Subscribe to our mailing list

+1(503) 655-5059
Home > Videos > Generator Protection in EasyPower
Generator Protection in EasyPower

In this webinar, given by David Castor, P.E, a brief overview is given of recommended protection for medium-voltage generators, including system design options and generator grounding options. We'll use EasyPower to look at short circuit currents and protective device characteristics.

The topics discussed include:

See the full transcript of the webinar below.

Download free demo

 Watch our most popular videos

EasyPower OnSite Intro

Utility Short Circuit & Arc Flash

Arc Flash Hazard Reduction

Arc Flash Hazard Reduction

Dynamic Stability Studies

 See all of our training videos

Full Transcript of the Video

Dave Castor: Okay, so it's, it's 10:00 so I think we'll go ahead and get started. I want to thank everybody for joining us today for this weekly webinar. So, our topic today is just going to be to cover some of the basics of generator protection and we're going to focus on, primarily, medium voltage generators and what the typical recommendations are how that, to some extent, depends on your interconnection and also on how the system is grounded. So, we'll look at some examples of different types of connections. Just kind of discuss the basic protection requirements. At the end I'll give you a couple references getting into this in more detail. You may want to look into those as well.

So, like everything (00:01:00) the protection that you put on your generator depends on the generator's size, how it's interconnected to the system, the interconnection requirements imposed by the utility or the regional grid, how the generator's grounded, the importance of the generator to your system or to your operation, and always which a budget is, and how much you're willing to spend. So as terms of electrical protection for the generator we can kind of break it down into two broad categories. There's always going to be a little bit of overlap here. Basically we're going to think about internal faults inside the generator and to some extent, within the generator protection zone which may extend beyond generator a little ways.

And then we'll look at external faults and backup protection for those and then abnormal operating conditions that we need (00:02:00) to protect the machine against. So, you have a large generator in your system that's a major investment. That's a long lead item and so if you're going to have damage to the equipment or to the generator you want to minimizes to the extent possible. Ideally, if you have a winding fault you want to be able to replace that winding and not have to restack the stator core due to a lot of damage to the core. So those are the goals. So, if we start talking about internal faults, primarily we're talking about stator faults inside the machine but when we have differential protection that differential zones typically do not extend beyond the machine itself so we will include anything within the differential zone and the ground fault in that area as an internal fault.

So, This would also include rotor ground faults (00:03:00) and also a loss of excitation, loss of field and we'll discuss those. So those are the typical internal faults or conditions that we're trying to protect against. As far as the typical abnormal conditions that we try to protect against for the generator, generator motoring, sometimes reversed power, low forward power, those names are somewhat interchangeable. The 32 is the ANSI function code that we'll see use for this. So, we'll talk about why the generator motoring or reversed power is something we want to monitor.

Over voltages and or volts per hertz, under voltage, negative sequence current is related to imbalance or phase to phase faults that can be particularly damaging to the rotor of a synchronous (00:04:00) machine, overloading of the generator and then, over and under frequency and we'll look at how we protect against those and why it's a concern. When you get into over and under frequency sometimes the interconnection requirements that are imposed on you by the utility or the grid will become the dominant issue there to deal with. There will be some overlap between the generator protection and your inner connection requirements. So in general that the type of protection we use depends to some extent on how the generator is connected to the system. And the two main categories we're going to talk about are unit-connected or direct-connected. And that's going to depend a little bit on the size and nature of the generating facility.

So, if we talk about unit connected, these are typical large utility generating facilities (00:05:00) or large cogeneration facilities with the key word there being large, and the basic principle, what defines a unit connected generator is that each generator has a dedicated step up transformer and it's going to be delta Y. So that's going to isolate the generator ground from the system ground that gives us much better protection. Much, limits the probability of having to deal with system grounds that can affect generator also have, on a large power plant you're typically gonna have some kind of utility transformer that comes off the same bus. High resistance grounding is the norm here.

There's really no reason not to use high resistance grounding and a lot of advantages to it to limit the ground fault current and with the unit connected concept we can have multiple units at the (00:06:00) same facility we just keep adding them on each with its own step up transformer and unit auxiliary transformer. So here's an example of a unit connected generating facility. Just a little EasyPower one line here. So, here's my generator, and out here is my substation 230 KV and this gonna be my connection to the outside world, where my power gets exported out to the grid. Then off the generator bus we have a second transformer that serves those 138 to 4160 that's station service, it serves the house loads for this PowerPoint.

And so the key thing here is that these transformers are dedicated to this one particular generator so there's no direct connection from the generator to (00:07:00) the rest of the system. Both, all the connections go through these transformers and because these transformers are delta Y when I have ground faults out of my system they do not appear as ground faults to generator, so, it makes it much easier to provide ground fault protection. As I mentioned, we're normally gonna have a high resistance grounding here via a distribution transformer just to get the turns ratio advantage and allow me to put in a smaller resistor. So we're gonna limit that ground fault current to something in the range of 5 amps on a high resistance grounded system and that's kind of a whole topic in itself. Basically you're gonna make it as low as possible while limiting the over voltage transience sense occur.

Something in the range of 5 amps is typical. Okay, so that's the unit connected. So typically these (00:08:00) are gonna be large generators. The other option I mentioned is direct connected. This is gonna be more typical of industrial facilities, cogeneration plants, and smaller utility plants. You have small isolated utility systems on islands. You may have lots of diesel generator systems and these are typically gonna be direct connected. So, the key here is that generators connected direct to a common generator bus each one with its own breaker and then loads are served directly from the bus or through a common transformer. So these are generally gonna be low resistance ground. That allows us, helps protect the machine but also allows sufficient ground fault current that we can selectively coordinate faults in the system.

So here's just a simple example of a direct connected generators. I have 3 units, each (00:09:00) of them at 10 MVA 4160 and each one has a generator breaker so we would synchronize across this breaker to a common bus and then typically, not always but you often times will have some kind of a transformer here to interface out to the utility system or to the grid and then another breaker that's gonna feed your local loads, plant loads directly, so. So the difference here is I don't have the transformer for each generator to isolate it from the rest of the system. So there is interaction between the generators and the rest of the system, particularly for ground faults it's significantly different. So, in these situations we normally would use what we call low resistance grounding and that's going to limit the current to something between 50 amps and 1000 amps, that's kind of the range for what we define as low resistance (00:10:00) grounding.

So this is via direct connected, and again I can have more, as many units as I need here. Alright, so if we look at the the typical protection schemes we're trying to provide here, the first one we're talk about is phase fault. So, phase faults in the generator is relatively rare, but if you do have one it can cause major damage so we want to try to trip as fast as we possibly can and so for any generator probably over about 1 MVA you should be looking at some type of differential protection if at all possible. And the advantage here is that I don't have to coordinate that with anything because if the differential element operates, I know he fault is within the generator or the generator differential zone and I trip quickly and these are extremely fast.

And (00:11:00) can trip off the line within a cycle or so. The only downside to the differential protection is that when I have resistance grounding the differential protection is not always going to detect all those ground faults so we need a different type of protection there and we'll take a look at them, and for high resistance grounding it becomes a little more difficult to make sure we detect all the ground faults. So, for phase faults within the machine the differential is our primary source of protection as that's the preferred method. So here just a typical scheme if you're not familiar with differentials.

So when , this is the 3 generator leads going out to my system this is the neutral side, these are brought out to a common neutral point here can I tie together when I have the (00:12:00) VCT's here as well so, the current going in and out here have to be equal so we sum those, each current in each phase as a restraining coil or signal and then these are the operating coils. So if we have a difference in current that indicates that there's current going somewhere that we don't want it to go and there's a fault we can trip so. These are extremely sensitive and well worth the effort to get the extra, extra connections and CT's here. So, in addition to the differential protection that's our primary phase fault protection for the machine. We also need some kind of backup incase, for whatever reason that doesn't pick up the fault.

Also, if we have a fault that's outside of the differential zone that's ideally that's going to get cleared by some other protective device but if it doesn't (00:13:00) we need a backup to allow the generator to trip, offline to protect itself. So this is complicated by the fact that if you look we'll have some slides on this but, when I have a fault that the generator is feeding current into the current out of the generator is not constant, it decays over time, depending on the exciter and other considerations. But we have to account for the fact that all overtime that current can decay significantly and so, instead of a standard over currently relay, we typical use what we call a voltage, a 51 V which is either going to be voltage controlled or voltage restrained. and they both are trying to acomplish the same thing basically it allows us to have an over current element that is, will actually pick up below the full (00:14:00) load current of the machine if the voltage goes low enough.

So, a voltage controlled relay, you essentially block the over current function until the voltage drops below some set point value. And then the over current relay will operate on whatever curve it's set on. The voltage restrained is more complicated, depending on the voltage the curve will actually shift the time current curve for the over current. So, the lower the voltage the more sensitive the over current relay becomes. So, the reason for all this is the way the generator behaves during a fault. So, here's a generator decrement curve that shows how the fault current behaves as the fault proceeds.

So, since the time current curve we can produce these in (00:15:00) EasyPower in the, in the coordination focus if you have the generator impedances and the time constants. So, this is where we get into the sub-transient reactants, the transient reactants, which is X-prime, and the synchronous reactants along with the time costs. So, on the time current curve time is going up, vertically. So, in the beginning my fault current is quite high but it immediately starts to decay. I get into the sub-transients region and then eventually it decays down to the synchronous, synchronous reactants. Many times the synchronous reactants is going to be over 100% and that means that the sustained fault current is going to be less than the full load current. Now this curve assumes a constant excitation.

In (00:16:00) the real world you probably have, you may have some type of field forcing which is going to drive the fault currents somewhat higher than this. So this curve will look the same but it's going to drop down this way. Instead of going all the way down, it'll be higher. We can take a look at that in EasyPower. In fact, we'll go ahead and do that now. Jump. So, I have, this is our direct connected system here. If I go to the coordination focus, if I look just at this generator, I go to plot, I get this, the curve we were just looking at basically. And so that data is contained in the TCC tab. So if I double click on the generator.

There's a TCC tab every generator, and (00:17:00) the sub transient, transient is gonna pull that out of the, data in this specifications tab that you've already entered this data. You'll have to add the XD which is the synchronous reactants, and the time constants. This you'll have to get from the manufacturers data sheet or test reports. So the curve that's plotted here represents the generator fault current output without a field forcing, in other words the field, the excitation into the machine remains constant during the fault. If your generator has, what we call field forcing, when the current starts to decay and there's a fault the voltage regulator, the excitation system will go and put additional current into the field to sustain, keep the voltage up basically and drive more (00:18:00) current in to the fault.

And so if I select with field forcing then I can define what the level of field forcing is. In this case I've 3 per unit. 300% percent is pretty common. So when I apply this, you see I get a second curve so. This is with constant excitation, this is with the field forcing. So, this is the difference that that makes. So the field forcing helps in terms of detecting fault and clearing and faults. So this is the generator fault decrement curve. So because of this characteristic we have to make sure we can actually detect a fault that's sustained for a long time and as for the voltage controlled over current relays come into play. Alright, so another common protection that you need to apply to these generators is negative sequence over current protection.

So (00:19:00) anytime we have an imbalance, imbalanced voltages, imbalanced loads we have negative sequence currents if you're familiar with symmetrical component theory. There will be negative sequence currents for any imbalance, whether it's a load or a fault. The worst case scenario we're dealing with would be a phase to phase fault in the machine that's going to generate huge value of negative sequence curves. Now, negative sequence currents are basically reverse phase rotations, phase sequence from the normal power systems. So, it's like, if your normal phase sequence is ABC the negative sequence going to be ACB. And so, if you look at a rotor that's spinning at synchronous speed, this reverse, this negative sequence current actually appears as a double frequency so a 60 (00:20:00) hertz system it's gonna look like 120 hertz when it gets to the rotor.

So these currents do create flux that crosses the air gap and induces current in the rotor and at 120 hertz the higher frequency that current tends to stay on the surface of the rotor and can be extremely damaging to the rotor. So we have the manufacture of the generator should give you the limits on the maximizing negative sequence current for the amount of time that is can withstand. This is how we set our negative sequence over currents. So, typical the continuous, so anytime you have any imbalance you have negative sequence currents so they have to be able to withstand some amount of negative sequence current and that's limited to about 10%. Once you get over that and you'll start to alarm and then above certain other value. So it's kind of an "I squared T" function.

So (00:21:00) the heating issues, so there'll be limits that are provided. In the IEEE guide they have some recommendations for different types of machines but ideally you'd get this from the manufacture. So you can use the inverse time curves similar to normal phase over current or you can use some kind of definite time where it's above a certain value for a certain amount of time it's gonna trip. So this provides, so there's usually two levels of protection that you're gonna provide, one is for these kind of long-term imbalances issues and the other is to detect imbalanced faults. That's gonna really provide backup to your other protection. So negative sequence, is very important because of the sensitivity of the generators to negative sequence currents. Particularly the issues in the rotor.

At the other kind of abnormal operating condition we're gonna deal with is loss of field, loss of excitation. So, if you (00:22:00) have a machine that is running at full load and you suddenly lose a field it loses all of its restraining torque and it will quickly go to over speed. The issues that can cause it to slip polls, lose synchronism, those kind of issues can be very damaging to the generator. So normally the excitation system's going to provide protection against loss of field that's built into the excitation system but you need a separate relay, protective relay to back up the excitation system. So that's gonna be the loss of field protection. Typically what we do these days is use a distance type protective element that looks at the R and X that it sees.

So we need a voltage in current input for loss of field, and we do this by taking the capability curve of the generator and converting that to a R, X diagram. So let's take a look (00:23:00) at just a typical generator capability curve. So, the vertical axis here is the reactive power and the horizontal axis is the real power. So we're just sticking to these 2 quadrants. We're not looking at a, if we were on this side, this is when the generator is motoring or reverse power. But looking at the situation, this basically defines the region that the unit can operate in. Up in this quadrant this is real power into the system and reactive power into the system. So I've got vars and megawatts going into the system we call this, this is normal overexcited operation. This is lagging. The generator is lagging when it's providing vars into the system.

And these are the limits. This (00:24:00) is due to stator winding above this point here into the limiting, to the rotary heating, and then you get into over excitation limits here. As your vars start going to high. In this quadrant below we're under excited. So, we're still delivering power into the system but the unit is absorbing vars into the generator and this and has more limitations and more concerns. If we get too far under excited we can lose synchronism or slip a poll, those kind of things. But generally under excited means we have megawatts going power going into the system but vars going into the generator. This is in this situation the generator is leading. Operating in a leading power factor.

So, in order to monitor loss of field, we take this (00:25:00) generator capability curve, basicly this is power and this is Q or vars, we convert this to a RX diagram, and this defines the operating, basically this is the conversion into an RX diagram. So my generator needs to operate outside of this region here. So, once we've defined that region we can set, the distance elements, we typical use 2. So, these are offset mo elements, and these're going to be built into your relay typically. This is for loss of field again. This first element is going to have some kind of time delay. So what happens is if I, combination of RX that's seen by the generator gets into this region it's gonna trip.

As we have transients we can briefly, (00:26:00) we tip into this circle so we want to put a time delay, tenth of a second, something like that, on this outer circle, the inner circle will trip basically instantaneously. So, this is the typical protection that we use to detect loss of field under excitation type of issues. And if you are trying to apply this, the relay instruction booklet will generally give you some guidelines for setting this it's usually a function of the transient reactants and the synchronous reactants. Alright, so we typically are gonna want reverse power protection on our system, on our generating units and reverse power does not mean the generator is going backwards, it means that it's not producing real power or we're out of that, those 2 quadrants were into the other quadrants where the power's going into the generator, and the generator basically becomes a (00:27:00) motor, a synchronous motor.

Now the reality is that this reverse power protection is provided to protect the prime mover not necessarily the generator. The generator is happy operating as a motor within certain excitation limits but the reverse power can cause major problems for steam turbines, gas turbines, reciprocating engines, hydro power units. So, the reverse power is really there to protect the prime mover and not the generator. For steam turbines the reverse, when I have low power I can get overheating in the low pressure sections of the turbine depends on steam flow to cool low that low section as steam goes into the condenser.

These reverse power settings are very low compared the actual normal (00:28:00) rating of the generator. So, 1% to 3%. So, it becomes an accuracy issue when I have CT's and PT's that are sized for the normal flow power and I'm trying to monitor real power down into 1% to 3% of the full power so, the accuracy becomes a little bit of an issue. But, there will be guidelines for reversed power for whatever type of prime mover that you have. For recipricating engines there's reisk of damage to the engine in explosions and gas turbines, and that kind of thing. It's important to understand the limits for reverse power based on the particular prime mover that you have. In steam turbines it's also common these days to use reverse power for normal shutdown and that's to verify that the steam valves have actually closed.

Historically there's been a lot of cases where indications said the steam (00:29:00) valves were closed and they were not closed and as soon as the field was removed the generator went into over speed and self-destructed, so. It's common now to use reverse power to prove that this steam valves are closed, so that's another use for reverse power. Volts per hertz protection is really to prevent against excessive voltage high flux and saturation of the core and that can be extremely damaging. In addition to volts per hertz you need standard over voltage protection. Again, as with the, we mentioned, with the excitation system the voltage regulator should provide protection against volts per hertz, and over voltage, under voltage.

But the protective relay will be used (00:30:00) as a backup to the voltage regulator. Over voltage settings may also be dictated by your transmission operator or your power, your utility and so that's another factor that you have to put in there. Generator overloading or overheating, the best protection there is really going to be embedded RTD's, temperature detectors in the stator and to provide alarm and tripping for those and if you have water cool stator or hydrogen cooling you're gonna need some runbacks, automatic load reductions or trips if you lose those modes of cooling. Now, if you don't have RTD's the relays these days can typically provide a thermal model, similar to what we do with motor protection.

So, that would be another option although the actual temperature (00:31:00) measurements are going to be your best protection against actual overloading or overheating of the windings. Alright, some other protection may run into, and that's typically provided as an option or built into the new multifunction relays, some kind distance protection as a backup phase fault detection and this is going to be similar to the voltage restrained relays that we talked about but, we just use a distance element looking back up into the system to detect the faults. Over under frequency, again this is gonna be tied to your volts per hertz but also your interconnection requirements. But obviously there's going to be limitations on the frequency range that this system can operate at but normally your grid requirements are going to be more severe (00:32:00) than the actual machine limitations.

Inadvertent energization, this is be a case of somehow the generator breaker closed and the unit was not running. That's obviously not a good situation. So, you can typically detect that and trip on that very quickly. Sync check protection is you provide backup to your automatic synchronizer or your manual synchronizer, make sure that's not being closed in grossly out of sync, and then as a stability issue for very large generators you may need to provide out of step protection but that, but generally can be dictated by your, your grid, operator.

Okay, so let's talk now about the ground protection. Ground fault protection and before we do that need (00:33:00) to talk about methods for generator grounding. And if we're talking about medium voltage generators the recommendations of the IEEE and pretty much anyone else is going to be that you use some type of resistance grounding on the neutral of the generator. Solidly grounded generators are typically not recommend if you can avoid it, so, some situations may be necessary to provide a ground source but normally you're gonna want to avoid solidly grounding a generator and the reason is that the ground faults are to be the most common fault and so you can limit the damage by reducing the ground fault current.

Also, if you look at the impedances for most generators, the zero sequence impedance is going to be lower than the sub transient reactants so that means that the (00:34:00) ground for a, a line to ground fault, the fault current can actually be higher than the three phase fault currents and that's going to cause, can cause severe state or core damage. So the ground fault protection that we use is going to depend on the grounding method. So we'll talk just briefly about that. Again, this could be a whole topic in itself but, we mention that for direct connected generators we're typically gonna use low resistance grounding and through some kind of a resistor we're gonna limit the grounding, the ground fault current to something between 50 amps to 1000 amps. That's a pretty big range. The lower the better but traditionally we used higher values, we had electro mechanical relays.

Now with the newer relays that are more sensitive (00:35:00) you can probably to something lower, 200 amps, 100 amps, maybe all the way down to 50 amps. Now the low resistance grounding does limit the damage but even at a 100 amps, 200 amps there's still a fair amount of damage that can be done. But the advantages that with, if I have 200 amps, a 200 amp resistor lets say, with 200 amps flowing I can use my normal over current relays, ground over current relays to detect that and to selectively coordinate.

So on a direct connected generator were on that other plant loads and other plants which you and relying on to coordinate those so I have to maintain selectivity to VAR resistance routing it's not easy to do the low resistance routing it's fairly easy to achieve the tradeoff is (00:36:00) even have more damage when you do have a fault in the status quo to a sewers are typical direct connected system of that three generators each has its own grounding resistor that's commonly done in the nine states that do come and bus and so when I the ground fault that a ground fault, my system sell more that's going to limit its ground fault current that this generator can provide to 100 apps that of the events for meats generator to a list and let up, here and we'll talk about this and if I have the grounded why you're only step up transform two VA utility that and this is done it in to the use of the full currents and gift and if the watch out for this (00:37:00) demo to an example of an additional one stiff resistance.

So, if you're going to have low resistance grounding you want every ground source to be resistance ground. Alright, so the other thing you have to be concerned of with, in this situation where I have multiple generators on a common bus is going to be circulating currents. So, you've probably heard that all the generators need to have the same pitch and that relates to the harmonics that the generator generates. So, if I have a, some kind of harmonic voltage present that can force current through my ground.

Things like third harmonics are going to look like zero sequence currents and so I have an issue with current going through this resistor. It might (00:38:00) only have a 10 second rating for faults so, if I have a system of certain amount of third harmonic current I have to be concerned about if these resistors are going to be adequately rated, if they can dissipate the heat over, on a continuous basis. With the low resistance grounding I'm typically gonna have some kind of an over current relay here. And that's gonna be used to trip off the generator and hopefully something out here will trip first depending on where the fault is. Alright, let's take a quick look at, my system here.

I've got a, I go to short circuit focus, I have each one of these generators grounded through a 100 amp resistor and I've got my (00:39:00) transformer here, I'll take a look, and I have 100 amp resistor in the transformer neutral. So, if I switch to line to ground faults I'm going to fault the generator bus here just by double clicking on it. So, I get a total fault current of 400 amps, so. That's basically 100 amps through each one of these sources through it's 100 amp resistor. and I can see that if switch, instead of looking at A phase current if I look at the the III0 I'm gonna see 100 amps ground current from each source. Okay, so that looks reasonable.

So, I get a total of 400 amps so if this fault instead of being on the (00:40:00) generator bus was actually in the generator I would essentially 400 amps of ground fault current flowing into this generator even though this resistor is 100 amps, the total ground fault current, the total energy, total energy is going to be based on the 400 amps. So as you add units and ground sources you have more and more fault current. So the alternative is to have a common resistor, one grounded resistor where could, you might have to switch the ones that're not going to be in service. And you do see that done in some parts of the world. It's not common in the US. It creates operational issues because you have to remember to make sure you have the right resistor in the circuit.

But just remember that just because I have 100 amps here in my resistor doesn't mean this fault current is going to be limited to 100 amps if the (00:41:00) fault is in the generator. Alright, so if I go back to database, let's take a look if I were to get rid of this grounding resistor and go to solid grounding. So now I have a solidly grounded Y here, this is a delta. So this is going to be a ground source for 4160 volt system. So, now when I go back to short circuit on line to ground when I do a, fault this bus. Now, instead of 400 amps I get 62, 63,000 amps. And the phase current here is mag, is much much greater.

So if I were to have a ground fault within my generator I'm gonna have a huge amount of fault current flowing into that machine, that's gonna cause (00:42:00) significant damage because this is solidly grounded. So, to really protect your machines need to have every ground source resistance grounded. Alright, so let's go back to my, power point here. So, again, beware the solidly grounded transformer neutrals. Okay, so that was low resistance grounding, let's talk about high resistance grounding. The concept is the same, we're going to put some impedance between the neutral and ground to limit the fault current but we're going to go to a much higher resistance. And so we're gonna have, we're gonna limit the current to something around 5 amps, maybe less. The idea is to roughly equal the capacity of reactants of the system.

And this is again, another topic in itself but, (00:43:00) what we're trying to do is minimize the over voltage that can occur during a fault and, and limiting the current to the extent that we can. So, we're gonna go from something, let's say 200 amps down to 5 amps. So we greatly reduce the damage that can occur in the machine. But we have so little current, let's say we have 4, 5 amps of fault current, very difficult to use a normal over current relay to detect that. So what we do is we use a voltage. So the normal scheme here is, we're gonna ground this through some type of a usually just a single phase distribution transformer. And this'll be, you know, if it's a 4160 volt generator this is going to be 2400 volts here and 120 or 240 here.

So, the resistor basically, the resistance (00:44:00) value is multiplied by the square of this turns ratio. So I can get by with a much smaller resistor by doing it this way. So the normal scheme is to put an over voltage here. That when I do get a ground fault I get a voltage that appears across the resistor and then I trip on the voltage. And that works fine but the problem is there's no way to tell where the fault is on the system. So this is going to operate for a ground fault anywhere on that system. So its not selective coordination is extremely difficult if not not impossible. So, this is typically used, that's another advantage of the unit connected generators. So, if we go back, and I thought a slide here, well, let me go back.

On the unit connector generators we had the generator, the unit transformer that isolated the generator (00:45:00) from the rest of the system so using high resistance ground I'm not really giving up any selectivity cause for a fault anywhere in the generator through the transformer I'm gonna want to trip anyway so. This is ideal for unit connected generators and that's one of the big advantages of the unit connected the generators. So, let me just go here. So here's my unit connected generator and my high resistance grounding. So, any ground fault down through the delta windings here is going to show up. I'm gonna have voltage across my voltage sensing and it's gonna trip. So, if the fault is it down here on the Y side it's not going to appear as a ground fault here. So this ground relay will not see that fault.

That's the advantage of the unit transformer (00:46:00) unit generator concept. Alright, so if we think about a normal Y connected generator, if I have a ground fault and a winding that's very close to the neutral point I have a lot less voltage there. So, those are much much harder to detect and so with the high resistance grounding there's a limit to what we're gonna be able to detect and so there's a lot of schemes that have been developed to provide what they call 100% stator ground fault detection. So, for the very large machines this becomes an issue but I'm not going to get into all the details of all the different approaches that've been taken but just be aware that there will be a limit, if I'm just using my normal high resistance grounding and voltage detection there will be a limit. You might only get 90% of the stator winding from ground fault protection.

You've got to think about (00:47:00) the part that are not really going to be able to detect and, but there are schemes that try to do that. Alright, so I just wanted to touch briefly on the distinction between generator protection and interconnection protection. There is some overlap and if I only have one generator then essentially it all can kind of meld together but when I have multiple generators with a common connection to the grid I'm gonna have individual generator protection plus I'm gonna have some type of interconnection protection. So those typically are going to be different relays. Don't have to be but the utility or the transmission operator is going to provide rules and guidelines as far as your interconnection protection.

So, as far as the actual generator protection that's more the responsibility of whoever owns (00:48:00) the generator. So, just keep in mind that those are related but they're not necessarily going to be the same protection. Alright, just to get down to the issue of what relay should I buy, there's lots of relays out there right now that can provide generator protection and so you're going to want to get some kind of microprocessor, multifunction relay. So, I can buy a single relay, this is a Freiser 300G but there's other, similar products available from other suppliers. But that one relay can provide all of the protective functions and a lot of the interconnection requirements. So all of the functions that we talked about today can all be provided in this one box. Provided you have the right CT and PT inputs into it.

However, if this relay should happen to fail, and they definitely (00:49:00) can, you have, you go from having wonderful protection to having absolutely no protection. So, you're going to want some type of backup in a separate relay. Whether you, some people just duplicate these two relays, have identical relays with identical settings and that's fine, or you may go to something a little less elaborate. You're gonna need a separate relay that can provide some backup protection. So, ideally you would have these, your backup relay would connect to a separate set of CT's in case the CT fails, but one way or the other you do really want a backup relay of some type.

Alright, (00:50:00) so suggested references if you want more information, the kind of the Bible that we go by is the IEEE Guide for AC Generator Proection, C37.102As far as text, if you're interested at all in protection or protective relaying I would recommend the Protective Relaying book by Black burn, J. Lewis Blackburn and I'm sure if you go to search for this on Amazon you'll find it. Alright, so our time is up. I want to thank everybody for for joining us today. Thanks everybody we'll talt to you again soon.