes very quickly and that's just the system recovering. So this is what you'd expect to see. It might not always be this high. It might only be about four per unit up to 8 per unit for the generator, but eight is about the highest that they expect to see.
41:34
Now, asynchronous generation, specifically inverter-based resources, is a little more complicated because these IDRs or inverter-based resources are current limited devices. They don't have the capability to push eight per unit of their nominal. current in fault conditions, they can't, they just can't do it. So what they have instead is ride through requirements. And these ride through requirements kind of govern how long they have to be in
42:04
operational in fault conditions before they're allowed to trip.
42:09
So a typical inverter can see anywhere from a 1.2 up to 1. 5 short circuit contributions in fault conditions, typically up to about 30 cycles, similar to the similar to the synchronous generator in that different frame. But what you don't see with this is that that peak value and then the of that sub transient happens into the more steady Yeah.
42:35
state. You just really see that steady state fault in the Asian British generation. What the actual contributions are are going to depend on the number specifically, but C2800 is the governing regulation for inverted based resources connected to the grid. So that's your best reference for that.
42:57
And this is again what you might see. So this is very, this is probably about that equipment rating where you have that limited per unit value of the current output, and you see a slight voltage depression during that fault condition, but still within capabilities. And then again, this is, this is actually only for about 0. 3 seconds. So, maybe the fault cleared right here, and that's why it shut off, but can go up to about 1/2 a second from 30 cycles for that. Okay.
43:26
So this, the introduction of inverted-based resources in the grid can cause some complications for this exact reason, where you have lower fault current contributions, which are reducing that grid voltage support in fault conditions. So because they're pushing less current, you don't have that current propping up the voltage in fault conditions that you see in the desynchronous generation. So lower fault grants can also cause complications like we talked about
43:55
earlier, especially in older protection schemes. So you have some plants or generators or whatever, they've been around for a while and their protection schemes are shaped around synchronous generation. So as the market share shifts towards synchronous Resources that peak fault current available at each site is potentially going to decrease if you're going to require revision to protection schemes, especially with oversights.
44:22
And what that can ultimately cause is delayed fault clearing and then also problems with zones. So when you have your protective zones for your faults, like A is supposed to protect A, B is supposed to protect B, C is supposed to protect C, you might see things tripping out of sequence, which is going to result in more things being awful on you need to be. Um...
44:44
Something that exacerbates that as well is distance between generation sites and load centers. Longer transmission systems by default, you have higher impedance, so you're going to reduce fault period, especially at the load, because that load is seeing the full system impedance. So it's going to be
45:03
It's going to be decreased there. And this is especially problematic for the inverter-based resources because they already have much lower bulk current connotations. So the further they are from their load base, the more that problem is going to be exacerbated.
45:18
This is not to say that it's not doable and absolutely it should be continued to be leaned into and work with and integrated into the grid. It's just something that when we're planning these protection schemes, we kind of have to rethink how we do it now and like reshape some of the the long standing expectations and traditions for protection and coordination efforts to make sure that we are. um protecting the system as it currently exists in the future changes.
45:45
jumping forward.
45:47
All right, so synchronous generators can reach up to how many times their nominal rating during the sub-transient or instantaneous fault period?
45:59
Options are two times, one-half times, nominal rating, 8 times, or twenty-five times.
46:07
Select in the poll.
46:10
Hit submit.
46:14
Responses are coming in overwhelmingly 8 times nominal rating.
46:21
Fantastic. That is absolutely correct. So 2 is about the peak that you'll see for the absolute highest really that you'll see for inverter based resources. One half, that would be devastating for the grid. So let's hope that doesn't happen. And then 25, 25 times your nominal value would be incredibly hard to design a system around. So 8 is probably a good number.
46:46
All right, last learning objective, the ins and outs of the short circuit study. So short circuit study is, I think, maybe a little bit of a black box as to what expectations are and what you need and why do you need it?
46:59
So, one of the first things that we need to do an accurate short circuit study is grid contributions. So, the two things that we need for that really are default availability. So, what is the magnitude of the fault current that the grid can currently produce at that point of interconnection? or POI, and then the grid X over RR. So what is the reactance to resistance ratio of the grid? Because we do our calculations and we per unit primarily, I don't need to know the actual impedance.
47:33
Just knowing the X over R ratio is enough. What that X over R ratio kind of tells me is in part how stiff the grid is and how responsible it is to false.
47:46
So, the system design is the other really important part of a short circuit study. So, this includes the configuration of the equipment as well as the equipment specifications. In large part, I'm looking for continuous current rating. I'm looking for those, the respective short circuit current ratio or ratings for each of the PCBs. equipment. And I'm looking for a location of the equipment relative to other equipment. Then I'm looking for cables and
48:13
conductors and transformer impedances. That's a really important part as well because those impedances are going to cause losses in the short circuit. That's going to affect what we see. It's also going to affect how the short circuit hits other equipment at the site.
48:27
Inverter short circuit contributions. If you have inverters on your site, you need to know how much they're contributing to that fault. It may not seem like a lot, but that coming in can push equipment Yeah. ratings over the edge or keep it under depending on how much they're actually rated to push. All interrupting protected devices. Obviously, you need their interrupting ratings, you need their withstand ratings.
48:52
And then generators and motors. If you have generators and motors on your site, you really need their transient sub transient reactances because those two values are going to determine what their short circuit contributions are to the grid. And that's going to determine what those peak values look like. Generators especially are very influential in short circuit studies. It.
49:13
Yeah.
49:14
And then motors, especially noted, have the ability to push short circuit as well. So they also need that information.
49:24
So what do we get out of a short circuit study? Fault current values, obviously. So this is all of your closed fault types that we talked about. You get your X over RR ratios seen at each voltage level of presentation. So why does this matter? I actually think I saw a question about But.
49:42
this part of so. Interrupting equipment is tested at a specific X / R ratio. If your equipment x / r exceeds the x / r ratio.
49:55
That you have a if if the site X / R exceeds the equivalent X / R, then you're going to have to derate your breaker capabilities to reflect that increased rating. The you can also use X / R ratios to calculate DC offsets. Sometimes that's a specification that you can provide to manufacturers that you're looking for a specific DC offset. in your equipment or that you're looking for them to test a specific X overall ratio that exceeds the normal testing specifications and something that's
50:23
something you can get to manufacturers.
50:26
Another thing is the interrupted duty analysis. So you're really answering two questions with your interrupting duty analysis. Can my interrupting devices actually interrupt the current that's available, default current, and that's based on the symmetrical RMS current? And then can they withstand the maximum peak fault current? So that's going to be your closing up rating. So you're really evaluating those 2 ratings against the current and seeing at
50:53
the site. And then equipment withstand is for your non-interrupting equipment. So
50:59
Same 2 questions generally. Can the equipment withstand the peak fault current without mechanical failure? And can the equipment carry the symmetrical fault current without the thermal failure? So that's really what you're looking for out of a short circuit study in a nutshell.
51:16
Okay, bringing a record. That was a good one. All right, no worries. So, which of the following is needed for a short circuit study? Select all that apply. The equipment configuration, transformer and cable impedance data, site geographical coordinates, or the project manager's favorite lunch order? Select and hit submit. To.
51:46
All answers are coming in.
51:49
You got some jokers in the house. I love it. So overwhelmingly, answers are A&B.
51:57
That is correct. But I will say if the short circuit study is going to be late, D is very helpful. Just keep that in mind. But that wraps up what I had to cover today. So if we have some questions in the chat, we need to. Let me pull that up.
52:31
Yes. What's your... out there. And last thing, too, before we get into Q&A, just so it doesn't get missed, please tune in for next month's presentation. We will be putting on our monthly webinar series. Keep your eye on the emails that will have a new topic coming your way. So make sure you keep that in mind and Ba.
52:49
keep your eyes peeled and looking for that. So.
52:54
Also, too, just another piece of housekeeping. If you check in the chat towards the top, there is a PDH available for your attendance of today's webinar. So you can note it's marketing at CAI dash ENGR, and then with the subject line, short Circuit PDH, and we'll respond back to you with your PDHs. So, all right, thank you much. Moving on to questions. This was from earlier in the presentation. How do you address when the utility x / r
53:24
is higher than the UL 49 molded case breakers x / r ratio? Now, I don't know if we can answer specifically the UL rating, but If the x / r from the utility is higher than the x / r ratio of the breaker spec, what do we do? Madison, any thoughts on that? Yeah, so when I talk about this, touch on it very briefly, if your tested X over R is lower than the X over R you see at the site, then you're going to have to de-rate the interrupting capability of your breaker.
53:57
So if your breaker is rated at 63 KA and your X over, I'm not 100% sure what the math is behind it, but I assume that either the manufacturer has a de-rating curve available or it's probably available in a regulation, a standard practice for de-ratings. It's actually not something I've encountered personally, but it's just like a temperature de-rating or an elevation de-rating or other where you're basically exceeding testing specs. So you just de-rate their equipment.
54:27
And that may require to go up to the next size or rating. Yeah, and just...
54:31
Sure. Another thought that may be appropriate Yeah.
54:34
there is whenever you get an x / r ratio of your system, whether it's at the utility or at your level, which may be in the medium and low voltage areas that you're studying, if you start getting above an x / r ratio of 17 per IEEE, you have to start thinking about the decrement of how your short circuit will decay. It will decay slower at higher x / r ratio. So this goes to Madison's point exactly that, you know, if you have an interrupting rating of a value and you have a momentary rating of
55:07
a value, you'll be a lot closer to the momentary value than the the interrupting rating in that case. So you can always conservatively say, you know, rate your breakers at the momentary value, you know, understanding you may be overbuilding a little bit if that's the case. But when you have a higher x / r ratio, you'll have to do some complex math to start to understand where you're really going to be. You know, we've done that with a few projects in
55:30
the past. So, but it's something to keep awareness of. If your x / r ratios are high, that you'll see that short circuit envelope will collapse slower and you may need higher rated equipment.
55:43
It.
55:44
Alright. And.
55:47
So let me go to the next question here. Next question. And again, feel free to put things in the Q&A. I'm kind of going through the questions in the chat. And again, if we don't get to your question, we will respond after the presentation. So for breakers, can the interrupting current rating be used if it's larger than the asymmetrical current?
56:11
breakers, can the interrupting current rating be used? So for example, if the asymmetrical current is a value and the interrupting current rating is a higher value, is that acceptable? I think is maybe another way to state that.
56:28
Yes, you would like your interrupting current rating to be greater than the asymmetrical current. available on the site. Does that answer the question?
56:38
Yeah, I think so. Yeah. So yeah, it sounds like in that case that yeah, Right.
56:42
It. if you're, you know, your asymmetrical should be, you know, your highest value, your momentary value. And if you have a rating higher than that, But.
56:51
then you know you're all set. So, OK, so. Absolutely. Actually, I might have another equipment. Absolutely.
56:57
Next question, how do you model motors that have a VFD controller without bypass?
57:08
So, I think, I think, Kat. So I'm going to say that it depends on the software that you're using. I wouldn't recommend doing it by hand mathematically. But exactly what a VSD controller without bypass is going to look like is probably going to depend on where you're modeling it.
57:24
Okay. Yeah, I think that question is, when we talk about short circuits for the Nine.
57:29
first couple of cycles in a short circuit, a motor can provide fault current Singh. The. depending on the motor type and how it's connected. And when you have a VFD, E.
57:38
there may be potential there, like you're going to have to look at the VFD drive configuration, the model of the VFD and see if there's going to be fault current. coming back through that drive. And then you're going to want to model that in your short circuit program or in your calculation to account for that extra fault current. And that's important for things like, say, arc flash calculations, where so generally your motor
58:01
contribution is going to be much less than your system strength calculation. For a short circuit study, You're sizing your breakers for the worst case condition, and usually the motor contribution won't be that case. I'm sure there's an exception to that, but in general, that's true. But for an arc flash, you have to consider fault current from all sources and timing of clearing from all sources. So that may be where you're driving with that question. So yeah,
58:24
you'd want to make sure that you model that fault current appropriately. And you're going to want to do a little research on the VFD dr controller to make sure you understand what fault current may come back through the system.
58:36
I think we answered this one already talking about x / r. Copy of the recording. Dell will post this. This recording will be available through the Commonwealth website, I believe. And Dell, is there a link that goes out for the Yeah, at the end of the Webinar, everyone who registered and attended recording?
58:57
should be getting an email from us with the link where they can watch it on demand. And in the next day or two, it will also be posted on our YouTube channel.
59:10
I think we got time for one last question. So, Brad Semmler, what is the effect of an ungrounded three-phase system?
59:20
So I think maybe the context is, is how do how does the fault current or say a single line of ground fault affect an ungrounded system? That might be a good way to phrase that question.
59:32
So, when you're talking about ungrounded three-phase systems and how fault currents are going to flow there, you are going to start getting into symmetrical component analysis, which is a bit outside the scope of flow recovering in this presentation, just because that's an entire presentation by itself, to be honest.
59:53
But when you have an ungrounded three basis, and what you're going to see is those grounded fault currents are going to circulate back through the system rather than flowing out through the. So that's going to be more of the impact that you're going to see. It's a very brief answer.
1:00:11
But you can get much more into the weeds and the the specific impacts of an unbounded three phase system.
1:00:17
Yeah OK. Yeah, one point to make note too. Yeah, a very good point, Madison. Yeah, as we're getting into much components a little bit, but when we have an ungrounded system and you have a line to ground fault, what ends up happening in that system, and this will be from maybe your power class, you know, three phase power classes, either in your master's program or your bachelor's program, is that because of that, because there's no ground system for that current to flow through,
1:00:41
you see voltage rise on the unfaulted phases, and that voltage rise can be square root of 3. So if you have a system that's designed for, say, 10 or 20 percent over voltage maximums, and you have an ungrounded system and you have a line to ground fault,
1:00:58
that you can have the unfaulted phases will have major voltage rise. So again, this is where on-ground systems are generally not used in the United States for distribution systems and low voltage systems for that reason alone. Otherwise, you have to really plan your system out and make sure that you have a system built to withstand that overvoltage capability and your equipment must be able to withstand it as well. For example, the, you know, all the way down to the load level in some cases.
1:01:26
Very good question. All right, well, thanks, everyone. I really appreciate your time today. I apologize for ending here at the top of the hour, but it's important to respect everybody's time, and we will respond with answers to the remaining questions. So thank you much, and we'll look forward to seeing everybody next month. Thank you.
1:01:43
Thanks everybody.
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