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?
The only way that an in increase in electrical load can decrease speed is if the load is greater than the generation. So, if the load is 20MW and the frequency is stable, if the load increases to 21 MW (actually any value above 20MW) and fuel is not increased then the speed (and the frequency will decrease).
Think about riding a bicycle along a flat road at a stable speed which is about three-fourths of your maximum speed and you need to maintain that steady speed for the duration of your ride. And you are approaching a hill. A hill that is long and fairly steep.
As you start up the hill, you increase the torque you are applying to the pedals to maintain your speed. But, the hill is long and you reach the limit of your ability to produce torque and maintain the speed and the bike begins to slow down.
A generator is a device for converting torque into amperes. Power is expressed by multiplying volts times amps (basically) and since generators generally run at a relatively constant voltage (usually no more than plus or minus 5 percent of rated terminal voltage), the power produced by a generator increases and decreases as the amperes that are flowing in the generator stator windings.
And, to increase the amperes it is necessary to increase the torque input into the generator from the prime mover (be it a reciprocating engine, a combustion turbine, a steam turbine, a wind turbine, a hydro turbine--any device that can produce torque). More fuel equals more torque; less fuel equals less torque. Just exactly like on the bicycle, in the example above and in the real world.
When a generator is paralleled with other generators on an alternating current grid, the load is the sum of all the lights and motors and computers and other electrical loads. The total amount of electrical generation must exactly match the amount of electrical load in order for the grid frequency to remain at rated. If the total generation exceeds the load then the frequency (and the speed) of all the generators will increase above the desired grid frequency. If the total generation is less than the load then the frequency (and the speed) of all the generators will decrease below the desired grid frequency.
And one of the most important aspects of any AC grid is its frequency (in most parts of the world).
The frequency of an AC machine is expressed by the formula:
F = (P * N) / 120
where F = Frequency, in hertz
P = the number of poles of the generator rotor
N = the speed of the generator rotor (in RPM)
When synchronous generators (alternators) are connected in parallel with each other on an AC grid, they are all operating at a speed that is directly proportional to the frequency of the AC grid. No generator can go faster or slower than the speed which is proportional to the frequency.
There are great magnetic forces at work in the synchronous generator to keep the rotating magnetic field of the generator in locked synchronism with the magnetic fields induced in the stator winding by the current flowing in the stator windings. These forces keep every generator's rotor locked in synchronous speed with the frequency of the grid with which they are connected.
The production of electricity is all about producing torque in one place, to be used in another. The torque is converted to amperes, transmitted over wires, and then reconverted into torque. So, generators are just supplying torque from where they are located to many different locations--anywhere wires can be run.
So, I would like to know how and when you experience a decrease in speed when the load increases. Are you speaking of the entire grid? Or just a small isolated generating "island" and it's load?
i think what you have provided is wonderful and very useful. but a question in my mind is that, like in synchronous motors, is it not possible that the speed remains constant and angle b/w the excitation voltage and terminal voltage change so that the net torque required is met by the the current due to change in angle. normally what happens in motor the reverse of that can be assumed to be true in generators. but in synchronous machines the case is coming out to be different. motor is constant speed, whereas in generator i think nothing is constant.
also a second doubt. if we look at a vector formula then :-
E = V + IZ
now in generator, when load inc IZ inc , also speed decreases so E decrease. due to armature reaction V also decrease(generally). how can all the 3 parameters change simultaneously ?
If there is no automatic governor on the prime mover driving the synchronous generator providing some kind of speed/load control for the prime mover and the generator rotor, and if there is no automatic control of the generator terminal voltage, and if the generator and prime mover are being operated independently of other generators and their prime movers, then if the load (real or reactive) changes speed can change and generator terminal voltage can change and armature reaction has an effect on speed and load and voltage.
In the real world where prime movers used to drive synchronous generators have automatic governors to control speed or load, and synchronous generator excitation systems have automatic regulators to control generator terminal voltage (or VAr setpoint or power factor setpoint), when loads change the governors respond appropriately to maintain speed, load, generator terminal voltage.
It would be disastrous to operate a prime mover and generator in any kind of application (supplying a small isolated load independent of other generators and prime movers, or synchronized to a grid with other prime movers and generators) without a governor that was capable of responding appropriately to load changes and without an exciter regulator capable of responding to VAr changes.
All of this counter emf stuff is wonderful in that it helps us to understand what's physically happening inside the generator and possibly how generators are designed and constructed, but it doesn't help us to understand how generators and their prime movers are operated in the real world, and how to operate them reliably and properly to supply power to loads at stable speed (frequency) and load and reactances.
It's very important to understand all of the components of equipment that produces electrical power. There must be a source of torque and there must be a source of excitation. The torque is provided by the prime mover (turbine, reciprocating engine, etc.), and the excitation is provided by the exciter regulator, sometimes called the AVR (Automatic Voltage Regulator). When there is a source of torque (provided by the prime mover) and voltage (provided by the exciter regulator and the rotating magnetic field of the generator), the generator can convert the torque into amps. The torque must generally be provided at a specific frequency, which is directly proportional to the speed the prime mover is spinning the generator rotor. The speed of the prime mover can be controlled by the prime mover governor.
Further, when a synchronous generator and its prime mover is operated in parallel with other synchronous generators and their prime movers, the speed of all of the generator rotors (and hence their prime movers if directly coupled to the generator rotors) is fixed by the frequency of the grid. If the grid frequency goes up, the speed of all the generator rotors goes up at the same time. Conversely, if the grid frequency goes down, the speed of all the generator rotors goes down at the same time. It is the job of the grid/system operators to control the amount of generation so that it exactly matches the load on the system so that the frequency remains relatively constant; failure to do so can result in unstable grid frequencies.
And if the grid operators don't account for the reactive "loads" of the grid, then the grid voltage can also be unstable or too high or too low.
Everything is related, but it's really important to consider all the conditions of operation, and many times textbooks and references don't properly state all the conditions when they're explaining these very important principles.
So, yes, in the absence of any kind of "response" to changes in load then speed and voltage and counter emf can all change. But, that just doesn't normally happen in the real world of electrical power generating equipment.
While agreeing with all that was said above, I am not sure whether Salman's situation was actually referring to situations where you have an isolated and very finite grid. Isolated grids have an added limitation in that keeping exactly 50Hz (or 60Hz for all that matters) is somewhat difficult, or puts too much demand on controlling/governing systems. In such environments it is normal to accept some deviation from the nominal frequency.
Given this it is observed that the actual load is dependent on the frequency at that time. One must keep in mind that certain loads, especially motor driven loads, are speed/frequency dependent, and so if the frequency falls, their power demand falls also. Water pumps are a case in point.
In such situations one observes that the system manages to stabilise at a different frequency with minimal control system intervention, eg. 49.95hz for 50Hz systems. Obviously to bring the frequency back to 50Hz, one needs to increase the power input to the generator prime mover, thus ending up increasing the speed/frequency of the system.
And this I believe this is what Salman was commenting upon when he said that if they increase generator rpm they increase the power of the generator.
Frankly, I didn't really know how to respond to Muhammad Salman's post, but made an effort anyway. His summary asked about decreasing speed with increasing speed, and his post talked about decreasing speed with increasing load, and increasing load by increasing speed.
Would you agree that if a synchronous generator is being operated in parallel with other generators that an increase in load (on the system!) would generally have little or no effect on a properly operated system (grid)? A change of 0.001 Hz is virtually imperceptible on the operator interface of most prime movers.
I really wonder if some operators actually watch prime mover speed when they are "changing load". I believe the assumption is that as fuel is increased during starting and acceleration, that when load is "increased" after the unit is synchronized to the grid with other generators that speed will change with "load" changes. In other words, that increasing the fuel flow when the unit is synchronized will have the same affect as increasing fuel flow when it's not: that speed will change.
All they are really doing, when they are connected to a grid with other generators, is changing the amount of load their generator is providing. They aren't changing the load of the grid. And, the speed of their unit usually doesn't change by a perceptible amount, or an amount that is proportional to change in fuel flow that would be experienced if the unit was not synchronized with other generators.
The point of reference of most of the questions regarding speed and load and counter emf of synchronous generators is not clear at all.
As Muhammad Salman has not responded, we don't know if his question was answered or not.
Thanks a lot. A large part of my doubt is clear now. if you know any good reference book do tell me. i want the effect of load on an ISOLATED alternator, without keeping anything constant, i.e. just an isolator supplying a variable load. And thanks again for the information.
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.
However in small island systems, e.g. where a 30MW generator supplies 10% of the total system demand, a change in generator output will have a big effect on the system frequency. In such situations, one observes that to maintain system frequency, the prime mover governors are constantly acting, due to the constant corrective action of the droop control. Droop settings of 4% to 5% are used to create some system stability, obviously at the expense of not maintaining the system frequency exactly 50Hz (or 60Hz as the case may be). The load manager then corrects the generators' setpoints to maintain the frequency close to nominal, and this is done at a much slower rate.
Hope this clarifies my point.
I have done some shipboard generator control work and troubleshooting, and the "islands" don't get much smaller than that. (Though some naval vessels are bigger than some countries I've worked in!) And, in all cases, even when dockside and loading and unloading with large shipboard cranes, the emphasis was always on frequency control, keeping the frequency as close to the setpoint as possible. This takes some good operational skills, and some good governor tuning, as well as good communications between the deck and engineering crews. The Chief Engineers would get really upset if the frequency wasn't controlled stably, and the Chief Mates would get upset if the cranes became sluggish and unresponsive. It's a learning experience for all, and some learnt the lessons better than others.
Your point about smaller grids is well taken, and I do presume that people consider the relative size of generators compared to the grid when taking into account the effects of adding or removing generation. Most of the smaller grids I've worked on used 20-, 25- and 40 MW gas turbines for main generation, with some smaller steam turbines (less than 15 MW, if that large). A few locales had multiple 70- or 110 MW gas turbines, but those were larger peninsular grids with more load and generation than smaller regional grids.
Thanks for your help with these posts; your clarity is most welcome!
I wish I could understand all of these esoteric questions about emf and counter emf. I recall when I was in university how confusing the texts were about this versus our laboratory exercises where we had to learn about frequency control, isochronous and droop speed control, and paralleling/synchronizing. I just consider all of that emf and counter emf stuff as transmission method "background" stuff; it's nice to know but it's not ever measured in the day-to-day operation of power generation equipment.
At any rate, we shall continue to endeavor to persevere, shall we not?
> 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
Rate of decay = 60/((2 X 10^13Joule/(1000*10^6))
=0.003Hz/second (0.2Hz in 100 seconds)
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.
Your explanation is good. However there is a grey area wherein you talk about the additional torque being converted to Amps. It is the only possible result when the speed of the synchronous generator is held constant and if you try to increase the torque. Can you try to explain the transfer of torque to amps.
Electrical machines (motors and generators) are devices for converting electrical power into mechanical power (motors) and converting mechanical power into electrical power (generators).
There is virtually no difference between a motor and a generator. In fact, in some applications the electrical machine is used as both a motor and a generator. The difference is whether or not torque is being produced by the electrical machine (in this case it's a motor), or whether the machine is converting torque into electrical power (in this case it's a generator).
That's what generators do: They convert torque into amps. Motors convert amps into torque. Wires connect motors to generators. So, in effect, the torque being produced by the prime mover (turbine; reciprocating engine; etc.) is supplying the torque that the motors connected to it are supplying to their loads--through the wires that connect the motors to the generators.
That's why we produce electricity: To easily transmit torque from one place to many places using wires.
There are mathematical formulae that could be used to explain this, but you can find those on many Web sites if you need them. (I note you didn't question how motors produce torque from amps. It's exactly the same phenomenon, just in reverse.)
well once again i have to respectfully disagree/ slightly change what csa has said in his post regarding converting of torque into amps in a generator.
The total current in a generator is a vector addition of active current and reactive current , torque is only responsible for the active current not the reactive current. a more correct explanation would be that the mechanical torque applied to the shaft is converted to active electrical power.
in a steady state condition the mechanical torque applied by the turbine is equal to the backward electromagnetic torque produced by the generator. this is the reason that the machine is running at a constant speed. thus ignoring the losses the mechanical power is equal to the electrical power produced. if there is a change in the mechanical or the electrical load in the machine acceleration or deacceleration of the machine takes place. for example if the machine mechanical input is increased, the machine accelerates till a new steady sate is reached.
The originator of the thread asked why the machine speed decreases in case of a electrical load increase. This can be explained by the governor droop chara.
The droop chara of the machine is given as 4-5%. droop is defined as the percentage negative change in speed when the machine is loaded from no load to full load. a very simplified explanation is given below
under steady state condition Power mech = Power electrical power
if there is a small increase in the electrical power then
deacclerating power = electrical power - mechanical power
this difference causes the machine to deaccelerate and thus reduce the speed. if there is no governor and the mechanical power remains the same the speed does on decreasing. however when a governor is present , it senses a reduction in speed and increases the fuel input thus increasing the mechanical power , thus reduction in speed is limited to the droop percentage.
Synchronous machine chara.
Though the above machine is a simplification of what happens during a machine loading and unloading. The machine actual parameters can be visualised by the operating diagram of the machine. I am uploading a small picture here. it represents the machine operating region. here
E - Generator field voltage
V - Generator terminal Voltage
xd - Machine impedance
I - current output
delta - machine load angle
phi - power factor of the machine
The region OPQR represents the stable operating region of the generator. P represents the maximum power output from the machine. The curve QR the maximum
excitation of the generator. lines parallel to the X axis are constant power lines while circle (arcs) drawn from the center O represent constant excitation.
The Tip of the point E is the operating point of the generator. you can see in the diagram that the operating point E is at the intersection of the constant power line B and constant excitation circle B'. The equation is given by
E (angle delta) = V (angle zero) + I(angle phi)*Xd
Varying the excitation without changing the power
In the initial operating diagram we see that the operating point lies in the constant power line B. if no power input is increased the generator power output follows this straight line. now if the excitation is increases the magnitude of the E increases and shits to a new excitation arc C'. thus the new operating
point is E' which is a intersection of the constant power line B and the new excitation arc C'.The effect of such a operation is that the power factor of the machine reduces as shown in the figure.
Varying the power without changing the excitation
In the third diagram , we actually increase the power input to the turbine which increases the power output from the generator. now the power line shifts from B to C. but as the excitation is not varied it remains in the same curve B'. thus the new operating point is a intersection of the new power line C and the old excitation line B'. the effect of such a operation is that the machine load angle increases. The deaccleration power mentioned in the post is the one which increases the load angle thus facilitating the transfer of more active electrical power.
what i have presented is a idealised case , but in real operation both the power and excitation is varied thus the final operating point is a combination of the two.
Attempts are made to try to keep the explanation as simple and real-world as possible, and some assumptions have been made.
And we're talking about units with properly acting governors, in any mode (droop or isochronous), and we should be referring to stable grid frequency (unless otherwise stated).
In general when someone asks about loading a unit, they are not usually asking about changing the reactive component of the load. If they are asking about the reactive component of the load of an alternator they will usually use the term VAr or power factor, or, they will talk about "reactive power" (which as we all know is a no-no on this site).
In a real world situation where there is no VAr or Power Factor control in operation on the generator (alternator) exciter and when an operator "loads" a unit the excitation generally remains constant because it is manually operated. Until the loading is complete, at which time a duly vigilant operator will check the VAr meter or the power factor meter and then adjust the excitation to maintain the desired setpoint.
Without vectors and formulae and neglecting the reactive current component, which the originator did not ask about, the explanation given was valid. We have to be very careful here on control.com lest the 'Exclamation Pointer' chastise us for incorrectly referring to reactive "power" in our discussions, which makes this forum different from all the other discussions of alternator operation and loads in the world. (Aren't we lucky?)
It would be very interesting to know how much the speed (RPM) of the prime movers and generators (more correctly called alternators) at the site where ProcessValue works decreases when loaded (or increases when unloaded), either "electrical power" (amps) or reactive current. As used in this context, loading and unloading refers to increasing, or decreasing, respectively, the amount of torque being produced by the prime mover and transmitted to the alternator. And this question would be presuming a stable grid frequency which is at or very near rated frequency.
The answer should also include the time period the speed changes are observed to occur. Is it 0.00095 seconds? Or is is 9.995 seconds? Or, does the speed/frequency drop when some load is applied and remain there until an operator takes some action?
And, how would a prime mover and alternator behave if a unit were synchronized to the grid without a governor and then electrical load were "applied" to the unit, what would the speed do? (Without a governor there would be no droop- or isochronous speed control.)
In the real world, when alternators and their prime movers are operated in parallel with other units on a grid with a stable frequency (an "infinite" grid as some would say), when an alternator is "loaded" there is an imperceptible change in speed. Granted, there is an acceleration/deceleration and change in load angle (which is invisible to the eye, naked or not) but for all intents and purposes the speed of the unit, and the frequency of the grid, doesn't change as machines are loaded and unloaded unless there is an imbalance between generation and load.
In any case, we are not talking about percentages of speed, like 1% or 0.25% or 2.34%. We're talking about hundredths and tenths of RPM for split seconds and fractions of a Hz for split seconds.
So, ProcessValue, how much does the speed of the units at your site change when they are loaded and unloaded and for how long does this speed change exist? The question is regarding increasing (or decreasing) the amount of torque being provided by the prime mover to the alternator. You can state if reactive current is constant or not, but the question should be viewed in the context of stable grid frequency when the units are operated in parallel with the grid. And, you should also tell us by how much the speed/frequency changes and for how long if the units are being operated independent of the grid ("island mode").
Anxiously awaiting your response--with or without vectors or formulae.
Inquiring minds want to know what kinds of speed changes we're talking about and for how long these speed changes last on real world units with properly acting governors, in either droop- or isochronous speed control.
CSA makes my life difficult by assigning my difficult tasks, lol ; just kidding. well this one is going to take me a little bit more time. I am taking 3 days off and will be going to the site on 3'rd. but this is what i am goint to do.
the question piqued my interest on how to simulate the loading and unloading of the machine that too by a significant load and sudden load. the normal raise / lower will not work here. the reference change too small to be recorded. to really feel / record the change the speed a minimum of 2 MW ( at present at a site with frame 5 machines) sudden loading and unloading should be there. i cannot go and ask for a sudden feeder charge or turn on a motor, but i can do this.
" Test procedure " ;)
The machines at the site feed to a section load of 14 - 16 MW and have a grid transformer back up.
a. parallel the machine to the grid. keep the machine under 2-4 MW export, ie keep the machine more then 2-4 MW more than section load so that the excess is exported through the grid transformer. Now open the grid transformer thus simulating the grid islanding, the machine will be suddenly unloaded by 2-4 MW.
probably what is going to happen is that there will be a speed oscillation and will settle according to the droop chara.
b. the reverse of the operation, ir keep the section under 2-4 MW import and open the grid transformer. this will simulate the sudden loading of the machine.
in both the above cases i will keep the VAR export/import as zero, thus in effect simulating a loading and unloading of a unity PF load :).
i will also run a trend recorder for DWATT anf DF with 40ms resolution, hopefully i will get the desired results with this.
CSA, if you have anything to add to the above test procedure, or want a remakeover of the procedure please tell me. i will consult with the operations team and try to do it. there is a TG under shut down at site and they are keeping all the units under import and continuous import from grid. hopefully they would have started the machine by Monday and i will be able to do the above " experiment ". but as i said i need a little time, but i will post my answers by jan 1st week.
I am also working on a simulation with ETAP, the models are coming on nicely i will post the results here. perhaps then we can compare the simulation and real world results.
And i nearly forgot, CSA, Wishing you a Happy and Prosperous NEW YEAR.
This test that ProcessValue has devised does not meet the requirements of the request posed to him.
It seems what needs clarification is the definition of "loading" and "unloading" and "electrical load" (or "load").
I will grant that one definition of "load", or "electrical load", is the amount of motors and lights and computers and other devices drawing power from a grid.
But, operators don't have control over the electrical load on the grid, only the "load" the prime mover(s) and alternator(s) they are operating can "assume" from the total load being supplied by all of the alternators and prime movers connected together on the grid.
So, another definition of "load" is the amount of the electrical load that is being produced by the prime mover and alternator, which is a part of the total electrical load of the grid with which it is being operated in parallel with other prime movers and alternators.
Operators don't have control of the numbers of motors and lights and computers, or the load on the motors. They can only control the amount of power their prime mover and alternator is contributing to support the total electrical load. Operators refer to the amount of the power their unit is providing to the system as "load". This is the "load" of their unit, which is only a portion (sometimes a very minute portion) of the total electrical "load" on a system to which is connected.
In other words, when an operator raises, or increases, the "load" on a prime mover and the alternator it is driving he/she is not changing the electrical load on the system--only the amount of electrical load being provided by the alternator and prime mover under his control. That's what the operator knows as "load"--the amount of power being produced by the unit under his/her control.
My definition of "loading" and "unloading" a prime mover and alternator being operated in parallel with other alternators is to increase the load being supplied to the electrical system by increasing the energy input to the prime mover, not by adding or subtracting electrical load from the electrical system to which the alternators and prime movers are connected.
Now, when the "load" of an individual unit (prime mover and alternator) on an electrical system increases while connected to a normal grid in parallel with multiple alternators and prime movers, if the electrical load on the grid does not change then what would tend to happen is that the grid frequency will tend to increase. (In this scenario, the total electrical load on the system (the numbers of motors and lights and computers) would need to increase by the same magnitude at the same rate in order for the grid frequency to remain absolutely constant. Or, ... read on....)
But, the diligent and proper operators of a grid will--either manually or automatically--unload another alternator and prime mover (or multiple alternators and prime movers) in order to keep the total generation equal to the total electrical load thereby keeping the grid frequency relatively stable. If they have a machine operating in Isochronous mode (or several operating in Isochronous Load Sharing, or some other kind of automatic frequency control scheme) the grid frequency will remain relatively stable.
In actuality, what happens on many grids is that the droop action of many of the prime mover governors will sense the change in speed and will therefore reduce their power output in order to maintain speed (presuming the units are not using GE's version of Pre-Selected Load Control!). In other words, when the differential between the turbine speed reference and the actual turbine speed changes the governor will counter that action to maintain the same differential.
The originator has never responded (not with the same "name" as originally used anyway) to clarify his open question. So, some assumptions were made, and hence the response that was given.
A subsequent poster (at least someone using a different name who did not identify himself as the original poster) asked about alternators operating independently of a grid and without any governor/control, which is not the original question.
And, still, I have yet to encounter a real prime mover and alternator being used to produce electricity that didn't have some kind of governor: electric, electronic, hydraulic, mechanical or some combination thereof. A prime mover driving an alternator supplying a variable electrical load without a governor is a laboratory experiment, not a revenue-producing machine.
So, if the turbines and alternators at ProcessValues's plants are loaded and unloaded by manipulating the amount of motors and lights and computers connected to them, then the test would be a valid one. These are the normal kinds of conditions that operators encounter--not the manipulation of electrical loads (numbers of motors and lights and computers) to change the load of the alternator. Unit operators don't increase and decrease the "load" of the unit (prime mover and alternator) by changing the energy being input to the prime mover--NOT by changing the number of motors and lights and computers connected to the system to which the unit is connected.
But, if the units at ProcessValue's plant are loaded and unloaded by increasing or decreasing the amount of fuel being admitted to the turbines, then test he has devised is not a valid test per the question.
A valid test would be to run a trend, while the unit is operating on a stable grid in parallel with other units at a stable frequency and to increase or decrease the fuel being admitted to the turbine and observe the change in speed while monitoring the "load" being produced by the alternator. We want to know how much the speed (frequency) changes when fuel is changed and the electrical load being produced by the alternator being driven by the turbine changes while being operated in parallel with other prime movers and alternators on a system with a stable frequency.
No more and no less. Just as during normal unit operations in every part of the world where multiple prime movers and alternators supply an electrical load consisting of motors and lights and computers.
Process Value's site seems to be in India...... and I am not sure which state in India can claim to have a 'stable grid'..... :).... So I guess, the primary condition itself will not be met for the test.....
Sorry for diverting the thread with an insignificant input.....
That's one of your strong points, Rahul P. Sharma. We're still waiting for the frequency readings from the speed pick-ups of the Mark II and Mark V units from your site to see if the two units are running at different speeds while connected to the same grid. And for the Mechanical Dept. to provide the nameplate data from the load gear box nameplates.
As ProcessValue has pointed out, no place in the world has a perfect grid frequency, but as long as the frequency isn't changing by more than +/- 0.25 Hz in a very short period (seconds or less) we could review the results.
The point is that units are not normally loaded or unloaded, except possibly at ProcessValue's site, by "throwing on" or "throwing off" blocks of electrical load as he wants to do with his test. They are normally loaded and unloaded using the RAISE SPD/LOAD and LOWER SPD/LOAD buttons/switches/targets (or the Preselect Load Control enable functions, which essentially drives the turbine speed reference up and down just like the RAISE and LOWER functions).
What we want to know is how much the actual running speed of the turbines at ProcessValue's site change by and for how long when they are loaded and unloaded using the RAISE- and LOWER SPD/LOAD functions, which is how units are normally loaded and unloaded around the world. Not by throwing on or throwing off blocks of load, which is not a typical loading or unloading method.
CSA , the present site i am working on and also incidentally which happens to be my "parent site" is a refinery, and almost all the sites i have worked on are refineries (that is where they send me usually). here the electrical load manipulation works in many ways. you can view my site as a bottom up co-generation plant. the GT predominantly supply electrical power to the section load in the refinery but the GT's are also kept in parallel to the grid as there is a PPA with the state power operator. thus a min power export of 2-3 Mw is maintained. Inside the refinery the operators are the people who give clearance to the HT or large motor starting. Thus in effect the plant operators have certain degree of control to the electrical load in the refinery. and also they need to maintain the export so they also have control over the prime mover to increase or decrease the load when under parallel to the grid. so in effect both the operations specified by you are done.so i have went ahead and done a battery of tests. There are certain restrictions in the operations and certain limitations in the test setup (i have explained them in part 2 of the explanation), but i have done as much as i can , which included cajoling , pleading , begging :P plant supervisors . lol .
One of the main reason why i said devised the test about sudden loading and unloading is because , it is only then we will able able to get an adequate hunting in the generator which will hopefully give the disparity between the turbine frequency and the grid frequency. for a normal loading and unloading which is done at a constant and controlled rate it will not be possible to "see" or get this experimental data. the machines in refineries are small, they will have no effect on the grid whatsoever , imagine trying a auto loading of 2-3 Mw on a 22 MW machine in a 48000 MW grid. and CSA in your earlier post you have mentioned on the frequency change in a independent machine also. the frequency change in the independent machine can be done in two ways . one is by fuel change and other is by load change. my experiment was specifically aimed at that. any ways i am presenting the data in three parts go through them and tell me if you are satisfied ( yes , yes i know you are a hard man to impress :P ) , and also if any more clarifications are needed in the explanations given.
I am spacing my answer into three parts
Part - 1 : The theory - this section will explain with vector diagrams the response of the machine in parallel and independent condition.
Part - 2 : The experiment - i did a few experiments to compliment the theory part , this is to give a real world example of the theoretical conditions explained. and also as asked by CSA the experimental data for his quiries. This section contains trends , and trend data in csv files for readers here to take and analyze.
Part - 3 : The Grid - There seems to be a lot of talk about how the grid operates. I am explaining my view on it. I am also uploading a document on the operation guidelines and philosophy of the southern gird (India). people who are interested on grid operation can read it as it is an excellent material on grid operation in india and also in general.
The generator doesn't hunt.
The generator prime mover's governor will hunt if not properly tuned. And we're supposed to be talking about properly acting governors. Not laboratory exercises.
When your plant is connected to the grid, if you start a large motor the grid will supply that power until such time as your operators increase the power produced by one or more prime movers to return the export to 2-3 MW. In fact, if one of the turbines trips, won't the refinery continue to run on grid power? (Even if there is some load-shedding scheme in place/required?)
When you are connected to a sufficiently large grid, there is no difference between turbine frequency and grid frequency. Your little 25 MW unit isn't likely to have much of an effect on a 2000 MW grid, or even a 1000W grid, or even a 600 MW grid. The frequency of all the machines connected to the grid is the same--because they are synchronous machines. Synchronized together.
Even on a grid composed of two 25 MW machines, the speed of both machines is identical and is directly proportional to the frequency. And if the power produced by the two machines isn't equal to the power being consumed by the load, then the frequency isn't going to be at rated.
The question remains: How much does the speed of the turbines at your site change when they are loaded while connected in parallel with a other machines on a grid of relatively stable frequency? Even if the frequency isn't 50.0 Hz, how much does it change when you increase the fuel to one of the turbines causing it to accept more of the load on the grid? And for how long does the speed change?
" The generator doesn't hunt.The generator prime mover's governor will hunt if not properly tuned. And we're supposed to be talking about properly acting governors. Not laboratory exercises."
Not entirely true , governors are tuned for and at steady operation and to an extent small signal disturbance. For transient condition the generator will hunt before setting to the final steady state condition. an example would be , synchronizing , large motor start in the section , sudden frequency change in the grid , transient fault conditions.
I have given experimental data on all the above , in all the condition , synchronizing , large motor starting , and sudden frequency change the MW output of the machine hunted before it settled down on a steady state value. How well it recovers from the hunting depends on how well the governor is tuned. Governor cannot totally prevent a load hunting it can dampen it and stabilize it as quickly as possible. and in this regard it is not only the governor of the generator which plays the part, the AVR is also hugely responsible for maintaining a stable operating generator. Modern AVR's are equipped with
a. Load angle limiters
b. Over excitaion limiters
c. Inductive current limiter
d. Capacitive current limiter
e, v/f limiter
f. Power system stabilisers
to name a few. They help in reducing the extent of the hunting and the reduce the time needed to settle down to a steady state. Generator hunting are inevitable due to the nature of the gird and the nature of the loads.
" When your plant is connected to the grid, if you start a large motor the grid will supply that power until such time as your operators increase the power produced by one or more prime movers to return the export to 2-3 MW. In fact, if one of the turbines trips, won't the refinery continue to run on grid power? (Even if there is some load-shedding scheme in place/required?) "
True , this is exactly what happens in the steady state condition. I have given the motor starting trends , if you will see in that the machine is the one which actually takes up the load first (transient) then it reduces. yes in case of a machine trips the grid will supply power.
"Even on a grid composed of two 25 MW machines, the speed of both machines is identical and is directly proportional to the frequency. And if the power produced by the two machines isn't equal to the power being consumed by the load, then the frequency isn't going to be at rated."
Yes in a grid composed of two 25 MW machines the frequency is identical. But i do not get your point about power produced by the machines not equal to the power consumed , under steady state condition the power produced by the machines will always be equal to the load power + losses. even in a small micro island it is possible to run the machine at rated frequency.
The generator (alternator) is a "stupid" device. It just converts torque into amps, and in the process can handle some reactive current. (I almost said power! But I did use an exclamation point! Oops, I did it again.)
The alternator is driven by the prime mover; the reactive component is driven by the exciter regulator. The prime mover governor can hunt, and the exciter regulator can hunt. But the generator doesn't hunt. Only the devices that drive the loads connected to the generator can hunt, making it appear that the generator is hunting but it's really the drivers that are hunting.
Any instability is due to transient conditions being reacted to by the prime mover governor and/or the exciter regulator.
But we digress. Because, again, the focus is being distracted from the original question.
And, again, we're not talking about transient conditions. The question was about steady-state loading and unloading and it's effects on the speed of the turbine (and frequency of the alternator) when connected (synchronized) to a grid in parallel with other alternators and their prime movers.
So, from the data it seems very clear: There is no appreciable change in speed or frequency when the unit is loaded or unloaded while connected to a grid in parallel with other prime movers and alternators. Not including load throw-off or load throw-on, which is really subtracting or adding from the load on the grid, of which the alternator for which data is being gathered is only one portion.
Again, when we're talking about "loading a unit" or "unloading a unit" we're talking about using the RAISE SPD/LOAD or LOWER SPD/LOAD targets to increase or decrease the amount of fuel being admitted to the turbine, which will increase the amount of torque being applied to the alternator rotor. But, because the alternator is SYNCHRONIZED to a larger grid composed of multiple prime movers and alternators all supplying a load composed of motors and lights and computers, the increased torque can't cause the speed to increase appreciably (unless the prime mover is very large with respect to the other prime movers on the grid, or the grid is "soft") and so the increased torque results in increased amps flowing through the alternator's stator, which is referred to as "increasing the load." The MW meter of the alternator in question will increase in the positive direction, hence, the "load" increases.
In other words, in non-laboratory conditions (i.e., real world conditions), when connected to a grid in parallel (synchronized) with other alternators and their prime movers, the speed/frequency does not change when the load changes when loading and unloading the units using the governor RAISE and LOWER functions. The vector data and the "test" results prove that.
With due respect, CSA has small problem to understand the argument along this line.
Straightly speaking two generators in parallel most likely are never have the same frequency. As long as their Synchronism Torque Angle (STA) will not deviate by greater than 180 degree, theoretically their governors can keep them under synchronism.
Loss of synchronism occurs when STA is greater than 180 degree. In practice the deviation is kept well below 70 degree.
Whatever you want to call it: load, prime mover or generator. All of them are prompt to hunting.
It is true as pointed by somebody in this forum that a power system doesn't work if there is no frequency deviation. All prime movers (that includes generators) in the system do not recognize what is load. They can only recognize speed. Sound strange right? But it true. So their responses are based on frequency deviation.
FYI- In 2005 our grid system with running capacity of 15,000MW was hunting by the order of +/- 200MW for about 20 minutes. What I'm trying to say is when it comes to load swing (load hunting) system size doesn't matter. What matter is the size of transient load whether its magnitude is big enough to trigger the swing.
> With due respect, CSA has small problem to understand the argument along this line.
Okay, Namatimangan08, so exactly how much does the speed differ between synchronous generators connected in parallel to each other and supplying a common load?
Please be precise. 1 RPM; 10 RPM; a fraction of an RPM.
I will concede that there are differences in acceleration but they are transient differences.
Please enlighten me, and all of us, with your precise measurements of speed differences. I'm always willing to learn.
Way to go CSA, so nice to see you check in every now and again. I deeply miss your input, the site just ain't the same!!
Your welcome mate. We share and we learn.
Remember my "controversial" that I have made probably last year of a year before. "scientifically there no such thing of infinite grid". I also mentioned that if you don't believe with this argument you will find one major problem to explain precisely about how a power system works without violating the conservation of energy.
Infinite bus is NOT a scientific principle. On its own, it does not exist. How we can prove it?
Go to a generator. Look at system frequency. Wait it steady state operation is achieved, ie. its frequency remains constant say at 60Hz says for 5 minutes (If you can find one). Find out the total power production from all prime generators attached to the grid. Says 15,000MW.
Next by the conservation of energy, if frequency hasn't change then generating power is equal power consumed.
For every 1hour the grid supplies 15,000MWh. The demand consumes 15,000MWh to. Therefore frequency remains at 60Hz.
From there on let us raise the generator in front of us by 1MW. So the total supply has become 15,001MW. The demand will not change since that 1MW is hardly change its terminal voltage. For a specific purpose assuming the grid system has no speed droop, no AGC and no AVR. What happens to the system after 1hr, 10hrs, 100hrs, 1,000,000hrs?
You are going to from the conservation of energy that supply side will increase as time goes. The demand remains the same. If we allow time to approach infinity we create vast unbalance between both. That indicates the system cannot exist since it cannot comply with energy balance. Stable system must comply with energy balance.
I know about inertia. That is my important point. Inertia is a part of the "infinite grid" too but less understood by many. From the above example we can't construct a working model for grid if we don't add inertia to the system.
Finally, we put speed droop, AVR, operators' interventions, AGC and control to the system. We introduce the physical parameter that is called inertia. We put systematic method to control. Then only the working principle a grid system can be explained flawless.
In summary, infinite grid terminology inclusive all these elements. It is actually the destination rather than a scientific concept that many people are inclined to believe.
If you agree that transient can exist then you have to agree with permanent frequency difference. I thought I have posted my true experienced dealing with an isolated system with 4 Diesel Gen sets that almost never able to get their frequency equal longer than 5 seconds. It was quite long explanation, Unfortunately, I think it went missing or probably I didn't press submit button.
To provide direct answer to your question, I would say most medium to big grids have little problem to deal with frequency deviation between two parallel generator up to 30rpm for a 3000rpm system. Roughly about 120 RPM, Some of hydro units might be put to partial shutdown generator by protection scheme. At 240 RPM normally the generator will be removed from system whether under electrical over speed or out of step/out of phase/slip pole/loss of synchronism protection. At 300RPM mechanical over speed protection... Just to be sure in case electrical over speed fails to deliver the required task.
> To provide direct answer to your question, I would say most medium to big
> grids have little problem to deal with frequency deviation between two parallel
> generator up to 30rpm for a 3000rpm system.
How long can "...most medium to big grids..." deal with these 1% frequency deviations between two parallel generators?
I'm interested in hearing from other readers and contributors about their experiences between generators operating in synchronism with a grid and other generators when the grid frequency is normal. How much deviation from rated speed/frequency do you observe when running at steady state conditions (stable power output)?
I do not disagree that load angle/torque angle--whatever someone wants to call it--will differ between generators being operated in parallel with each other. And, I believe that when loading and unloading generators being operated in parallel with each other that the momentary (on the order of milliseconds) acceleration changes.
But, I do not believe that synchronous generators being operated in parallel with other synchronous generators can operate a differing frequencies or speeds (since the two are directly proportional). That's the whole concept of synchronism. Why else would it be necessary to synchronize an incoming generator with other generators? Why not just close the breaker if the frequency of a generator doesn't need to match the frequency of the other generators?
Why does a generator being operated in parallel with other generators go into reverse power when the torque input to the generator is reduced below the amount required to keep the generator rotor spinning at synchronous speed/frequency?
Please, Namatinamgan08, enlighten us. Provide the mathematical formulae to support your position. Answer all of the above questions with actionable data, not personal thoughts and impressions.
Where is the proof of your contention?
How long? If no out of step protection, it will take as long as it takes until it goes to over speed protections or internal damage has occurred.
The first over speed protection is the unit goes to reverse power. Why? In an attempt for the governor for that unit (Via speed droop) to ensure it will not go faster than the average frequency. The governor will try to dis-accelerate the rotor by reducing the torque. But if the unit is out of synchronism already no amount of reducing torque can bring it into synchronism again. Its shaft will continue to accelerate since there is no opposing torque from the load to slow its frequency. Finally it generator turns to reverse power.
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.
Ok. Let us understand system dynamics from Newton's laws: Swing Equations for parallel generators are as follows:
J (d2A/dt) + c(dA/dt) +kA = Tm-Te
J = Moment of inertia (Prime mover + generator + others) kgm2
c= Damping constant
k= Stiffness constant
A= rotor angle from stationary point of reference
d/dt = time derivative
Tm= output torque
Te= opposing torque.
There is such thing that is called locked into synchronism. But it meaning is not the same as many of us wanted to believe. This is similar to infinite grid concept. Let me explain further.
Steady state means Tm-Te=0. So the LHS is zero. The shaft for the prime mover will not accelerate, not going to move faster and also not going to change its displacement angle relative to rotating magnetic field.
If Tm> Te then the LHS is not zero. Energy is added to the rotating grid. This additional energy will be used up for (1) increase d2A/dt (2) increase dA/dt and (3) changing the A. Its angle may be displaced by certain radians relative to the rotating magnetic field.
The magnitude of d2A/dt is determined by the the value of J. The bigger J is the smaller its d2A/dt
The magnitude of the dA/dt is regulated by the droop via its droop set point- direct intervention of the input to prime mover. The higher its percentage set point the slower the droop to provide frequency damping. kA in controlled via manual intervention- Calibration of the unit output so that the load it dispatch is "housed" at predetermined frequency. Says 100MW at 60Hz. Note that 100MW at 60 Hz and 100MW at 59.9Hz as far as grid operation is concern is not similar. This is especially true for the units that are put under AGC -frequency control.
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.
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.
> Namatimangan08 wrote:
>> To provide direct answer to your question, I would say most medium to big
>> grids have little problem to deal with frequency deviation between two parallel
>> generator up to 30rpm for a 3000rpm system.
> How long can "...most medium to big grids..." deal with these 1% frequency
> deviations between two parallel generators?
> I'm interested in hearing from other readers and contributors about their experiences between generators operating
> in synchronism with a grid and other generators when the grid frequency is normal. How much deviation from
> rated speed/frequency do you observe when running at steady state conditions (stable power output)?
---- snip ----
There are two kinds of torques that we are talking about. One part is opposing torque that is produced by the demand. The other part is traction torque that is produced by the dynamic of prime mover and generator.
Which one you are referring too? All the while I was referring to the dynamics of prime mover and generator.
Realizing that you probably work in a certain Asian sub-continental region of the world famous for lack of frequency control and poor grid frequency regulation you may indeed see more unusual circumstances than many readers here. Actually, that might be changing as this site seems to be attracting more inquiring minds from that part of the world looking for explanations to unusual operating conditions.
I will maintain that a properly regulated--or "tuned" to use your terminology--will result in all synchronous generators operating in synchronism (in other words: at the same frequency/synchronous speed). You are now saying that a generator might be at 59.9 Hz versus another unit at 60.0 Hz (or 0.167%), when you previously said a machine could operate at 10% difference. It's very confusing.
Just a few months ago I had the opportunity to visit a grid control headquarters for a very large grid which is well-operated and famously stable, and I inquired about generators operating at different frequencies on the grid. The looks I received were wilting, meaning I wilted under the stares.
I think I'll stick with my "problematic" and simplistic understanding of the basic fundamentals of AC power systems, and leave the transient, freakish off-frequency operating characteristics for others.
Grid and Grid
Wow, i return to control.com to see a old thread popped up :) and with a raging discussion going on. back to the good old days i guess. Here is my take on the situation.
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. "
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.
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). 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.
Case 1 - Increase turbine power when connected to the grid
you go on increasing power the generator output will increase till it reaches max output. in this condition only the load angle of the generator increases not the speed. suppose that you are mad enough you have manual fuel/steam control you increase the turbine output again , the generator will load , its load angle will increase and after some time when it exceeds the max stable load angle it will go to pole slipping condition. this case is possible only in laboratory conditions. 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. Overspeed can happen because of load throw off not the other way around.
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.
"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.
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. 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.
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.
Governor mode Machine 1 Machine 2 Remarks
droop droop stable
droop load control stable
iso droop load will hunt depending on the iso setpoint and current frq iso load control Disaster :P potentially unstable behaviour
iso iso needs load sharing scheme , otherwise will lead to hunting
load control load control disaster again
Query 1 - How long can "...most medium to big grids..." deal with these 1% frequency deviations between two parallel generators?
well i take it that you mean "two areas" rather than two generators. In every grid there will be inter area oscillation. These are very low frequency load hunting due to the relative change in the speed between two areas which are synchronised and connected by tie lines. the oscillations occur due to frequency deviations of about 0.02 Hz or 0.01 hz not 0.5 hz. wide area oscillations as far as i have seen has been for about 0.2 Hz during a severe sustained fault in one area.
Statement 2 - Realizing that you probably work in a certain Asian sub-continental region of the world famous for lack of frequency control and poor grid frequency regulation you may indeed see more unusual circumstances than many readers here. Actually, that might be changing as this site seems to be attracting more inquiring minds from that part of the world looking for explanations to unusual operating conditions.
ha ha ha well, we thrive in adversity don't we ;). Next time you visit a grid control station of a ISO(independent system operator) or a Load dispatch center you can ask about interarea oscillations , it will be present in the most stable of grids too. As far as frequency regulation is considered, it will be about +- 0.2-0.4 Hz for stable grids (UK and Canada comes to mind) and +- 1.2 hz for er well power deficit ones (best example would be India, sigh)
> 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.
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 :).
> 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.
> Realizing that you probably work in a certain Asian sub-continental region of the world famous for lack of frequency
> control and poor grid frequency regulation you may indeed see more unusual circumstances than many readers
> here. Actually, that might be changing as this site seems to be attracting more inquiring minds from that part of the
> world looking for explanations to unusual operating conditions.
You are right. In our country frequency regulation is not excellently done. But that is not my point. We are talking about fundamental rather than specific method used in any country.
> I will maintain that a properly regulated--or "tuned" to use your terminology--will result in all
> synchronous generators operating in synchronism (in other words: at the same frequency/synchronous speed). You are
> now saying that a generator might be at 59.9 Hz versus another unit at 60.0 Hz (or 0.167%), when you previously said a
> machine could operate at 10% difference. It's very confusing.
My main argument is, the main operational objective is still keeping the frequencies for all parallel generators to be equal. That doens't mean it is okay to operate the generators even at 0.5RPM difference. This does not change the fact that their frequencies can deviate since the governing equation for each unit in the system is not the same.
Meanwhile the droops are tuned in such a manner that such deviation will never been allowed to go unchecked. Some of the times one or two units can go to reverse power, partial shutdown generator or even over speed protection operated. Those protections are standard protections for any any grid system in the world. That includes in your country.
> Just a few months ago I had the opportunity to visit a grid control headquarters for a very large grid which
> is well-operated and famously stable, and I inquired about generators operating at different frequencies on
> the grid. The looks I received were wilting, meaning I wilted under the stares.
You can stay in front of the grid monitoring panels for 20 years. No way you can see such deviation if don't want to see it. If you want to see it you have to install a system. We (my company) have installed one. We call the system Wide Area Monitoring System (WAMS). One of the parameters that we monitor is torque angle between inter inter connectors. Scanning time is as short as 500ms. I thought I have frequency data at one snapshot for various locations that showed they were not equal.
> I think I'll stick with my "problematic" and simplistic understanding of the basic fundamentals
> of AC power systems, and leave the transient, freakish off-frequency operating characteristics for others.
Let show us mathematically how two parallel generators can be "locked" into synchrorism the way you think that it works.
General rule that we know is something that we can put together can be teared apart. Even mechanical coupling between two generators can be cut into two pieces if enough torsion is applied. Size doesn't matter.
What is so special about the grid system under synchronism that only put together by the magnetic forces? What makes them cannot be separated at all?
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.
> 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 ----
> 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?
We have conclusively concluded that over speed came first. We could learn sequence of events up to 500ms frequency.
>Which trip first, breaker or overspeed?
When I first explained my finding to one of the plant technicians he suggested the same question. No. He was not questioning my finding. He denied it by saying that 445 RPM (it was 462 RPM actually due to zero bias error of -17RPM for the speed sensor) was obvious scenario when a t/generator trips off.
We came together to the frequency-load-time plots. The time stem can be set as small as 500ms. We moved the reference line for the plots slowly to the point just before the t/g tripped off. Here are the parameters -the fifth tripping of the day.
Load = 16 MW
RPM = 445 RPM
Trip on over speed protection.
Just after that load, voltage, current etc. became zero.
System frequency was almost flat at 50.00 Hz. Just before the tripping system frequency had increased by less than 0.1-0.2Hz.
During the fourth tripping I had already advised them to reduce the generator voltage for that unit. But nobody took it serious. I was merely a contractor to them. So nothing much I could do to make them listen to me. They repaired here and there then try to put it back on bars. The t/generator tripped off when the operator tried to raise load just after synchronization.
After the fifth tripping I told the plant staff that they had to make sure that they could put the t/generator on bars for my team even that meant they had to stay back for the next 24 hours. They had promised us to put on the t/generator for my team work. Then I told them that, the best chance for them to not to stay back that long was to reduce its terminal voltage from 11.5kV to 11.2kV. For the 6th start, we managed to keep the t/generator until our team completed our work for that day. So all of us went home earlier than 24 hours.
The t/generator tripped again for the same reason a week later.
Can you plz make your posts simple and easy so that we can understand easily. I understood that the turbine tripped on overspeed when the breaker was still closed? What is your justification in asking to reduce the terminal voltage to avoid overspeed trip.
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.
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.
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.
---- 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.
Dear Process value, we are waiting for your valuable posting Part3 (grid operation document)
(Ref;6th Jan post)
Thanks & Regards,
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.
Part - 1 : the Theory
The machine acts differently for different operating conditions. Yes i am a fan of vector diagrams and i am using them again :)
section A - Machine in parallel to the grid
I am assuming that the machine is put in droop mode of operation. in the vector diagram there are two main vectors. The vector V which is the terminal voltage while the vector E is the generated voltage in the alternator. The vector V in effect represents the grid and the vector E the machine. Both these vectors rotate ; V to the grid frequency and E to the machine frequency , and the normal convention is to that they rotate in the anticlockwise direction. when a machine is synchronised to the grid both the vectors E and V rotate in the same frequency , thus the relative speed between the two is zero. This is reason why we can draw a stable vector diagram. The angle between the two vectors , the load angle determines the power output of the machine. when connected to the grid the machine and the grid frequency will remain the same under steady state condition. Thus the hallmark of a grid under steady state condition in stable frequency.
Now two separate conditions can happen to the machine connected to the grid.
A.1 change in the grid frequency - when the grid frequency changes , the vector V accelerates twords the vector E and then finds a steady state position. Thus this causes a reduction in the load angle and thus the power supplied by the machine to the grid reduced. the reverse happens for a reduction in the grid frequency. Here the change in power output with the change in frequency follows the droop reference of the machine.
A.2 Change input to the machine - when fuel/steam input to the machine is increased the machine accelerates ie in the vector diagram the vector V remains the same but the vector E accelerates away from the vector V. thus the load angle in the machine increases and thus the power delivered to the grid increases. the reverse happens in case of a fuel/steam reduction to the turbine/gen set.
I am uploading a diagram here which explains the above scenarios with VECTOR diagrams. I have also induced the corresponding droop Chara diagram also.
Section B - Machine independent , and supplying to a section load
The explanation of a independent machine is a little difficult as there is no fixed reference point of observation. Machine and bus load angles are always expressed from a reference bus. i am taking a intermediate generation bus as my reference. The machine is put in droop mode of operation. The vector V represents the section load terminal voltage , while the vector E the generation voltage. The vector V is controlled by the load while the vector E is controlled by the generator. both vectors are moving in the anticlockwise direction with the the speed equal to the speed of the generator. The relative difference between the speeds is zero for a steady state condition. The angle between them , the load angle determines the power transfer.
Now two separate conditions can happen to the machine when it is independent
B.1 - Change in the section load - when there is increase in the section load the vector V decelerates and reaches a new steady state position. this deceleration will cause the increase in the load angle which will cause the increased power transfer. the machine speed also drops in accordance with the droop chara/ref. the reverse happens for a decrease in the section load.
B.2 - Change in the input to the turbine - when fuel/steam to the machine is increases when it is operating independently with a constant section load ( in real life cases this is not the same as most of the loads in a system are motors and an increase in the frequency will increase the power output from the motors) both the vectors E and V accelerate together so as to keep the load angle a constant. This increase in speed is due to the shift in the droop ref chara. the reverse happens for a reduction in the fuel/steam input. However the increase in the fuel is minimal as assuming a constant section load the increase in fuel is just to compensate the rotational losses for a higher speed.
I am uploading a diagram here which explains the above scenarios with VECTOR diagrams. I have also included the corresponding droop chara diagram also.
>Part - 1 : the Theory
Vector diagrams are welcome.
The question remains: How much does the speed of the turbines at your site change when they are loaded while connected in parallel with a other machines on a grid of relatively stable frequency? Even if the frequency isn't 50.0 Hz, how much does it change when you increase the fuel to one of the turbines causing it to accept more of the load on the grid? And for how long does the speed change?
> pick-ups of the Mark II and Mark V units from your site to see if the two units are running at different speeds while connected to the same grid. And for the Mechanical Dept. to provide the nameplate data from the load gear box nameplates. <
> As ProcessValue has pointed out, no place in the world has a perfect grid frequency, but as long as the frequency isn't changing by more than +/- 0.25 Hz in a very short period (seconds or less) we could review the results. <
> The point is that units are not normally loaded or unloaded, except possibly at ProcessValue's site, by "throwing on" or "throwing off" blocks of electrical load as he wants to do with his test. They are normally loaded and unloaded using the RAISE SPD/LOAD and LOWER SPD/LOAD buttons/switches/targets (or the Preselect Load Control enable functions, which essentially drives the turbine speed reference up and down just like the RAISE and LOWER functions). <
> What we want to know is how much the actual running speed of the turbines at ProcessValue's site change by and for how long when they are loaded and unloaded using the RAISE- and LOWER SPD/LOAD functions, which is how units are normally loaded and unloaded around the world. Not by throwing on or throwing off blocks of load, which is not a typical loading or unloading method. <
Part - 2 : The experiment
what i have said above is theory , which to the best of my knowledge is true. It is very hard to get experimental data on load angle calculations , ( there
is a load angle calcualtor of the generator on the AVR but i do not know how to get the real time data from the avr , when i asked the vendors they said such provisions is only at their test site and it is not possible on the given system :( . ) but with certain operational constraints i have done the following
experiments over a period of two days.
1. Auto loading ; machine parallel to the grid with preselect control
2. Auto Unloading ; machine parallel to the grid with preselect control
3. Manual Loading ; machine parallel to the grid with droop mode
4. Manual Unloading ;machine parallel to the grid with droop mode
5. Opening of the grid breaker under export condition
6. Opening of the grid breaker under import condition
7. Synchronizing with the grid
8. Heavy motor starting in section
I let the trend recorder run for one whole day and i got some interesting trends on how the machine behaves to grid frequency occilations and sudden and rapid frequency change in the grid. The machine was kept in preselect condition during the test. The archive file below give the trend snapshots and the trend data in csv.
I trended the following signals
1. DWATT - machine MW output
2. DF - Machine frequency calcualted from the machine speed sensor TNH
3. TNH - Machine speed
4. TNR - droop reference
5. L70L and L70R - the machine speed raise / lower command which is responsible for increasing or decreasing the TNR
6. FSR - the fuel stroke rate in percentage
7. FQLM - the fuel flow in kg/s
8. SFL1 - the bus frequency , this is calculated by mark vi VTUR board from the Bus PT connection. BUS PT is in the CPP sec C bus
9. sdiff2 - the difference in the frequency between the machine and the bus. it is the value of ( df_vtur - sfl1)
The experiment setup - The present site i am on has the following configuration. The test was done on GT-3 as present in the drawing. The Gt is a frame 5
machine with 22 MW capacity at site condition. The machine is a dual fuel capability machine now running in naptha.
Pic of the test setup - http://www.2shared.com/document/YLmm69rE/test_setup.html
The complete trend snapshot and trend data in csv format is uploaded here in the archive file GT_test.rar
Limitations of the test setup - The major limitation of the test setup is the lack of a frequency source which is in the grid. I had to take the bus frequency which is similar to the grid frequency under parallel condition. This is what is used for the auto sync.
1. Auto loading of the machine - The machine was in preselect mode at 14 MW and the setpoint was raised to 18. it is seen that during parallel operation to the grid the MW is hunting by 0.2-0.3 MW continuously. it is also seen that the machine frequency is hunting with the bus frequency during the whole operation. ie the machine was constantly accelerating and de accelerating over the setpoint , not by much but by but by a maximum of 0.0015 to negative of 0.002 , it also oscillates the whole way during the ramp up to the 18 MW. This is similar to the condition in "section A " of the explation . Machine parallel to the grid with increase in the fuel/steam input to the machine. here what we do is increase the fuel to the machine.
2. Auto Unloading of the machine - Here the machine in preselect mode , from 18 MW the set point was given as 14. similar to the auto-unloading of the machine but the occilations seem to be on the higher side here , the hunting was from a maximum of 0.002 to a negative of 0.0025. MW was around 0.3-0.4 MW all during the ramp down period. This is similar to the condition in "section A" of the explanation . Machine parallel to the grid with increase in the fuel/steam input to the machine. here what we do is decrease fuel to the machine.
3. Manual Loading of the machine - similar to the auto loading , except that a manual raise command was given three times. check out the results in the folder.
4. Manual unloading of the machine - similar to the auto unloading , except that a manual lower command was given , check out the results and graphs in the folder.
5. Opening of the grid breaker with export - This is very similar to a load throw off in a independent machine. an export was 2.5 MW was maintained when the grid transformer breaker was opened. this led to the sudden load throw off , sudden increase in the speed. This is similar to the "section B , B1" of the explanation. here there is a sudden reduction in the load. this is where you can really see the machine hunting. the speed during the initial throw off jumped by around 0.01 Hz . the machine frequency which was around 49.65 raised to 49.95 a increase of 0.3Hz for a load throw off of 2.5 MW , indicating a droop of around 3.34 %. This speed hunting is mainly because the machine cannot match the speed in which the load was thrown off. it can be clearly seen in the graph that even though the reduction in load is near instantaneous the fsr and thus the fuel reduction takes some time more , this is the reason for the speed spike and the subsequent speed hunting.
6. Opening of the grid breaker with import - This is very similar to the sudden loading of the independent machine. An import of 2.5 MW was maintained when the grid transformer breaker was opened. This led to the sudden loading of the machine and thus a sudden reduction in the speed. A very similar result to the above just that the speed reduction took place in accordance with the droop. one interesting aspect is that the hunting died off quite quickly in this case.
7. Synchronizing with the grid - This is where the actual Load and speed hunting in the machine can be seen clearly. This is a transient chara of the machine .
8. Sudden frequency increase in the grid - This is similar to the "section A ; A1" explanation. This trend is available in the grir_frq_change.rar archive. here you can see that the grid frequency raised from 50.1 to 50.22 suddenly , now the machine power came down from 19.5 to 18.6 before recovering as the machine was in preselect.
so that is all from the experiment side , i forgot to do manual raise lower and raise in the independent mode of operation . i will upload the data as soon as i do it. besides this all the cases in the theory Section A A1;A2 and Section B B1 is covered and it can be seen that the theory matched the results.
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.
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 exactly 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.
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 ----
> 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)
"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.
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.
First of all, there is no issue to debate regarding the frequencies of prime movers and resistive loads. At least I'm not the one to debate about it. The issue I was trying to explain is the mechanics between parallel generators. Not generators vs resistive loads.
The physic of t/generators in parallel works as the following. As on of the t/generator tries to move faster it has to drag the rest of system loads to accelerate together due to opposing torque the loads put on the accelerated t/generator. Therefore, the further away it tries to move, the slower its acceleration becomes. So its shaft undergoes retardation. Meanwhile, the frequency for the remaining system will accelerate due to additional opposing torque they put on the t/generator. Naturally, both of them will come into synchronism again if its torque angle does not deviate up to out of step protection activated.
The mechanic to keep the synchronism healthy is not limited by the explanation given by the preceding paragraph. There is another mechanic at work namely the speed droops. Let us take your example to illustrate how this mechanic at work.
Assuming we start from the system under perfect syncronism. All of sudden one t/generator tries to accelerate by 0.1Hz/s (36 deg/s). Assuming the system uses 5% droop set point. Then as the shaft for accelerated t/generated is displaced by 36 deg/s or + 0.1 Hz relative to the remaining grid, its speed droop will reduce the t/generator output by 2%. This provides additional "opposing torque" to reduce its acceleration. By the same time the frequency for the rest of the system has experienced slight acceleration. As a result its shaft cannot move freely to 72 deg as given in your stated example. For the next one second its displacement could be 0.75 times (27 deg)of the first second. By the same time the remaining grid frequency probably has increased by says 10 deg relative to the previous frequency. As a result you can see the total deviation for the next one second is smaller than the first second. For the 3rd one second the droop will keep on reducing the load by says 1.75% more. So the rate of frequency deviation will become even smaller, while the remaining grid frequency is catching up. They will definitely settle down at the same frequency again.
For a stable grid you take for granted relative angle between both of them stays less than 80 deg during steady state load change and during the calculated transient disturbances.
These are the mechanics at work that systematically ensure all the rotating generators cannot go higher than 80 deg faster or slower relative to average system frequency (frequency of the network) assuming the grid is under the normal operating condition.
But then how a turbine/generator or a group of turbine generators can loss its synchronism? Assuming major disturbance that causes one of the turbine generators to undergo acceleration at the rate of 360 deg/s. In this case you can see that natural mechanic cannot stop the deviation to be less than 180 deg since it is completely out of phase already. Even the droop can't help either since its ramp rate is not not infinitely fast. The fastest ramp rate that I know is 15% per second.
Between 90-180 deg it is called transient instability region (Process Value's statement). In this region, system frequency regulation and control may or may not able to pull the frequency back to syncronism again. It depends on whether the shaft displacement has tendency to go above 180 deg or to go below 90 deg region.
Luckily there are many layers protection before it can reach the runaway speed. I will name all that I know. (1) The speed droop (2) Partial shut down generator -hydro (3) Out of step stage 1, 2... (4) Over speed protection Stage 1 (electrical) (5) Over speed protection Stage 2 (mechanical) (6) Breaker failure protection.
A more common scenario is that the incoming generator is rotating slightly faster than the grid - so the synchroscope pointer is rotating clockwise. If it's rotating at 1 rev in 10 seconds, it is doing 0.1 rps faster than the grid - for 60 Hz, the machine speed will be 60.1 Hz.
Also assume that the breaker is closed at 11 oclock - the machine rotor field will be 30 degrees ahead of the field set up by the external voltage.
When the breaker is closed, the rotor position will not change instantaneously because of its inertia. Since the power fed to the transmission line depends on the phase angle (see my other post) there will be a small amount of power fed from the generator - this will acts as a brake on the rotor and pull it into step.
If this was not the case, and the rotor could increase its angle without limit, then at 0.1 Hz relative slip speed the generator angle would increase by 36 degrees in 1 second, 72 in 2 seconds ... But because of the relationship between power and relative angle, the electrical power out of the machine increases and the system reaches equilibrium with the rotor angle stable when electrical and mechanical power are matched.
> A more common scenario is that the incoming generator is rotating slightly
> faster than the grid - so the synchroscope pointer is rotating
> clockwise. If it's rotating at 1 rev in 10 seconds, it is doing 0.1 rps faster
> than the grid - for 60 Hz, the machine speed will be 60.1 Hz.
You are right but the main reason to keep the speed of the incoming generator to be higher than the grid is to share some load from the grid.
As soon the generator takes the load from the grid the speed will come down according to speed droop setting and it will continue to take the load until it equalise the speed of the grid.
I also agree that the generator frequency may not be exactly equal to the grid frequency, they may be slight changes,but it will be in both side (+or -).
It cannot stay in one way like lagging or leading for long time.
If the generator speed lags behind grid frequency than the generator will give up its small load to adjust to the grid frequency. When its leading it will take some load from the grid to match with grid.
Variations may not be experienced Physically also but always there will be an attempt to match the frequency with the grid. But again it depends on the governor performance too.
This is just my thought.
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.
There might be angular differences between machines, but significant frequency differences? No. Not even 0.1 Hz for any appreciable period of time (more than milliseconds).
As suggested by others, acceleration differences will result in momentary (millisecond) frequency differences, but the poles of the generator rotor will not run at any other speed than the above formula will allow relative to frequency for even 1 second. That would mean that the poles have slipped and that would mean catastrophic damage has occurred.
I have been doing some World Wide Web research on out-of-step relays and their application, and while there can be losses of synchronism between generation areas in a power system or between interconnected systems when detected these events should very quickly result in separation of the affected areas to prevent widespread outages and even damage. In no paper I have read does it ever talk about individual generators being out of synchronism with each other. And even areas of generation which are detected to be out of synch (which is usually much before actual "slipping" of poles occurs) the protection is supposed to operate to isolate the affected areas to protect them against damage.
Many of the manufacturers of out-of-step protective relays have extensive papers on their application and operation.
> I have been doing some World Wide Web research on out-of-step relays and their application,
The paper that I quoted before talks about a generator or a group of generators can go out of sychronism. If you think the paper was written by an academician who has lost touch with reality in his writing, then think about my experienced with a 28MW Pelton turbine generator.
The physical law you require is the power transfer over an inductive transmission line. This is given by
(V1 x V2) x sin(a1-a2)/X,
where V1<a1 is the voltage and phase angle at the generator, and V2<a2 is the same at the other end of the line.
So if we use phase angle a2 of V2 as reference, and if V1 is leading V2 by a1, there is a power flow from 1 to 2. If 1 is a generator, this power flow is an output from the system and must be balanced by the mechanical power to the generator:
Mechanical power in = electrical power out + losses + rate of change of shaft kinetic energy.
This balance can be turned into a second-order differential equation relating the rate of change of (rate of change) of angle a1 to the losses (proportional to the rate of change of angle as the relative speed of damping windings) and the power flow down the line.
If mechanical power in increases, the shaft KE increases and there is a very small increase in instantaneous speed of the generator rotor.
This increases the angle of 1 relative to 2 and the electrical power in the transmission line increases to match - the acceleration power falls to zero and the two systems return to synchronism.
If you want more detail, I can send you some references to texts containing the necessary differential and other equations.
So, Bruce Durdle, are you saying that during loading of a machine that it's frequency will increase (say to 50.5 Hz) for a brief period of time (how long, please--just an estimation is all that's required) and that the generator being loaded is actually out of sync with the other generators with which it is being operated in parallel with? And then after some time when the kinetic energy balances out the rotor will return to the same frequency as the other machines?
Do the poles of the generator rotor actually speed up and "jump" ahead? Wouldn't this be slipping a pole by increasing torque and wouldn't it have physical consequences on the coupling and rotors of the generator and/or the prime mover?
I completely understand that there are angular differences under steady-state operation that are a function of load ("torque angle", "load angle", whatever someone wants to call it). And it's also clear that when torque input from the prime mover increases or decreases during normal loading and unloading that there is also an angular change because of acceleration. But that is brief (on the order of milliseconds) and in my experience the poles of the generator rotor stay in synchronism with frequency of the generator stator (the grid frequency).
If the rotor actually sped up or slowed down then currents would be induced on the rotor in addition to the slipping of poles that would be occurring.
I'm sorry to be so dense; I've actually asked this of you in a previous post. I would like to be very clear about this for others reading this post, because my experience just doesn't match with this operating out of synchronism, even for 1 second, or 0.5 seconds.
Again, out-of-step relays are supposed to sense slipping of poles before it occurs to prevent mechanical damage and outages. Some monitor load angles and from what I've been reading they attempt to anticipate an out of synch condition (which would result in slipping of poles) and operate to prevent such an occurrence.
If I'm wrong, then I'm wrong. I have no problem with that. I've been wrong before, and I'll be wrong in the future. Maybe it's just the equipment I work with that doesn't allow me to see these speed differences. But, from everything I was taught and understand an out of synch condition on a generator is catastrophic--in many ways. Loss of excitation relays and out-of-step relays are used to try to prevent this by anticipating such a condition and operating before it occurs.
I've worked on some pretty big machines and they can actually have an effect on grid frequency they are so "stiff" (I think that was the term that was used) and unless some other machine's load is reduced as these big machine's loads are increased the grid frequency will increase (presuming the grid load is stable at the time). And, every generator's frequency (and speed) increases until the machines operating at part load have their droop governors kick in, or an ISO operator reduces load on one or more other generators to bring the frequency back to nominal. But, we're talking about hundredths of a hertz, but not more than a tenth of a hertz. And, it's the whole grid not just one machine.
I am saying that, if the mechanical power into a rotor is increased so that there is a surplus of energy in, the result is an instantaneous acceleration of the rotor. This is extremely small and results in a small increase in speed which in turn increases the rotor angle of the generator. This increase in the rotor angle will then act to increase the electrical output of the generator - restoring the original power balance, and reducing the acceleration to zero.
The effect is very short-lived, with the time before equilibrium is restored being dependent on the moment of inertia of the shaft (typically of the order of 1 second). The total change in angle for say a 10 % change in power is about 8 degrees, and if the machine has an inertia constant of 5 seconds (typical for a large hydro or small thermal set), the total KE is 5 x the VA rating. The actual increase in speed as a % of nominal is about 1 %, and I doubt if it could be detected on most machine tachogenerators. We are talking very short-lived infinitesimal effects here.
If you can stand it (bearing in mind earlier comments about differential equations) I can dredge up some hard data from my records and set up a dynamic model for you - but it would be in something like Excel so I'd need an address to send it to.
My comment on synchronising was based on my observations of what works - if the synchroscope is going at about 1 rev in 10 sec clockwise, and you close the breaker at about 11 o'clock, the immediately pick up about 10-20 % forward power with minimum rotor disturbance. I have also seen situations where synchronising was very difficult because the external grid was not strong enough to develop the synchronising torque needed to pull the rotor into lock unless the breaker was closed at top dead center with little or no speed differential - this on plants with a large local load where the incoming link was designed for a small residual power flow.
I far as I know, out of step relay doesn't do anything rather than alarms plant operators or removes the plant out of the system.
I think you can rely on the droops to keep the synchronism healthy and inertia energy constant to absorb and provide energy momentarily. The amount of inertial energy of a t/generator is one of the parameters that will be clear specified when we wish to purchase a turbine generator.
It is important to ensure the sum of the total inertial energy of rotating mass of the grid supports the stable ramp rate of turbine generators to have a stable system. This is one the reasons why some parts of the world, as you say, constant frequency operation is merely a dream. My country is not spared.
Why is that so? Slowly fundamental for stable grid operations is compromised for lower operating cost. We can view it by looking at the ratio between the biggest per unit capacity of a prime mover and maximum grid (or area) peak demand capacity. As the ratio becomes bigger, the system becomes less infinite. Otherwise, it becomes more infinite. This is one of the indicators to measure how "infinite" is the system that we have.
So if in your country you have this ratio smaller than 2%, I think you can't see most of the issues that I put forward. Ours the ratio is 5%. That ratio is still okay to get a stable grid. But as I told you slowly but surely lower operating cost will dictate the way that our grid is operated.
Too bad, but we have to bear with it.
Managed to troll through my archives and found a reference giving some typical swing curve calculations ("Power System Stability: Synchronous Machines" by E W Kimbark).
As an illustration of the numbers involved, one of his worked examples (related to a fault condition rather than a change in loading) gives a change in power angle from 46.5 to 88.3 deg after 0.35 sec, then reducing to 52.5 deg after 0.65 sec. The rate of change of angle was 0 initially to + 9.6 deg/s after 0.2 sec, (slip speed 0.026 Hz or 0.043 % at 60 Hz). Maximum acceleration in deg/s was 3.5 at 0.05 s.
Not the sort of effect you'd expect to see on a meter!
> The physical law you require is the power transfer over an inductive
> transmission line. This is given by
> (V1 x V2) x sin(a1-a2)/X,
> where V1<a1 is the voltage and phase angle at the generator, and V2<a2 is the
> same at the other end of the line.
---- snip ----
Thank you mate. The physic law that I asked specifically was, using your equation (it is a matter of fact I am one of the strong believers in that equation too).
Mechanical power = rate of increase in kinetic of rotating mass + power consumed + losses + power required to change the shaft angular position.
Re written your equation in the form of swing equation for each generator, using torque rather than power, the DE looks like this
Jd^2A/dt + cdA/dt + kA = Induced torque
J= second moment of inertia (kgm2)
A= Angular displacement (rad)
c= Damping constant
k= Stiffness constant
The solutions are of the type of second order DE. Well understood....
There are four possible scenarios about the solutions we may have at the end of our Laplace transform analysis for the second order DE depends upon mainly J and c above. They could end up one of the followings
1. Undamped oscillation
2. Underdamped oscillation
3. Overdamped oscillation
4. Critically damped
The questions are:
a) What law of physics that ensure all parallel generators will end up either 1,2,3, and 4 above without exception? Why we can't have a group of t/generators that falls under 2 and the remaining falls under 1, for instance?
b) Assuming there is a specific law of physics that can explain all of them shall end up according to 3 only (as many people believe), then what law of physics that explains they all shall have oscillation with equal amplitude, equal phase and equal time? Remember the swing equations for all turbine generators have little thing to do with electrical network. The parameters used by swing equation as you have agreed all come from t/generator alone.
I have been following this post since it started now almost 2 years ago from a simple question, "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?
At the time this seemed like a simple question, which can get very complex by introducing vector angles, apparent and real power, line impedance etc, etc, etc. But I really appreciate the fact that most people who post here attempt to keep their answers on the simple side if possible.
In my small 10 years of the industry I have not seen even a small amount of what is out there, but I thought and still mostly think I understand the simple idea of how a power system operates. There have been several ways that people who post here have tried to simply explain the idea of how a generator converts mechanical energy to electrical energy, and how these generators work together to provide a stable and consistent flow of power. I still tend to think it is a difficult concept to understand sometimes, and even more difficult to explain, especially for people like me who dislike complex and theoretical math.
But my belief still tends to fall with CSA and Bruce Durdle that once a generator is synchronized to the grid, that its frequency will be the same as any other generator in the system no matter how close or far away. My understanding is that all these generators are rigidly coupled together by the magnetic forces that exist between the stator and rotor of each machine, making multiple generators act like on large single machine. I do understand that a machine might be slightly out of angular phase with the grid at times, when it is being synchronized to the grid, or if an event occurs where a large load is introduced or taken away from an area near a machine. But due to the magnetic coupling inside the generator it is not possible for that machine to operate at a different frequency or speed than the grid it is attached to, unless it losses synchronization by loss of or too little field excitation.
I am really confused by your first post on this thread.
"Straightly speaking two generators in parallel most likely are never have the same frequency. As long as their Synchronism Torque Angle (STA) will not deviate by greater than 180 degree, theoretically their governors can keep them under synchronism."
Can you please explain to me in simple terms what you mean by this statement? I can understand that a generator may have a VERY slight difference in phase angle at times, not normally though and a slight deviation in phase angle is not a difference in frequency. The rotor is still rotating at the same frequency or speed of the grid.
Further you say, "Whatever you want to call it: load, prime mover or generator. All of them are prompt to hunting." I really don't understand this statement either. If a generator governor is operating properly then a generator should not "hunt".
Lastly you state the following, "It is true as pointed by somebody in this forum that a power system doesn't work if there is no frequency deviation. All prime movers (that includes generators) in the system do not recognize what is load. They can only recognize speed. Sound strange right? But it true. So their responses are based on frequency deviation."
FYI- In 2005 our grid system with running capacity of 15,000MW was hunting by the order of +/- 200MW for about 20 minutes. What I'm trying to say is when it comes to load swing (load hunting) system size doesn't matter."
This seems really scary and foreign to me. I can't find anywhere that someone says that a power system doesn't work if there is no frequency deviation. Can you please explain this reasoning to me so I can understand it?
I don't mean to pick on your posts but they just don't seem to make sense to how I was taught in school and how I see my plant operate.
First of all magnetic coupling between generators and load you can assume they are rigid. It can be treated as rigid coupling for almost all practical purposes. But it was not only me in this thread that proposed two areas might have temporary frequency swing which is called inter areas oscillation. I have seen this swing myself. So I cannot be intimidated by complex vector diagrams that I don't understand if they suggest the other way around. That oscillation can be very damaging but to me it not about load. It is more about generators in parallel.
If the truth about rigidity of that magnetic coupling that troubled you and you want to know the truth, I have posted key words for Google search that enables you to access many articles to support my position regarding this matter. At least one of the articles clear stated it is not rigid at all. It is "elastic". Just go there and read. You don't have to take my words.
> "Straightly speaking two generators in parallel most likely are never have
> the same frequency. As long as their Synchronism Torque Angle (STA) will not
>deviate by greater than 180 degree, theoretically their governors can keep
> them under synchronism."
You run a unit at 3000RPM. Close it breaker to supply load to electrical appliances. A moment later you close another breaker (not synchronization) for a t/generator that is operating 3010RPM. What will happen? Do you think the breaker refused to close just because incoming and outgoing RPM are not equal? No. The breaker will close. If there is no protection against out of phase, the two t/generators will operate at their respective frequencies at least until severe damaged occurred.
If you can measure the sine waves using two oscilloscopes that you specifically filter them out to see 3000RPM and 3010RPM you will see these two sine waves coexist together. If you believe the idea of one frequency then which generator follows which? Why then?
We don't close breakers for parallel generators. We synchronized them. Things get a lot better then. But the fundamental hasn't changed. The fundamental is that two diff frequencies can exist in one transmission line if the sources induce two diff frequencies.
You have given us a lot of pause and have made many of reflect on our understandings and experiences.
You are welcome to your understanding and interpretation and you are even free to speak what you believe to be true (freedom of speech is an awesome thing!). Others are also just as free to ask for clarification and/or to challenge what is being said or proposed.
I happened to come upon this thread on a once-per-month visit back to control.com and just wanted to clarify what you were saying. I was not offended by your statement about my misunderstanding; my only interest was to have you clarify your statement. You have done so. I have attempted to add the benefit of my experience and understanding. Others have added their voice to this thread.
As I've said many times before on control.com: I have been wrong before, and I'll be wrong in the future. I try to learn from my wrongs and grow my knowledge in the process. However, this time, I don't think I'm in error.
My hope for forums like this has always been to foster sharing amongst many people, because my personal experience is only one fraction of the experience that's available in the world. I had always hoped that others would begin to post more often and add their experiences. I wanted to just correct "tribal knowledge" myths (completely unrelated to this thread!) and errors, and to challenge people to explain their positions on some issues so as to help them, and others, to be able to reason through issues or principles and arrive at a more thorough and possibly correct understanding.
One of the reasons I have chosen not to post as often to control.com is that I seem to have monopolized most of the Speedtronic-related threads here. Since reducing the number of posts I make some "new" people have come forward with their experience and knowledge (not all of it correct, but none of it false) and that was both encouraging to me, as well as discouraging. It just points to the monopolization I was sensing and reinforces my decision to significantly reduce the number of posts I make to this forum.
However, when I visit the site and see a fairly inaccurate statement about basic principles I feel it necessary to speak up. While my understanding--and explanation--may not be 100% accurate (again, I don't have the knowledge of power system stability theory and practice and experience with transient studies and events) I believe my basic understanding of the operation of AC electrical power systems and synchronous generators is sound. It's disconcerting that I can't seem to find the words to explain it more clearly.
I don't wish to belabour this topic on this thread, or any other thread, any further. We are all free to disagree, and I choose to disagree with your explanation. Others may choose to agree, that's the beauty of freedom.
Best regards, Namatimangan08. Thanks for making us all stop and reflect on our understanding and experience. It's very helpful, humbling and enlightening to do so from time to time.
Back to my once-per-month check-ins now. Keep up the good work, everyone, and don't ever be afraid to post here or to ask for clarification.
> I have been following this post since it started now almost 2 years ago from a
> simple question, "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?
---- snip ----
> Can you please explain to me in simple terms what you mean by this statement?
> I can understand that a generator may have a VERY slight difference in phase
> angle at times, not normally though and a slight deviation in phase angle is not
> a difference in frequency. The rotor is still rotating at the same frequency or
> speed of the grid.
This is my note for this matter. If you want to figure it out how a grid works yourself just don't make simplification until you can be cheated by you own simplification. Put the fact that there are hundreds of t/generators in parallel. Just figure it out how they can maintain their synchronism. At the end of the day you will find it is not as simple as you want to believe.
The age age swing equations that I have shown you is more than 250 hundred years by now, I supposed. Yes. It is a bit difficult to most of us here even to me. Therefore many people wish to take short cut by creating the what so called "rigidly locked into synchronism" to explain how grid work. As I told you, such concept does not exist. Try to goggle it yourself if you can find any scientific evident to prove its existence.
What you can find, i can assure you this, is elastically locked into synchromism. Elastic means they can slip. This is what is termed as generator slip poles. Just goggle it. You don't have to take my words.
The reasons for elastic bonding between generators and loads can occur is due to time taken between torque induced by prime movers and developed torques to match is not infinitely small. It takes sometimes before they match. During this period one tries to move away from the other. But this is not the main issue I like to talk about.
The important point I wish I can share is, if the loads and the generators are not rigidly locked into synchronism then why should we believe all the turbine generators can be rigidly locked into synchronism between them?
Point to ponder.
I have read your replies and will agree and disagree with you on certain points.
I agree that magnetic coupling and rigid coupling are two different things. But my opinion is that ANY coupling can be elastic, it depends on the forces being exerted on it and its relative strength. But again when talking of parallel units they are coupled to the grid they are part of. They can operate at slightly different phase angles but not at different frequencies.
You talk about having a unit operating at 3000 rpm, I assume we are talking about a machine designed for a 50hz system, so I'd rather say you have a machine operating at its designed 50hz frequency. Now you close in another unit operating over frequency, approximately 50.16HZ. So you close the breaker. But assuming the unit has less inertia and power than the grid it is joining, that unit will be pulled or pushed into sychronization with the grid it has just become part of, assuming the unit breaker closes with the phase angles nearly in sync. If the breaker is closed out of sync then large scale damage can occur.
In your other response you talk about generators slipping poles, and you seem to suggest this is normal, which I don't tend to agree with. My understanding was that generators don't generally slip poles. I thought that controls and limits were in place to block this type of event because of the damage it can cause?
I agree that it is interesting to ponder this subject. But to paraphrase the simple question that started this thread was:
1) why does speed of a generator slow down when system electrical load is increased.
2) why does speed of a generator increase when system electrical load is decreased.
It seems like the thread has moved very far away from this topic.
I just give direct answers. If they help.
> 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.
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.
> one might have higher ramp rate than the other
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.
>> one might have higher ramp rate than the other
> 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.
my doubt is, when the load is removed from the alternator will there be an increase or decrease in current, if so what is that phenomenon called?
When there is no load on an alternator there will be no current. For example, prior to synchronizing the alternator to another alternator or to a grid with other alternators the alternator is running at or near rated frequency and voltage but no current is flowing in the alternator stator because the alternator is not connected to a load.
However, when the alternator generator breaker closes and the alternator is connected to the grid current will flow in the alternator stator windings--and the amount of current flowing in the alternator stator windings is directly proportional to the amount of load. Increase the load, the amperes flowing in the stator winding will increase; decrease the load, the amperes flowing in the stator winding will decrease.
The basic formula for electric power is:
P = V * I
where P = Watts,
V = Voltage (alternator terminal voltage)
I = Current (alternator stator current)
For all intents and purposes the alternator terminal voltage is relatively constant at most loads, or even when there is no load. Most alternators have a rating of only +/- 5% of nameplate rated voltage; for a machine rated at 11,000 volts that's only 550 V (above or below rated).
So, to change power one has to change the current.
A generator is a device for converting torque into amperes (an alternator is an AC generator which should be running at a constant speed/frequency). A motor is a device for converting amperes into torque. (No one ever seems to have a problem with how a motor works, and everyone agrees motors are driven by generators (alternators), but many people are quite confused about how generators convert torque into amperes.
In reality, the prime mover (a steam turbine, or a combustion turbine, or a reciprocating engine, for examples) driving the generator is really doing the work of all of the motors and other loads connected to the generator. The amperes are the way it's doing that work--electric power transmission and distribution systems are just transmitting torque from a few locations to many locations, by means of wires which carry amperes.
So, load is proportional to amperes. Take away the load, and the amperes go to zero. Make the amperes go to zero, and the load goes to zero.
Hope this helps!
As for what the phenomenon is called? Electricity, maybe?
That explanation was quite helpful.
but i have one question .
as you said that "The total amount of electrical generation must exactly match the amount of electrical load in order for the grid frequency to remain at rated. If the total generation exceeds the load then the frequency (and the speed) of all the generators will increase above the desired grid frequency. If the total generation is less than the load then the frequency (and the speed) of all the generators will decrease below the desired grid frequency."
my question is how do we keep the total load to such an exact value as the load is the sum of all the appliances like lights, motors, computers, traction loads, how is this load matching done as there are peak periods?
so what type of system is used for load control so as to keep the system frequency constant?
It depends on how precisely you want to control frequency. If the grid loads (and the turbines driving the generators) can tolerate frequency wandering between, say, +/-0.5 Hz of nominal (50 or 60 Hz) then a central dispatcher can manually dispatch generation up/down to keep frequency within tolerable limits.
Much more commonly, though, the utility has a scada system which feeds MW and frequency data to an Automatic Generation Control application (AGC). AGC runs typically every 2, 4 or maybe 6 seconds and sends generator MW controls out to raise/lower generation at selected units to return frequency to nominal if it wanders too far away.
If the utility is connected to neighboring utilities via AC transmission lines, the areas meter the power exchanged between them and compare that with the amount they actually want to exchange. That difference is added to the frequency error and, again, AGC sends controls to restore the so-called Area Control Error (ACE) to some small value.
"Small value" is a matter of perspective: a utility serving 10000 MW of load might control its ACE to within +/- 20 or +/- 60 MW of zero. It depends on the nature of the load they serve, where they are electrically in the grid, etc.
Note the amount of frequency deviation that AGC responds to can be very small, easily on the order of 0.002 Hz. There is a relationship between generation-load balance and frequency: a 100000 MW system suddenly deprived of 1500 MW of generation might see its frequency drop by 0.1 Hz (it would go further if the governors didn't respond to the frequency decline.) So 0.002 Hz on such a system translates to a generation change of 30 MW - the size of many of the turbines I read about in this forum. (this is why wind generation is one of the worst things to ever happen to the power industry - and the rates you eventually pay: the intermittent and undependable nature of the generation drags frequency around, which increases regulating demands on the controllable units. It also requires much more regulation capacity to handle the enormously increased range required by the amount of variability. So utilities must build more generation, not all of which is supplying load.)
You coincidentally used terminology that is quite common in the utility industry - load control. Another term for AGC is Load-Frequency Control, or LFC. In some places, it's just "Load Control".
> 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.
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
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.
> " The total amount of electrical generation must exactly match the amount of electrical load in
> order for the grid frequency to remain at rated. If the total generation exceeds the load then the frequency (and
> the speed) of all the generators will increase above the desired grid frequency."
does this mean the the whole power system must not generate more power than how much the load is needed? so if I'm doing a simulation, power generated from the system must match the load?
There is a fundamental principal in physics which is essential to grasp in control systems analysis and modelling - the idea of energy balance. The "normal" version of this is that energy in must equal energy out - for control work, this needs to be modified to "Energy in must equal energy out plus change in stored energy".
So, over a second, if you generate 200 kJ, (generated power Pg = = 200 kW) your load is absorbing 180 kJ, (absorbed power Pa = 180 kW) and losses are 5 kJ, (Pl = 5 kW) there are 15 kJ left over that have to go somewhere. In a rotating plant, there is a lot of energy stored in the rotating parts - E = 1/2 I w^2 - (for w read omega) and so the excess energy will go to speed up the system, increasing the frequency.
In most cases this is self-regulating to some extent as the load power for pumps, fans, etc will increase as the frequency rises. However, this must usually be improved on to get useful frequency regulation and the engine governor will reduce fuel to the engine in response to a speed increase.
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.
> 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.
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.
> (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.
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.
Thanks Mr.CSA for the reply.
Namatimangan08,I have checked the frequencies of our company owned power plant generators which are located at a total distance of 400 km.I checked the frequencies of 5 machines (ours here is 60 hz) and all of them are almost same. the difference being only in 0.02hz which could be due to their meters.You can see the values as given below.
My units-59.962 & 59.961
@ 100 km distance- 59.971
@ 250 km distance- 59.981 & 59.982 Hz.
> You can see the values as given below.
>My units-59.962 & 59.961
>@ 100 km distance- 59.971
>@ 250 km distance- 59.981 & 59.982 Hz.
1.How do you know because of the meters? You can see systematically the longer the distance is from referenced location the higher the slip frequency. If you move the location to 1000km away I'm sure it becomes even bigger.
2. That is what you expect under steady state condition where net accelerating torque to accelerate the rotor is less than 2% of the area peak demand capacity. You can record the measurements at these three locations every 10 seconds for 10 years. I'm very sure they will be never same longer than 30 minutes. But what you will see is sometimes frequency at location 1 is higher than at location 3. The most important thing you can see is the sum of the deviations (negative and positive) above your grid nominal frequency even over a period of as short as 10 minutes will be approaching zero.
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.
> 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,
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 OR 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 NOT 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) UP TO THE RATED POWER OUTPUT OF THE PRIME MOVER.
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. AND 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......
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.
> 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.
>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.
Int(P_m)dt -Int (P_e)dt = 0.5Iw^2 Eq(1)
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
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:
Id^2A/dt^2 = Applied torque- Resistive torque Eq(2)
A= angular displacement of the rotating mass
Id2A/dt^2 + cdA/dt +kA = T_m-T_e Eq(3)
c = damping coefficient
k = stiffness constant
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.
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.
> 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.
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.
To the fine Moderators: I propose to close this thread, once and forever.
Thanks very much in advance!
i have a great confusion in alternator in steady state changes. An alternator operating in steady state (at synchronous speed) what happens when..
1) prime mover torque suddenly shut down/increased/decreased
2) load is suddenly disconnected/short cktd
3) main field excitation suddenly gets open cktd/short cktd.
4) main field excitation suddenly reversed
5) rotor is suddenly blocked to move.
What will be the change in speed, terminal voltage, mmf, direction of rotation and in other datas...? Sir please response me..
> 1) prime mover torque suddenly shut down/increased/decreased
Since a generator is a device for converting torque to amperes, the power output (amperes) will decrease suddenly/increase suddenly/decrease.
> 2) load is suddenly disconnected/short cktd
For the case where load is suddenly disconnected, power output wil go to zero and if no other action is taken to reduce or shut off the flow of energy to the prime mover the prime mover will likely overspeed. In the case where a sudden short circuit occurs, the result will depend on many factors--but hopefully a generator protective relay will operate to protect the generator and prime mover.
> 3) main field excitation suddenly gets open cktd/short cktd.
Hopefully a generator protective relay will operate to protect the generator.
> 4) main field excitation suddenly reversed
How would this occur?
> 5) rotor is suddenly blocked to move.
How would this occur?
The direction of rotation of the prime mover and generator will not change during operation, before operation, or after operation.
Voltage is a function of speed and excitation. If speed remains constant and the excitation control system ("AVR") functions properly when any one of the plausible events occurs the generator voltage will react appropriately, depending on the type of excitation system.
I would like to know: "what causes the generator speed slow when load increases? is it armature reaction or anything else?"
First, why did you enclose your question in double quotation marks? Are you copying something from another of the 105 replies to this post?
Second, have you read any of the 105 replies to this post?
Third, a generator is a device for converting torque into amperes. A motor is a device for converting amperes into torque. Wires distribute amperes (torque) to motors and other devices which perform work by converting torque into useful forms of work (though I sometimes question how useful computers are, since I seem to work FOR computers more than they work for me these days!). AC power systems are particularly useful for distributing torque because the voltage can be easily transformed up and down, and by doing so the wires used to transmit the torque over long distances can be smaller (since when the voltage goes up the current goes down for the same amount of power (torque) transmission).
The thing about AC power systems is that they run best at or very near rated frequency--50 Hz in some parts of the world; 60 Hz in others. And to produce electrical power at a constant frequency the speed of the synchronous generators and their prime movers (turbines, primarily) need to be constant (F = (P * N)/120; it's all explained above).
The prime movers which drive generators are devices for converting one form of energy into torque. In general, when one applies more torque to a rotating device it will tend to speed up--but on a well-regulated grid that doesn't happen, the speed doesn't change by any appreciable amount (because the frequency is, or should be, very stable and doesn't change by any appreciable amount). So, what happens to the extra torque from the prime mover if it can't increase the speed of the generator it is driving?
Well, the generator, smart creature that it is, converts the extra torque that's trying to make it spin faster into amperes. And those amperes are what power the electric motors that drive the pumps to bring fresh water to your home and business, power lights and those virtual torque things: computers and computer monitors.
Now, let's say all the prime movers and generators are all operating at stable power output and the load on the grid (the sum of all the motors and lights and computers and computer monitors) is also stable and not changing. The grid frequency is also stable, and if everything is okay then the grid is at or very near rated frequency.
Someone starts a motor somewhere. That increases the load on the grid. If all the prime movers driving the generators don't change their energy flow-rates then the net effect of the starting of this motor is to tend to cause the frequency of the grid to decrease. Yes--of the grid. Regardless of the size of the motor or of the size of the grid. And, the change in grid frequency is proportional to the size of the motor in relation to the total amount of power already being transmitted on the grid. So, the change might be imperceptible--but it still happens. The larger the motor and the larger the load the motor is driving the larger the change in speed. But, there will be a change in frequency and it can be measured (if you have a device capable of enough accuracy).
Now, why does this happen? Because before the motor was started the total amount of torque being produced by all of the prime movers driving all of the generators was exactly equal to what was required to power the load (all of the motors and lights and computers and computer monitors) AND maintain rated frequency. But, when more load (increased torque requirement) is added to the grid and nothing is done to change the amount of torque being produced the effect is to reduce the speed of the prime movers because of the torque required to power the newly started motor. There's only so much torque being provided to the grid to power the load at rated frequency--any additional torque results in an increase in frequency (speed), and any additional load results in a decrease in frequency (speed).
It's EXACTLY like riding a bicycle carrying packages on a long and flat road that must travel at a constant speed. The rider has to provide only the necessary torque to move himself, the bicycle and the packages at the constant speed. Any additional torque causes the bicycle speed to increase; any decrease in torque causes the bicycle speed to decrease.
If someone tosses another package on to the bicycle as it passes by (increasing the weight being carried by the bicycle--the "load") if the rider doesn't increase the torque he's providing to the pedals the bicycle speed will decrease. But, in order to maintain the same speed the bicycle rider has to increase his torque production. It should be clear, a small package doesn't have much of an effect on the speed; a larger package has more of an effect on the speed. If people keep adding packages to the bicycle there will likely come a time when the rider isn't able to provide enough torque to maintain stable speed.
If another bicycle could be hitched to the first bicycle then those two riders could carry more packages than either could carry by himself. But, they have to coordinate their pedaling (how much torque they apply to the pedals) in order to keep the speed at the desired rate--or the speed is going to be very unstable.
Synchronous AC generators--and the prime movers driving them--are just exactly like multiple bicycles hitched together and moving packages at a constant speed. There is NO difference. None. Period. Full stop.
So, when we're talking about real power being produced by an AC power system, what we're talking about is torque production. If the torque required by the "load" increases but the torque production does not--the speed (frequency) decreases. If the torque production increases above the amount required by the load, the frequency increases. As long as the torque being produced by the generator prime movers is exactly equal to the amount of torque required by the load (the total amount of motors and lights and computers and computer monitors) the speed (frequency) will be at rated. When there is an imbalance of torque versus load, the frequency will change.
I'm sure there are maths that can be used to diagram load angles and emf's and counter-emf's, but this is what happens. Electricity production is about torque production and transmission. The prime movers (turbines) driving the generators are actually doing the work of all the motors and lights and computers and computer monitors at the ends of all of the wires. The wires are just ways to get the torque from one area (where it is being produced) to other areas (where it is consumed). And, again--an AC power system transmits power best when it's operated at a relatively stable and constant frequency. And the frequency is constant when the amount of torque being produced equals the amount of torque being consumed.
Just like on the bicycles in the example traveling at a constant rate of speed. The torque required to maintain a constant rate of speed varies as the load varies. An excess or deficiency of either will cause the speed to change. And since speed and frequency are related on an AC power system--an increase in load (increase in torque requirement) without a corresponding increase in torque production will result in a decrease in speed.
Does this answer your "question"?
Dear CSA sir,
1. That was my own question, not copied from any where else.
2. Yes, I read few replies of those but could not able to get my answer.
3. I guess I could not be able to place my question clearly.
Let, an isolated bus where a generator (rating: 300 Ampere) is supplying 100A to a motor maintaining 50Hz. If another motor (rating: 150Ampere) is connected to the bus, generator must supply 250A (100+150) with decreased frequency unless prime mover supplies more energy (let, any how prime mover is not supplying more energy).
My question is- Why does required torque increase when generator's current (load) increases? What does insist the generator to ask for more torque? i.e. When current increases, Is there any thing which opposes the generator's rotor to rotate (that is why generator can not maintain 50 Hz frequency)?
I give up. Try this:
Then, use your preferred Internet search engine to look up other relevant words terms.
You should be able to find all the maths and vectors you need.
I really hate to surrender defeat, but sometimes one just has to cut their losses in order to live to fight another day.
To my definition, you are are confusing two different terms. And failing to understand what motors and generator do: they allow torque to be transmitted long distances over wires instead of via shafts and belts and such. Or instead of every factory having to have its own torque-producing device.
But, I don't have all the answers and sometimes it's okay that I don't. This is going to have to be one of those times.
Best of luck!
If grid frquency decreased from 60 to 57 HZ what effect on generator active power increase or decreased connected in parallel with grid? generator specification 275MW, 3600RPM, 18KV, 60HZ.
Good, seemingly simple, question; extremely difficult to answer because it depends on how the generator-set is being operated.
The short answer goes like this: If the machine was operating at its rated output for the current machine- and ambient conditions when the frequency dropped, the power output would either decrease or not change by very much (depending on the type of prime mover driving the generator). If the machine was at part load (not operating at the rated, maximum output possible for the current ambient- and machine conditions) then the power output SHOULD increase--up to the rating of the prime mover.
Presuming the unit was at part load (not operating at the rated, maximum output possible for the current ambient- and machine conditions) and the prime mover governor was in Droop speed control, as the frequency decreased the active power would increase. This is one of the things Droop speed control does--tries to help maintain frequency by changing the active power output when the grid frequency changes.
But the amount of active power increase (as the grid frequency decreases) has a limit: It can't increase beyond the ability of the prime mover to produce power for the current machine- and ambient conditions. In other words, it can't go beyond it's rated output for the current machine- and ambient conditions. So, if the prime mover is rated at, say, 250 MW, the power output can't go above approximately 250 MW. So, if the machine was operating at 200 MW at 60 Hz, and the frequency dropped to 57 Hz (which is a pretty big drop--percentage-wise) the machine output can't increase above approximately 250 MW.
If the unit was being operated in Load Control (trying to maintain a particular load (active power) setpoint) then the active power would probably not change by very much (which is contributing to grid frequency instability).
Most people believe that when the grid frequency is unstable the power output of a generator-set should remain constant. But, that's not what it's supposed to do. Droop speed control will increase the energy flow-rate into the prime mover if the frequency decrease, which will cause the active power output of the generator to increase--up to the ability of the prime mover to produce power (it's "rated" output, approximately). And, if the grid frequency increases then Droop speed control will decrease the energy flow-rate into the prime mover, which will decrease the active power output of the generator.
One of the things Droop speed control tries to do--and what grid operators/regulators rely on--is that machines which can contribute more active power during grid frequency decreases will increase their active power output. And, if they don't increase their active power output when possible then they are not contributing to grid stability. (Grid frequency decreases when the load exceeds the generation, and it increases when the generation exceeds the load.) So, power plants that try to prevent their generator-sets from changing power during grid frequency disturbances are contributing to grid instability by not allowing their machines to change load to try to support grid stability.
Presume two riders on a tandem bicycle are both pedaling at about 70% of their capacity on a level road and are maintaining a constant speed--which is what they want to do: maintain a constant speed. Now, let's say that a large package is suddenly added to the basket on the back of the bicycle, causing the bicycle to slow down. The rider in the front of the bicycle increases the pressure he is applying to the pedals of his crankset, but the rider in the back of the bicycle doesn't--he keeps pedaling with the same pressure. The force being applied by the rider in the front isn't sufficient to keep the bicycle with the added weight moving at a constant speed and the speed decreases. But, if the rider in the back had increased the pressure he was applying to his pedals the speed of the bicycle would have returned to desired.
It's EXACTLY the same for AC power systems. Speed and frequency are directly related, and load changes cause speed changes. As long as somewhere a machine increases its active power output when motors and lights and computers and computer monitors are started the grid frequency will remain at rated. If a machine trips off-line suddenly and no other machine can (or does) increase it's active power output to help maintain rated frequency (speed) then the frequency of the grid (and the speed of all the generators connected to the grid) will decrease. If some generators could have increased their active power output but didn't (because the operator or the supervisor didn't think it should change) then they are contributing to grid instability instead of helping to maintain grid frequency.
Now, let's say the machine at your site was operating at maximum power output possible for the current machine- and operating conditions and the grid frequency decreased from 60 Hz to 57 Hz. It can't increase its power output--it's already at its maximum, so the power output will not change by very much--unless it's a single shaft heavy duty gas turbine-generator, in which case it's power output will go down, and probably pretty significantly. Because the speed of the axial compressor will decrease as the grid frequency decreases, so less air will flow through the machine which means the fuel will have to be reduced to prevent the turbine from tripping on exhaust overtemperature. It can't stay at rated output (for rated frequency), so the active power output will decrease.
That may not have been exactly what you asked, but I have a strong suspicion it is definitely related. You didn't say how the prime mover driving the generator was being operated (but most newer machines these days are usually operated in Load Control, or at "Base Load" (rated power output for the current machine- and ambient conditions)). Again, most power plant operators and their supervisors DO NOT want their power plant's output to change during grid frequency disturbances. They mistakenly believe that they are supposed to maintain a stable active power output. But that's not what's supposed to happen, no matter what operators or their supervisors believe. The way AC power systems operate--and are to be operated--require the active power output to change with grid frequency if possible. If it can, but it doesn't, then it's not contributing to grid stability--it's actually contributing to grid instability.
Lastly, ideally a machine with 4% droop could only produce rated power down to a frequency of 57.6 Hz, and then only if it was operating at zero active power when the frequency was at 60 Hz.
So, I hope you see the answer to your seemingly simple question is not so simple. There are a lot of factors, some of which are easier to explain and understand, and some of which are not so easy to understand or explain.
Hope this helps!
An increase in the current drawn by the load draws more power from the generator. If the mechanical power supplied to the prime mover does not increase, this power comes initially from the kinetic energy of the rotating parts - turbine and alternator connected together. As a result, the alternator will slow down and will continue to slow.
In most cases, the mechanical power supplied to the generator will be increased as the speed drops, because the governor system will sense the fall in speed or frequency and will increase the flow of fuel, steam, or water as appropriate. The system will come to rest at a new equilibrium point where the mechanical power in matches the electrical power drawn off (plus losses).
The whole system is in an energy balance - if it is not, it will not be in steady state. Remember that, in electrical terms, power = current x voltage; in mechanical terms, power = torque x speed. As long as voltage and speed are more or less held constant (through the actions of the voltage regulator and governor respectively, the current and torque will remain in proportion.
thanks for reply, I need a little more clarification
generator (275 MW at 18 kV working at 60Hz.)
Generator working limits 58.5Hz and 60.5 Hz. its mean at 58.5Hz steam turbine control valve full open. but if the frequency drop further to 57 Hz, what will the effect on generator active power?
It seems I don't have the answer to your question. Perhaps another contributor to control.com will step in and help.
Saudaslam... the situation you described is not that of a local generator connected to an 'infinite' grid.
Expectation of a reasonable solution to your problem requires additional information. For example, pre-disturbance parameters such as Gen Capacity, details on connection to grid, Step-up Xfmr (if existing), OVH line to grid (if any), percent Load change, V,I, etc!
after reading through all of these replies, I have a few things to add. 60HZ major grid @ 59.3HZ 58.9HZ and 58.5HZ will drop 10% of load at each point (30% total) to maintain system stability. And all generation will be climbing to max load to attempt to raise frequency That being said, I have never seen the frequency more than .05 from nominal. As far as generator speed, a +/- of 1 RPM from 3600 is normal but anything more or less would be of concern, but as stated many times frequency is directly related to generator speed. Once the generator is synchronized, there is no deviating from grid frequency. If there is not enough torque from the prime mover, you will motor the generator. Frequency will still not deviate from system frequency. Many stations will place generator load control to remote (Grid operator controlled) and set the primary mover to follow load.