Speed of Synchronous Generator

P

Process Value

I do not know how the grid explanation got missed , it is a one year old thread, i do not have the grid documents with me now. But i will see if i can dig up something. thank you for your patience.

 
N

Namatimangan08

> Argument 1 - "If feel doubt about this explanation, let you try to explain how a generator under parallel operation can
> go over speed but the grid remains intact. "

15 January 2012
Place : SJPL power station (Not its real name obviously)
Capacity = 2 X 29MW
Type = Hydro

Number of tripping 4 times in 24 hours. The last one for that day happened at 2130Hrs. The last tripping made such problem became my problem. I was forced to help them with trouble shooting. Otherwise I can't proceed with my other task that had little thing to do with that tripping.

Reason : Over speed protection electrical
Load : 16MW
Frequency: 445 RPM
Rated frequency: 428 RPM (50 Hz electrical)

Derived information: From units monitoring system that has scanning rate that can be made as short as 0.5 seconds.

This is not the only case but this is the latest one.

> from what i get from the statement is that a generator connected to a grid can go to "overspeed" conditions even when
> grid frequency is within operating limits. This is plain wrong.

Already answered above.

> When a generator is connected and it has a governor ( or even no governor as in lab conditions) it will never go to
> overspeed conditions under small signal disturbances. Pole slipping does not mean that the the generator is
> overspeeding , it means that the load angle has gone beyond its stability limit (theoretically 90 deg ,
> practically it will be around 80 due to the presence of resistance in the system).

> "or even no governor as in lab conditions) it will never go to overspeed conditions under small signal disturbances"

That is correct. But your grid system won't last longer than 24 hours without governors. It can't happen in the lab because you control a few parameters that are crucial. In reality the grid has to response to parameters that it has little control over them.

I didn't say slipping pole can lead to over speeding. My point is just opposite. Over speed protection operated for any one unit while the remaining grid operates under normal frequency indicates that slip pole has become intolerable anymore. The protection scheme has to isolate the unit.

Theoretical stability limit 90 deg or 180 deg? Let me check it out. But the safe limit is always below 70-80 degrees. We have little problem here.

> once connected to a grid you can do two things with the generator, increase its output by controlling the
> prime mover or reduce its output by controlling the prime mover, there will be transient speed differences when the
> system settled down to its new load angle but otherwise it will remain the same with some minimal hunting.

Well understood. There should be no argument around this statement.

> Case 1 - Increase turbine power when connected to the grid

> you go on increasing power the generator output will increase till it
this case is possible only in laboratory conditions.

No. It happens in real world. What happens in the laboratory can happen in real world.

> when generator is designed , its Xd value is chosen in such a way that its load angle does not exceed 50-55 deg at
> the max output at the rated "terminal voltage" and at "minimal excitation" point of the AVR corresponding to full
> load. I do not believe that any generator connected to the grid has ever tripped on overspeed (tripped on pole
> slipping yes ,definitely possible but a rare occurrence) when the grid remains at stable frequency.

It just happened to one of our client's power station in January this year. The size grid my client serves is about 17,000MW.

Over speed protection stage 1. RPM 445 RPM. Rated 428 RPM. Load during over speed protection was triggered 16 MW. Number of times 4 times in less that 24 hours. I helped the station technicians with trouble shooting after the fifth one.

My temporary recommendation was to reduce the terminal voltage from 11.5kV to 11.2kV. Next I told them the solution was at best can reduce number of tripping once in 24 hours. The problem was still there. I told them what to do to solve the problem entirely. But that one required lead time to do. The same unit tripped off for the same reason a week later.

Until last week they managed to load the unit up to 19MW (max 28MW). But any attempt to raise the load event by 0.5MW would have ended up with over speed trip. Almost every time without miss. Reducing the load was not leaded to the same outcome.

What do you think has happened to the unit? Hopefully I can tell you later after the problem is solved.

There was another one I had come across about 2 years ago.

Overspeed can happen because of load throw off not the other way around.

But slip pole is actually throwing the load. When the pole of a unit is slipped electrical load will no longer producing opposing torque on the unit. Thus it has similar impact.

> Case 2 - Decrease turbine power when connected to the grid.

> you go on decreasing turbine output , the generator output will decrease and eventually will trip in
> reverse power. "the fundamental concept in AC power system is that the bus giving power must be leading to the bus
> receiving power. Thus when the generator is supplying power to the grid it is leading the reference grid bus. when the
> power goes down the load angle decreases and decreases and eventually will lag the grid bus reference thus receiving
> power from the grid ,and thus the reverse power trip.

You are talking from electrical point of view. The argument is well understood. But that is not only the way you can explain it because the physics do not belong to electrical engineers alone.

From mechanical point of view this is how reverse power works. To remain in synchronism a unit has to generate minimum output. It has to go through windage resistance, bearing loss, vibration,etc. If the input is tuned to no load condition, that mean the power generated is equal to synchronism power. The gross output to plant bus is zero. If the power generated reduces below the syncronism power, the generator will import the current since terminal voltage remains the same and it wants to remain remain in synchonism- Note: to certain extent I'm also the believer to "locked to synchronism" concept. Finally, the unit turns to reverse power.

> "The whole phasor diagram in AC machine analysis is based on the fact that the two phasors representing the grid and
> the generator in this case have ZERO RELATIVE SPEED ie they are rotating in the same speed. " deviations in
> frequency is what is responsible for the load angle change. once a new load angle is reached the speed of both the grid
> and the generator remains the same.

We decide the system under consideration. We make the assumption. I know the concept of making equal relative speed for normal the phasors representation. But when it comes to load swing study, then you can't make the same assumption. The idea of load swing study is to see how the torque angle for each parallel generator moves relative to rotating magnetic field.

One of the posters here is trying to conduct study on the same subject.

To summarize in general there is nothing wrong with the assumption that all phasors have zero relative speed. It is 99.9% accurate. The truth is there are not equal. From the practical point of view deviation that has lower than 70 degree STA can be assumed to have zero relative speed. You can still assume they have zero relative speeds until your protection says the other way around.

> Argument 2 - " To conclude, "locked into synchronism" means all the above control requirements have been
> successfully tuned to deal with steady state (Tm-Te=0)or transient load changes(Tm-Te) is not zero. Successfully
> tuned means that in the event of calculated loss of generation (or demand load rejection) the controllers and the
> J constants for all generators are able to keep synchronism torque angle for all generators to stay within +/- 180 degree
> apart. Equal frequency is not a constraint that is required by the dynamic equations. Otherwise you don't
> need to have 20 swing equations for 20 units. "

> I agree to the above , but this is about the swing equations you have given is for transient stability analysis not
> small signal analysis.

I do agree with you about small system analysis. I am not talking about small signal analysis. More towards system fundamental. To be precise what can happen and what cannot.

Relative to small signal analysis, the system is actually infinite. It is a part of making the grid to become infinite. For example, to ensure steady state load change is smaller than 1% or to ensure transient stability limit cannot exceed 5% of the area (system?)peak demand since the speed droop response & system inertia have certain characteristics for them to work best.

> AGC and PSS uses the swing equations to various degrees to control but though it is certain that
> the frequency hunting takes place , i am quite sure that there will not be a " constant frequency " difference between
> the grid and the generator. ie if the gird is operating at 50Hz , the machine may swing at 50.01 and 49.99 but will
> not be at a constant frequency deviation say 50.1 for the entire operation; that is plain not possible.

As long as no slip pole takes place, you are absolutely right.

> Argument 3 - BTW: I have seen many times that two parallel generators did not have the same electrical frequency.
> Seeing is believing. The latest one was 2 months ago. I will tell you the story about it if the plant owner manages to
> solve this problem later.

> Are the two generators operating independently off the grid or are they connected to the grid? If they are
> operating independently then there is a possibility of frequency oscillation. This usually happens due to a badly
> tuned iso-load sharing scheme. If the two machines are put in droop they will not hunt ( equal droop or not). here is
> a chart to explain what can happen in islanded operation.

I have answered this question above.
 
N

Namatimangan08

Perhaps we have to look from "How things could go wrong with parallel generators under synchonism first" before looking for a simple steady state operations. Otherwise we tend to take for granted about a few things that need to be known in detail to make the grid works the way we want it to be.

Try this link.

Google generators loss of synchronism.

You can see many very good articles to explain how the mechanics of loss of synchronism at work. If you know what make the generators loss their synchronism then you know what to do do to make them to remain in synchronism.

Good luck.
 
Synchronous machines remain in synchronism because the angular frequency of the rotating magnetic field in the stator matches the angular frequency of the magnetic field in the rotor. As many others have said, there will be an angular displacement between the two fields, and this angle does not have to be constant, but this does NOT mean the machines are operating at "different frequencies".

In contrast, induction motors must have a different internal electrical frequency than the grid - this is how they generate torque. Same for induction generators. The difference is called slip.

Here's another take on it: "Frequency" is simply a count of some repetitive behavior in a period of time. So instead of arguing about frequency, let's count: a 2-pole synchronous generator on a 60 Hz system rotates once for every cycle, so in one minute will rotate 3600 times. How is it possible that, if its rotor is locked in synchronism, that another 2-pole synchgen can rotate 3597 times in that minute? Or 3607 times? It doesn't matter if your "grid" is 2 machines or 2000, if they are synchronous machines, then each sees the same number of electrical cycles/second and therefore their shaft speeds are a function of the number of generator poles and system frequency.

If you disagree, then please apply the same math, vector diagrams, whatever, and prove that, without slippage, the driven gear of a 2:1 gear train might rotate 98 times for every 200 revolutions of the driving gear.
 
P

Process Value

The grid again

ha ha ha nice to have a good discussion :)

The contention - “Theoretical stability limit 90 deg or 180 deg? Let me check it out. But the safe limit is always below 70-80 degrees. We have little problem here. "

The theoretical limit of steady state operation is 90 deg. (P = EV/Xd sin delta, max value at 90 deg). but pole sipping means that the load angle has gone past 180deg. during transient swings during fault the generator can go beyond the 90 deg limit and come back (equal area criterion). But once it has gone past 180 deg, pole slipping protection gets activated. now a days a double lens scheme which measures the generator impedance is used for pole slipping determination.

The Incident "It just happened to one of our client's power station in January this year. The size grid my client serves is about 17,000MW.

Over speed protection stage 1. RPM 445 RPM. Rated 428 RPM. Load during over speed protection was triggered 16 MW. Number of times 4 times in less that 24 hours. I helped the station technicians with trouble shooting after the fifth one.

My temporary recommendation was to reduce the terminal voltage from 11.5kV to 11.2kV. Next I told them the solution was at best can reduce number of tripping once in 24 hours. The problem was still there. I told them what to do to solve the problem entirely. But that one required lead time to do. The same unit tripped off for the same reason a week later.

Until last week they managed to load the unit up to 19MW (max 28MW). But any attempt to raise the load event by 0.5MW would have ended up with over speed trip. Almost every time without miss. Reducing the load was not leaded to the same outcome.

What do you think has happened to the unit? Hopefully I can tell you later after the problem is solved. "


First of all wow, secondly i have a few things to point out. The over speed protection is kept at 108% to 115%. Traditionally it has been lower for hydro units (8-10%), then for thermal units (110-112% ) and for diesel units 115% (they are more rugged i guess but that is the only prime mover when i have seen them at 115%). but in the above case the electrical overspeed trip is at 104%. This is very very unusual. the droop is usually kept at 3-5% and the electrical overspeed vale about it. so in my opinion 104% electrical overspeed trip is kinda er .. shocking. from the data i see that the machine is a low speed kaplan / francis turbine operating at low head. is this is double regulated kaplan ? does this have the pilot/main valve arrangement for input water flow. The pilot/main valve arrangement for low head can be a little quirky, ie no change in flow for a control period and heavy flow for another. but its been a long time since i have worked in hydro plants. i am just taking a guess here.

I do not understand how reducing the terminal voltage helps this situation. this is what i would do
1. Increase the really setting after consulting with the turbine OEM, which is am sure is possible up to at least 108%. ( if not this has to be a very special low cost turbine ?? )

2. check which is initiating the trip ?? the generator electrical overspeed really or the governor overspeed trip ? (governor usually has multiple overspeed protections, sometimes the electrical overspeed measurement is also used in turbine control for fast valving). are the speed in both the generator protection relay and turbine governor matching ??

3. what is the time interval if any for the stage one overspeed protection.

from what i see, this could be a main water valve problem, when you increase the load, there is a sudden inrush of water that is causing a transient speed rise, thus tripping the turbine. but if you ask me it is within limits as 4% swing in speed though unusual is not unheard off in transient load changes. but in my opinion this is a case of bad really setting and unusual circumstances.

can you confirm that the speed of the grid was only 50Hz when the tripping took place ??

The discussion - "
You are talking from electrical point of view. The argument is well understood. But that is not only the way you can explain it because the physics do not belong to electrical engineers alone.

From mechanical point of view this is how reverse power works. To remain in synchronism a unit has to generate minimum output. It has to go through windage resistance, bearing loss, vibration, etc. If the input is tuned to no load condition, that mean the power generated is equal to synchronism power. The gross output to plant bus is zero. If the power generated reduces below the synchronism power, the generator will import the current since terminal voltage remains the same and it wants to remain remain in synchronism- Note: to certain extent I'm also the believer to "locked to synchronism" concept. Finally, the unit turns to reverse power. "

ha ha ha well, as a solemn electrical engineer i want the world to be that way :p lol. but in my humble opinion synchronous power is a electrical concept. to mechanical guys they the power is either positive or negative . but i agree to the concept above.

the rest i believe has no contention. But i am curious to know about what you find about the hydro power plant though :).
 
Namatingan08,

> Perhaps we have to look from "How things could go wrong with parallel
> generators under synchonism [sic] first" before looking for a simple steady state operations.

There are so many things wrong with your posts on this thread, and that's without taking into consideration you are discussing abnormal operation without qualifying your statements.

You have said that two generators (synchronous, I presume) being operated in parallel will almost never have the same frequency and you have yet to provide any hard data as to how much the two frequencies might differ and for how long and under what circumstances.

As for the data from the fictitious hydro plant, I think we all agree on F=(P*N)/120, so what kind of synchronous generator has 428 RPM as it's rated speed? That turns out to be a 14.01869 pole machine for a 50 Hz system (nominal, and we all know in that part of the world nominal is a dream).... Something ain't quite right. I know what it is: It's really a 49.93333 Hz grid. Or, generator manufacturers are rating their products for abnormal frequency since normal rarely occurs in some parts of the world.
 
N

Namatimangan08

Google the the key words that I gave you. Find one statement that contradicts to my statement.

No they don't. I made the round off without realizing it could be an issue. It is actually 14 poles machine. The exact RPM is 428.57140. I know well about RPM and number of poles formula.
 
S
This is because the speed governor has certain delay in responding to the transient changes in the load. hence for a short time generator speed will decrease or increase depending of load changes. But there will not be any difference between frequency and voltage when the machine sychronised with the grid. (except in transient condition).
This is my opinion and experience.

Thanks
Sunil Kumar
 
N

Namatimangan08

> The Incident "It just happened to one of our client's power station in January
> this year. The size grid my client serves is about 17,000MW.

> Over speed protection stage 1. RPM 445 RPM. Rated 428 RPM. Load during over
> speed protection was triggered 16 MW. Number of times 4 times in less that 24
> hours. I helped the station technicians with trouble shooting after the fifth one.
---- snip ----

I think you have an idea about what was going on.

The actual tripping was over speed. It was the only indicator that operated. All the 5 tripping events were the same. I was puzzled why out of step alarm did not operated. But as far as our trouble shooting was concern, it didn't matter much.

When tripping relay was triggered, machine RPM was 445 RPM as given by the plant monitoring system. What was the the actual RPM? It should be 445+17 =462 RPM. Why? The Speed Sensor Generator (SSG) for that machine has constant bias error -17 RPM. So when the machine tripped most likely its actual RPM was 462RPM. You got the 8% over speed set point that you want since the machine has rated RPM 428.57 RPM.

So that was at least of the problems that we know at the moment. Bias error of its SSG by -17 RPM. That was the reason why I recommended the owner to reduce its terminal voltage since the generator was extremely over excite due to false SSG signal. It voltage was close to 8% higher than the machine just next to it.

FYI I was visiting the plant only just now. The problem is still there since they have yet to change the SSG. Now they keep that unit load to 15MW now. They planned to change the SSG later.

> from what i see, this could be a main water valve problem, when you increase
> the load, there is a sudden inrush of water that is causing a transient speed
> rise, thus tripping the turbine. but if you ask me it is within limits as 4%
> swing in speed though unusual is not unheard off in transient load changes.
> but in my opinion this is a case of bad really setting and unusual circumstances.

You got it right here. That was the other reason. I came to the same conclusion as yours. The machine has big problem with its nozzles. BTW the turbine type is vertical Pelton with 2 pairs of nozzles configuration. But I didn't think that reason alone could cause it to go over speed that often almost at every loads. Over excite + poor flow regulation sound convincing enough to make it happened. They have to change the SSG before we move to the second one.

> can you confirm that the speed of the grid was only 50Hz when the tripping took place ??

Within +/- 0.2 Hz. We could read it from the plot.

Thank you for your inputs anyway.
 
Sunil Kumar wrote:

> But there will not be any difference between frequency and voltage
> when the machine sychronised with the grid. (except in transient condition).
> This is my opinion and experience.

Thank you, Sunil Kumar.

This is <b>exactly</b> the same as my experience, training and knowledge (not my opinion).

Even on shipboard electrical systems, which are small islands with as few as two synchronous generators. Usually the speed governors of the prime movers of these shipboard electrical generators are pretty well tuned and can respond properly to most load swings with little or no problem and can maintain frequency to within +/-0.2% of nominal.

Also the operators of most shipboard electrical systems clearly understand isochronous operation and how to load and unload units to maintain frequency.

Namatimangan08 and Process Value are fortunate to live in a part of the world that experiences many transients and to have such other-worldly experiences to share. If only they would recognize them as transients.
 
N

Namatimangan08

Sunil Kumar wrote:

>> But there will not be any difference between frequency and voltage
>> when the machine sychronised with the grid. (except in transient condition).
>> This is my opinion and experience.
---- snip ----

CSA wrote:
> Namatimangan08 and Process Value are fortunate to live in a part of the world
> that experiences many transients and to have such other-worldly experiences to
> share. If only they would recognize them as transients.

I can assure you not only me Process Value. Since you didn't want to explore the key words that I have posted a few days ago let me summarize one of the articles that has something to do with our discussion.

Google: generators loss of synchronism - Look for for the second topic

Chapter 12 (My summary)

12.1 Introduction

"Normally all generators within the interconnected power system operate like their magnetic poles coupled through interaction through the network"

My comment- This statement is related to your position

"Interconnecting force is elastic, allowing some angular play between generators in response to system disturbances"

My comment - This statement supports my position.

" A loss of synchronism occurs when bonding force is insufficient to hold a generator and a group of generators in step with the rest of power system"

My comment- That is exactly the point I wanted to put forward. I think I'm in good agreement with PV.

"When synchronism is lost, the affected generator or generators operates slightly at different frequencies"

My comment- Clear this is my position. Probably PV position too.

"The different frequency is termed slip frequency"

"For a generator that pulls out of step ahead of the system with slip frequency of 4Hz will operating at a speed of 1+ Slip frequency/60=1.067pu or 6.7% over speed:".

My comment- This is likely the maximum allowable slip before protection system start to concern. I proposed 30RPM for 3000 RPM (1% slip) system is assumed to be normal.

Thanks
 
N

Namatimangan08


EhGC wrote:
> Synchronous machines remain in synchronism because the angular frequency of the rotating magnetic field
> in the stator matches the angular frequency of the magnetic field in the rotor. As many others have said, there
> will be an angular displacement between the two fields, and this angle does not have to be constant, but this does NOT
> mean the machines are operating at "different frequencies".

Actually there are two subjects that being discussed here. Two entirely difference subjects. Probably we are not in disagreement at all. I don't know for sure.

I have little problem to believe the loads cannot rotate faster or slower than "system frequency". This is I think CSA position. I have little problem to share his position.

But what is system then? System does not have any frequency. So the loads cannot follow the system frequency since it does not exist in the first place. What we know for sure what really exist is generators frequencies. System frequency is in facts the resultant frequency of all generators in parallel.

Here is my argument. All parallel generators can have different frequencies. As I show you the swing equations for parallel generators are independent from each other. Each of them swings according to dynamic properties of its own even though the opposing force (demand load) from that tries to slow them down is well distributed via accurate droop setting.

For a steady state stability study, the fact that each generator swings differently due to small perturbation can be ignored. Most of the time it is ignored. But for a transient stability study due to major disturbances, it is important to factor it.
 
Which trip first, breaker or overspeed?

---- snip ----

Namatimangan08 wrote:

> I have little problem to believe the loads cannot rotate faster or slower than "system frequency".
> This is I think CSA position. I have little problem to share his position.

> But what is system then? System does not have any frequency. So the loads cannot follow the system
> frequency since it does not exist in the first place. What we know for sure what really exist
> is generators frequencies. System frequency is in facts the resultant frequency of all generators in parallel.

> Here is my argument. All parallel generators can have different frequencies. As I show you the
> swing equations for parallel generators are independent from each other. Each of them
> swings according to dynamic properties of its own even though the opposing force (demand load)
> from that tries to slow them down is well distributed via accurate droop setting.

> For a steady state stability study, the fact that each generator swings differently due to small
> perturbation can be ignored. Most of the time it is ignored. But for a transient stability study
> due to major disturbances, it is important to factor it.
 
B
Many years ago, I developed a transient model of the New Zealand power system - small enough to have significant excursions from the nominal 50 Hz.

The basic model assumed initially that all rotating plant was lumped together - so the system inertia was the total inertia (reflected to 3000 rpm) of all connected generators, with an allowance for load inertia. The system frequency under varying load conditions was found from a differential equation based on the overall power balance.
Because of the topology of the NZ system (a relatively compact central core with some large outlying generation on the end of long lines) the main interest (and the reason for the model) centered on the behaviour of individual generators or stations swinging around the central core. So each station was then modelled independently as an entity with its own individual power balance - mechanical power in from the generator - electrical power out depending on the load angle and reactance of the transmission line connecting it to the central core.

The model was reasonably accurate and gave results quite consistent with the transients actually observed. On a major upset, the frequency fell to a minimum over about 4 seconds then recovered through governor action over the next 20 seconds. This was with a predominantly hydro system - times will be different with slower responding thermal generation.

However, while the power angle for the machines varied significantly, the actual speed differences across the system would not be very great. In other words, the machines remain in synchronism with each other but not necessarily at the nominal frequency. In the absolute extreme case, an idling machine with load angle zero would get to 90 degrees in 4 seconds - that's 1/4 of a rev in 4 seconds or 1/16 rev/s. On a 50 Hz system that's 0.13 %. Realistically, on an operating system, the differences in speed will be much less than that - say about 0.02 % - and these differences will exist for only a short time.

So yes you will see changes in speed across the system - but no the system as a whole will not lose synchronism.
 
N

Namatimangan08

> Which trip first, breaker or overspeed?

We have conclusively concluded that over speed came first. We could learn sequence of events up to 500ms frequency.
 
Thank you, very much, Bruce Durdle. I was so hoping you would weigh in on this topic (I almost asked you specifically for your experience in an earlier post!).

> So yes you will see changes in speed across the system - but no the system as
> a whole will not lose synchronism.

And that means that unless there are some extremely unusual transients that no single generator can go significantly faster or slower than any other generator--not by more than a value (angle; percentage; speed) determined by the number of poles of the generator, and the more poles the smaller the value.

This fictitious hydro unit obviously has some extremely unusual speed sensing equipment. A "generator" being used to monitor speed? That went out with vacuum tubes. No passive speed pickups? No active speed pickups? No keyphasors?

I will admit I haven't seen everything and don't have the knowledge about power system transients that many here do. But I do know that magnetic forces are very powerful and as long as the units aren't under-excited or lose excitation and fail to trip on loss of excitation they will not run faster or slower than the frequency of the grid with which they are connected. Even if it's just two single synchronous generators connected in parallel they will not run at different speeds, regardless of the frequency of the system. They are locked in synchronism by the magnetic forces at work in the generator.

Even if a generator slips a pole, it only rotates a certain angle before it "hooks up" (to use a modern term) again, even if it slips again. It's the forces at work when hooking-up and slipping that cause the mechanical damage, but they won't let the unit run at frequency (speed) significantly higher or lower than the frequency to which they are connected.

And, if excitation is completely lost and the unit becomes an induction generator, well, they typically don't run for very long before catastrophic damage occurs because of heat and imbalance and loss of air gap.
 
N

Namatimangan08

If you have 20 generators in parallel you think 20 generators all the times will have equal frequency? If that what you mean then please show any scientific or mathematical prove to support your position. How two generators that are placed probably (1) 1000km apart(2) one has moment inertia twice as big as the other (3) one might have higher ramp rate than the other (4) have diff impedance, etc. can rotate in harmony at the same frequency. If this is true there must be a plain simple equation that can describe the phenomena. Can you find any?

Base on one of the Newton's laws, such condition cannot exist unless the generators are coupled by a rigid coupling. Electromagnetic force that holds the generators in synchronism is not rigid. I have posted the statement from independent article to illustrate the point. The reason is a generator complies with the laws of motion.
 
> (nominal, and we all know in that part of the world nominal is a dream)....

Hi CSA, Don't you think that this statement is like a blame at the people whom you target. I sometimes felt that you take opportunity to make some comments even they are not really needed to be made. Sorry to say, we respect you for your posts but plz dont try to judge systems just by listening to some people or reading about them. I do agree that there are problems which exist and lot of measures being taken. Every grid in the world has its merits and demerits.

Ravi
 
S
Let us Assume that the Grid frequency is at exactly 60.0HZ and the generator frequency which is synchronised with grid is having 59.9 HZ. if so, what will be the angle between grid and the generator phases, it will change continously. In above case generator phases are 36 degree (electrical) slower than grid frequency for every second.

that means for first second 36degree out of phase, next second 72 degree out of phase, third second 108 degree out of phase like that it goes on, is it possible? my answer is No, I need your openion guys.
In my opinion there may be slight hunting between +or- but not in one way, ie, generator cannot run with lesser/greater frequency with grid continiouly.

I may not be perfect, opinion may differ depends on our knowledge.

Regards
Sunil
 
Ravi,

I'm not judging any system. I'm simply trying to point out that 50 Hz in some parts of the world is not 50 Hz. And, I have been told many times the system is a 50 Hz system, but in reality the frequency is almost never 50 Hz, it almost always runs at something more or less--and I don't mean 0.1 Hz, more like 0.7-0.9 Hz on a regular basis, with excursions to 47.8 or 52.1 on occasion.

And people are always wondering why their unit isn't producing rated power under these conditions--which they fail to mention in their original query--or why their unit is experiencing frequency swings when their governor has 4- or 5% droop.

Everything is relative. I have been asked many times why the IGVs are closing when the unit is being operated at Base Load, only to find the grid frequency is 47.1 Hz which means the IGV control curve becomes active at PART SPEED (when it's never active at rated, 100% speed) and fail to mention the grid frequency. And, worse, they are upset when they are told this is done to protect the axial compressor against surge in under-speed conditions; they want to defeat the protection to make more power. And, even worse it comes out that these same people have defeated the under-frequency protection relays on the generator.

Can you see how hard it is to properly respond to some of these questions? When complete and full disclosure is not made? People purposely hide information to try to make it seem the problem is the turbine control system, when it's not.

Having never been an ISO operator, I can't judge any grid or system. I can only talk about people who try to suggest that normal operation occurs on grids where the frequency is almost never at rated or nominal and pass the experience off as typical of every grid.
 
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