Speed of Synchronous Generator

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Namatimangan08

I just give direct answers. If they help.

Dear, Namatimangan08

> 1) why does speed of a generator slow down when system electrical load is increased.

Because of opposing torque that the electrical load has produced.

> 2) why does speed of a generator increase when system electrical load is decreased.

Because of there is additional torque that the Prime mover has. This additional torque will be used up by the system to achieve new steady state condition. Obviously at higher frequency.
 
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Namatimangan08

>> one might have higher ramp rate than the other
________________________snip

> Namatimangan08, are you sure that changing the machine loading ramp rate
> causes frequency diff. I have tried loading the machines using manual
> loading and auto ramp rate but I did not observe this.

The ramp rate for any t/generator for grid operations has already been limited so that it will never bring the generator to slip poles under steady state load changes and calculated transient disturbances. The fastest ramp rate that I know is 15%/second. Controlling the ramp rate is a part of grid operations too.

Its hardly you can see any diff in frequency deviation between parallel generators using your method. Especially during steady state operations, Even more difficult if your grid is bigger than 50,000MW.

Right here in my country, my company has installed a system that is called Wide Area Monitoring System (WAMS) for our grid. We can only see relative swing between two areas by having monitoring system that keeps on tracking the angles.

Obviously the grid faced some problems about power quality. That was why the grid management paid for the system. We (our company) installed for 5 areas all together.

Next time when you want to make similar test go and monitor generator frequency rather than grid frequency. It is greater chance that you can see relative difference. The faster you ramp the generator the greater chance you can see it.

My final note is I'm not saying their frequencies are different. What I'm saying is they can be different. You just have to wait the right moment.
 
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Namatimangan08

---- snip ----
> 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?

The official name that the plant operators call the sensor is SSG, or Speed Sensor Generator. It is a plain speed sensor. Not generator to sense speed.

Actually I referred it as Generator Speed Sensor when I explained what was going on to them after the fourth or fifth tripping. Later I had to tune to their terminology... SSG.

If that what you meant.
 
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Namatimangan08

Please read this book. Goggle generator in sychronism. Look for "Power System Dynamics": Stability and Control-Chapter 6.2 Swings in Multi Machine System : by Jan Machowski, Januz Bialek, Dr Jim Bamby.

BTW-The title of that chapter tells us that when it comes to swing related problem a simple lump model for generators in parallel is not the best to describe physical behaviors of the system under consideration.
 
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Namatimangan08

To reduce possibility of slip pole. At least I could see two reasons why over speed relay was triggered. Governor badly hunting and its terminal voltage was very high relative to the system voltage. Just looked at the unit next to it we knew that.

Put aside over differences in "loss of synchronism" issue. Can you see looking from electrical point of view we have only one governing parameter that control the load flow, i.e. generator voltage? But then every body here agree that the generator load is raised, it is torque angle that that is going to change. After all, torque angle for any generator can only be drawn by knowing its voltage.

As a conclusion, changing the terminal voltage will change the generator torque angle. The hydro unit I was talking about actually was trying to go to out of synchronism. After reducing the voltage its generator torque angle came closer to system average. As a result, it could last for 1 week. That was already above my expectation, i.e. 24 hours.
 
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Namatimangan08

> so what type of system is used for load control so as to keep the system frequency constant?

Think about how you are going to maintain tank water level at the desired level if you don't know the current consumption. How you are going to do that? This analogy is exactly similar.

About maintaining the tank water level problem, this is what you can do. As the level drops, you have already calculated net draw down. You just open inlet valve gradually until it reaches the new steady state (incoming=outgoing). Then you open a bit bigger too build up the level again to the original level.

For a grid system "level" is system frequency. "Tank" is inertia of rotating mass. Bringing the "water level to the new steady state" is the speed droop response. "bring up the level to the original level" is AGC frequency control or manual load intervention.

If you are smart with tank problem you may have an idea about about the next 30 minutes water consumption so that you are prepared. In grid operation it is similar. We call it load forecast + generation scheduling.
 
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Namatimangan08

> Your reasoning is perfectly right, as long as the size of the generators is small with respect to the total grid
> capacity. Continental systems are huge, so a 1250MW generator will only supply a very small percentage of the total
> demand. Changing its output will have a minimal effect on the system frequency.

This is the thing that many people can't put in perspective. The size you are referring to is inertia. Physical size is only a part of inertia. Inertia or mass moment of inertia is

Inertia= mass X radius of gyration^2

Without putting inertia in grid operations the only possible way to explain how a grid works is by assuming "all generators in parallel are locked into synchronism". This assumption is perfectly right to use in majority of cases. But definitely it will bring big problem if we want to design a power system from scratch or if we want to perform dynamic stability study.

I give an example inertia at works. Assuming a US grid system says 2,500,000 MW. When the system is rotating at 60Hz, its inertial could be around 2 X 10^4GJ. If a 1000MW unit trips off, the rate of frequency decay becomes<pre>
Rate of decay = 60/((2 X 10^13Joule/(1000*10^6))

=0.003Hz/second (0.2Hz in 100 seconds)</pre>
But then every second the governors for every prime movers in the system react to restore order. Every 4-10seconds AGC -constant frequency will try to support the frequency from dropping. You can see response time is much faster that frequency decay. As a result the actual mechanic can never been seen by observing system frequency alone.

So if any person stays in USA, Canada, Japan, etc tries to learn the grid system from his system alone, there is greater chance he or she misses the what so called mass moment of inertia.

Not all countries as lucky as the USA, Canada and Japan to have "an infinite grid system". My country is not an exception.
 
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Andrew Davidson

> I have confusion as how increase in electrical load lead to decrease in generator rpm? And why if we increase
> the generator rpm (by injecting more fuel in gas turbines) increase the power?

I cannot help but feel a fundamental point is being missed in this entire discussion. Everyone is focusing on the generators. Conservation of Energy is missing from this discussion!

Let's think about the demand for a minute:

What happens to demand as frequency drifts?
- AC induction motors speed-up and slow-down as grid frequency rises and falls.

Power output of AC induction motors is proportional to frequency they're run (consider the extreme case of a 0 frequency AC circuit, e.g. a DC circuit, run on an AC induction motor---what happens? no spin, no power, no resistance on the circuit)... if we extrapolate the other direction to higher frequencies we imagine a larger amount of power used by the motor as the frequency rises...)

Thus we start to see why frequency floats when all else is held constant on the grid... **it's the only way for the grid to maintain conservation of energy on a system with many motors.**

What about non-motor demand? (e.g. parts of demand not frequency-related)
-> These do not drift with frequency, thus we rely on there being AC motors on the grid in order for frequency drift to enable conservation of energy.

*THE GOLDEN QUESTION*
What happens when a light bulb is turned on, or a generator falls out of service, and all other generation is already outputting maximally?

--> The answer is, the light bulb takes power away from all the motors running elsewhere on the grid. They slow down. This is how energy is conserved.

--> When a generator falls out of service, all motors on the grid slow down by a factor equal to the loss of power to the overall grid.
 
Are the following statements correct?

1)Grid frequency falls when the demand /consumption is higher than generation.

2)If an islanded machine with 4% droop is generating full load 100 MW at 49.5 Hz the actual demand/ consumption from that machine is 125 MW as the frequency has fallen by 1%
 
[These are my simple replies to two simple statements under the stated conditions. Anyone wishing to take exception to my replies please be specific with your qualifications (meaning no vague or nebulous responses, and not including any questions to be answered off-line). Please ensure your exceptions are within the bounds of the statements and conditions stated by Dodo.]

> Are the following statements correct?

> 1)Grid frequency falls when the demand /consumption is higher than generation.

Yes.

> 2)If an islanded machine with 4% droop is generating full load 100 MW at 49.5
> Hz the actual demand/ consumption from that machine is 125 MW as the frequency
> has fallen by 1%

I believe there's not enough information to provide a single, proper response to the question.

I interpret the question to read that a single prime mover and generator is supplying a load, independent of any other prime movers and generators. If that is the case, the prime mover's governor should be operating in Isochronous Mode and the amount of droop the machine is set to operate with in Droop Mode does not come into play.

The missing information for me is:

A) whether or not the single prime mover and generator was operating in Droop Governor Mode or Isochronous Governor Mode when a load change caused the frequency to decrease,

and,

B) what was the load before the frequency decreased to 49.5 Hz?

If the prime mover was in Droop Governor Mode at part load (i.e., less than 100 MW) when the electrical load increased to 100 MW (which I interpret as the rated power output of the prime mover), and neither the operator nor the governor changed the Droop Governor setpoint when the load increased to 100 MW, then the speed would decrease until the governor sensed that the rated power output or energy input to the prime mover had been reached <b>OR</b> the Droop Setpoint differential had been reached.

In the latter case, as the load increased to 100 MW the differential between the actual turbine speed would decrease to 99% while the setpoint remained at 103% for a total differential of 4%--which is equal to the stated Droop. I would say the operator could then increase the energy input to the prime mover to increase the frequency of the generator to 50.0 Hz and the load would remain at 100MW. Again, this presumes the prime mover governor was in Droop Mode and was NOT at rated power output when the load increased to 100 MW; in other words the Droop setpoint was at 103.0% and the prime mover was producing less than rated power (I believe the load would have been 75 MW at a 103% Droop setpoint at 50 Hz before the load increased to 100 MW, at which point the speed/frequency would decrease to 99%/49.5 Hz.)

If the single prime mover and generator was operating in Isochronous Governor Mode at 100 MW and at 49.5 Hz and the prime mover was producing its rated power output, I honestly don't know how to correlate the actual electrical load to the load being produced, since Droop is not active when Isochronous is active.

If I recall correctly from university, when the "system" frequency decreases the actual amount of power being consumed by the load (the motors and lights and computers being driven by the prime mover via the generator) decreases, so the amount of electrical load actually decreases slightly as the frequency decreases. (As frequency decreases, electric motor speed will decrease and so the amount of torque produced will decrease.) The extent is a function of the nature of the load. That's why there are power system studies done.

So there are lots of factors at work in a situation where a single prime mover and generator supplying a load was already at rated power output and the load increased to cause the frequency to decrease, and, again, the stated conditions are not clear.

I'm sure that if the nature of the electrical load was known (number and type of motors; number and type of lights; number of computer; etc.), as well as some other critical information about the electrical distribution system that it would be possible to say how much electrical load (at 50.0 Hz) existed at the time a single prime mover and generator were operating at the rated power output of the prime mover with the prime mover in either Droop- or Isochronous Governor Mode at 49.5 Hz.

There are just too many intangibles to accurately predict the load at 50.0 Hz for a machine that was already operating at rated power output when the load increased and caused the frequency to drop.

So, to sum up, I don't know if the prime mover was being operated in Droop- or Isochronous governor mode. I don't know if the prime mover power output was already at rated ("full load") when the load increased to cause the frequency to decrease. I don't know how to accurately calculate what the load at 50.0 Hz would be if the unit was being operated at rated power output if the load at 49.5 Hz was 100 MW, regardless of whether or not the machine was in Droop- or Isochronous Governor Mode if the unit was already at rated power output (100 MW) when the load increased and caused the frequency to decrease to 49.5 Hz.
 
Thank you for the detailed reply.

I think Iso or Droop mode should not matter as they only determine the governor response to a freq change while what i asked was the reason for frequency to fall to 49.5 from 50 when the generation was 100 MW.In short, I was trying to put statement 1 in numbers.
 
The more I think about this (and I've thought about it a lot), I think Andrew Davidson's response below is the best response to your second statement. Read it carefully; it's very good.

If the prime mover's governor is in Isochronous and the load is at maximum at rated frequency and the load increases, then I don't believe that the Droop setpoint will have anything to do with how much the power decreases.

If the prime mover's governor is in Droop and the load is at maximum at rated frequency and the load decreases, then I don't believe the Droop setpoint will have anything to do with how much the power decreases.

If the prime mover's governor is in Droop and the load is <b>NOT</b> at maximum, and the load increases with no intervening action by the governor or an operator, then the frequency will decrease by an amount proportional to the Droop setpoint (25 MW/% at 4% Droop) <b>UP TO THE RATED POWER OUTPUT OF THE PRIME MOVER.</b>

That's the key: Whether or not the prime mover was already at rated output and at rated frequency when the load increased to cause the frequency decrease. <b>AND</b> whether or not the unit was in Droop or Isochronous Governor mode. And, how much the increased load was more than the rating of the machine.

As well as the nature of the load, as Andrew Davidson suggests. For all conditions of a single prime mover and generator supplying an electrical load.

In general, Isochronous Governor mode is proportional plus integral control--up to the maximum rated power output of the prime mover. If the speed decrease caused by the load exceeds a very tight deadband, the governor responds by increasing the power output of the prime mover until the speed increase reaches an upper limit (of a very tight deadband). But only until the maximum power output of the prime mover is achieved.

In general, Droop Governor mode is straight proportional control. The amount of the difference between the Droop Setpoint and the reference (usually turbine speed which is directly proportional to generator frequency) defines how much the energy input to the prime mover will be increased or decreased up to the rated power output of the prime mover.

The prime mover, barring any special governor modes or bypasses or something similar, is protected against overload by the governor.
 
Thanks a lot CSA and Andrew. You know that satisfaction of getting a nagging doubt cleared? I am totally at peace now! Thanks again
 
This thread is amazingly stereotypical "enginerd" talk (and I mean that as a joke, not insult).

As an analogy: if we take a nice flat and smooth piece of metal, I can say, "that is a nice smooth surface on that solid object". But if you bring out a microscope and look at the surface, you may say, "you are wrong, it isn't a smooth flat homogeneous solid...it's actually a rough bunch of cell like structures."

If we bust out a super powerful electron microscope (or whatever the new fancy technology is), you may say, "Well Gee, you are totally wrong...that metal object isn't solid at all, it's a bunch of atoms floating around and electrons and protons and stuff."

Thus my point: what level does one view the mechanical and electrical phenomena? Because, if it was truly as complicated as this thread makes it out to be, I doubt Westinghouse and Edison and their great staff would've been able to develop the electrical system over 100 years ago. BUT THEY DID IT--without intricate knowledge of the vectors, maths, and varying orders of differential equations.

I see quite often very smart people seem to overdo it with technical theories and formulas. Remember, math and formulas module the physical phenomena, not the other way around. If mankind didn't have the math, nature would still do what nature does.

But to the topic: I've had the pleasure (or maybe displeasure) of working on smaller islanded systems with unstable governors, no type of AGC, and management and operations that didn't understand fundamentals. One of my big projects was to lead a system wide governor tuning and modeling process to stabilize the system. I've lived it and fundamentally understand what happens by experience.

Now, I'm electrical transmission expert, but since governing is a mechanical trait, I am not at a major disadvantage for being a mechanical guy.

In this thread I see intermixing of electrical power and mechanical power--which should not be done. I see pole forces and slip angles combined with droop--which should not be done. Droop and governing ONLY cares about the RPM of the machine and nothing more.

Can a generator spin at 3005 on a system while others are at 3000 during steady state? Well, if somebody says they've seen it, I'd would ask them to give me the calibration records and tolerance of their RPM measuring device. When somebody says a machine is 50.013HZ and another is at 50.001 it's very hard for me to agree that those numbers can be trusted completely. Any informed person should know the limits of instrumentation.

During transients, can two generators on the same system have differing RPM? Maybe...who knows...does it matter? Remember the microscope analogy above? If we look close enough, I'm sure we can find the phase angle of one unit is different than the other due to magnet rotor slip etc etc etc (for which I gladly admit I am NOT well versed in).

However, I do have data and graphs and information from major system disturbances where a large unit trips on a rather small grid (unit making 10-25% of power) and the MW (electrical) power goes UP while the RPM remains stable for a second or two. Then the RPM begins to drop as system frequency drops due to the imbalance in MW generated vs MW demanded. A true expert in this area explained it to me as system inertia making up for the imbalance of power for the short time following the unit trip. The problem was that none of the other units would "step on the gas pedal" because their governors were messed up in many ways.

But again: Droop, Isoc, and governing in general is a mechanical task. Governors look at one thing......
 
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Namatimangan08

It is difficult to tell the whole story about how a power system works to a power system electrical engineers if they don't recognize the fact that power system dynamics are partly mechanical engineers major.

As long as you can agree that poles can slip then it is easier for you to see two parallel generators can have difference frequencies. Why is that so? Because nothing can stop them to behave that why, since the poles can slip. It is harder for you to believe my point of view if you believe poles cannot slip. Doesn't matter what.

Since you have mentioned the poles can slip then what stop the two generators to rotate at difference frequencies sustainably long? My short answer at this point is system protection. What can make it to happen? Two things that I know. Firstly transient disturbances. Secondly, poor selection of inertia size of a turbine generator with respect to it own ramp rate and relative to inertia and ramp rates of other generators in the system.

You should know better than me that two generators in parallel will go out of step if their synchronism torque angles differ by greater than 180 degrees. Each generator should have out of step protection. Not to forget overspeed protection. Why these two protections shall be there in the first place if two generators cannot go to a serious slip poles?

To take your challenge, I have seen both events. Steady state and transient slip poles.

I have seen two areas with frequency differences by the order of 0.02Hz-under steady state operation. We installed a dedicated system just to see such event. The system is called "Wide Area Monitoring System (WAMS)". The readings were taken a few hours before one of our major steam turbine generators tripped off, "coincidentally" due to "protection shutdown due to negative feed forward load". The plant load prior to that tripping was 650MW.

Why negative feed forward load? As you mentioned a generator is only looked at its speed to adjust its "feed forward load" via its speed droop. Negative feed forward load could only be triggered if its generator feed forward load was minus 650MW. The plant controller will bring the generator into reverse power if protection shutdown was not triggered. So there was nothing wrong with the protection logic.

For 5% droop set point , 50 Hz system, a 700MWe rated generator, therefore frequency bias setting will be 28MW/0.1Hz. From back calculation the speed droop for that generator should have sensed its speed had reached >52.3Hz! Otherwise it was unlikely negative feed forward load could have triggered when the plant was doing 650MW. I was thinking the other possibility that the plant was doing AGC during that event. If this was the case that the feed forward load could have been due to the AGC-ACE command. Not by droop. So that my calculated generator frequency can be wrong. But from the trip report, it was mentioned that the plant was not under AGC. It was under manual load control.

There was no such higher frequency being captured by the WAMS, before and after the event. This is expected since WAMS data at the moment measures frequency at HV side. At least not at that particular generator side.

As you can expect the system frequency felt from 50 to 49.6Hz. We had Under Frequency Load Shed (UFLS) protection operated. That was because some other reasons that I don't want to include in this discussion. Normally our UFLS shall not trigger if loss of generation is less than 800MW.

There was another "interesting event" that I have already shared regarding a 28MW hydro turbine generator went overspeed if its load was raised more than 17MW. Four times in a single day....

Maybe there was a poster here tried to suggest it was a made up story. The truth is that it is real. The same generator now is still limiting its load up to 18MW since the problem has not been fixed yet. It has improved by 1MW since then. But still long to go to achieve its rated maximum.
 
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Namatimangan08

>I cannot help but feel a fundamental
>point is being missed in this entire
>discussion. Everyone is focusing on the
>generators. Conservation of Energy is
>missing from this discussion!

I have tried to go along this line a few times. I don't know due to some reasons not so many posters here like to go along this line.

Here is the simplest energy balance equation to describe how power system works using a proven scientific method.<pre>
Int(P_m)dt -Int (P_e)dt = 0.5Iw^2 Eq(1)

Where

Int = integration function

P_m = mechanical power

P_e = electrical power

w = angular velocity

I = second moment of mass (Electrical engineers normally use symbol J)

t = time</pre>
Lower integration limit for the above equation can be assigned as zero. Higher integration limit could be at any time we opt to measure energy balance of the system.

If P_m=P_e, then the system is called to operate under a perfect steady state or dw/dt=0.

There is no such thing of continuous perfect steady state condition. As long as T_m-T_e does matter much to the system dynamics stability then who cares?

More often many people like to think in such a manner that the RHS of Eq(1) is zero. This simplify the explanation about how a power system works a lot. It is a matter of fact controlling a power system can be dedicated to managing the value for RHS of Eq (1), i.e. to maintain system frequency at the nominal frequency whether during steady state or calculated transient load change.

Such equation has its root from one of the Newton's motion laws. the basic form of the law related to the above is:<pre>
Id^2A/dt^2 = Applied torque- Resistive torque Eq(2)

Where

A= angular displacement of the rotating mass</pre>
Now, such Eq (1) assumes the system consists of three entities, namely traction load, resistive load and inertial energy of rotating mass. In reality, rarely anybody could see a power system consists of these three entities. Assuming we have 20 turbine generators attach a grid system. Then the dynamic behavior for each generator can be expressed by 20 mathematically equations such as the following: <pre>
Id2A/dt^2 + cdA/dt +kA = T_m-T_e Eq(3)

Where

c = damping coefficient

k = stiffness constant </pre>
The dynamics behavior for each turbine generator is determined predominantly by I and c in Eq(3). There is no way to make each turbine generator in a grid system to have the same per unit value for I and c. For example a hydro unit has per unit inertial energy constant between 1-2.5MJ/MVA at 60Hz and a condensing ST unit has per unit value constant between 8-9MJ/MVA at 60 Hz.

When the system goes through a steady state and transient load disturbances, each generator will swing according to second order D.E as given by Eq (3) above. Straightly speaking, the grid frequency does not exist. It is actually the net result of each swing equation of the turbine generator and opposing torque of the system!

The argument described in the preceding paragraph is important fact to explain that it is virtually impossible to have two generators in a grid system to rotate at exactly the same frequency at all time. As long as you believe poles can slip relative to the dominant frequency, there is a chance that you can see this is true since each generator will swing according to its own Tm-T_e, I and c values.

But then, why I can describe how the system at works without understanding these fundamentals? Maybe the answer is this-This is because engineers that designed the power system have already taken into consideration that each turbine generator in a power system shall be able to swing as close as possible relative to the other units in the system during steady state operation and calculated transient disturbances. Some of the main parameters that they have mean to control are: I, c, ramp rate for each generator, the magnitude of probability loss of generation, the magnitude of probability loss of demand etc. For example, what happens if we make a 10000 RPM generator close its breaker to a grid system that is operating at 3000RPM? Do you think that generator will rotate at 3000RPM just because the grid does so? Unfortunately you don't see such generator since it has never been allowed to enter any grid in the first place.

I wish I can make it simple. Unfortunately it cannot be made simpler than the need to understand Eq(1)& Eq (3) above.
 
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not_quite_nyquist

Two things:

Poles should never slip. If they do, you've got big problems. See GE's "Art and Science of Protective Relaying" chapter 10 for more information (it's free on their website). Agreed that units, even at stead state, are swinging against each other and are probably never at identical speed, but they should never be anywhere close to slipping a pole... Maybe we just have a difference interpretation of what "slipping a pole" means.

Second,
> I wish I can make it simple. Unfortunately it cannot be made simpler
> than the need to understand Eq(1)& Eq (3) above.

Try stating your Eq1 without the integration. Differentiation has always had a clearer physical meaning... rate of change.

Pmech-Pelec=J*dw/dt

When Pmech=Pelec, Pmech-Pelec=0... so dw/dt (rate of change of speed) must equal 0 since J is a constant... which means everything is perfect, speed is not changing and mechanical power input equals electrical power output. Any time Pmech does not equal Pelec dw/dt will be non-zero, meaning w (speed) is changing.
 
if the load is increased on the generator it means that the armature current is increased so that the armature reaction will increase and so is the synchronous reluctance due which the reverse motoring effect on the generator will increase if the power input to the generator in fixed load increase will lead to a decrease in speed of generator as the input torque is same but reverse torque due to load increase has been increased.

now when the speed of the generator increased power output also increases, actually the question is a bit uncleared as no conditions have defined.

anyhow lets examine both
1.stand alone
2.parallel operation

in first case if the generator was supplied more fuel is supplied to generator it will increase the input torque and due to which more load can be supplied against the rated speed of the generator. actually fuel input or input torque defines the no load speed of the generator and as the no load speed set point increases generator out put increase up to rated speed say 3000 rpm. beyond this an increase in speed will also increase the voltages.

in second case if the fuel in put is increased the load sharing by that generator will increase also the system frequency/ speed of generators will increase.

the third is the case of OTC control in this case as the frequency of the system increases mass flow of the compressor increase due to which outlet temperature decreases then the set value due to which fuel input increases to increase the exhaust temperature and due fuel increase input torque increases and so is the out power of generator.
 
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