Hello,

We are working on the control system of a CHP plant and I would like to know how the power generation control normally works.

I have seen a lot of information talking about PMS but I still have some questions about it.

We have a DCS (in this case will be Siemens), but I don't know if the following systems comes with the DCS or if they are independent of it:

-PMS
-AGC
-AVR (I think this comes with the turbines and it is independent)
-Load Shedding
-ESD

If somebody can also give me some explanation about each system it would be helpful.

Thank you very much for your help.

 

Daniel Chamorro,

Bravo! You are wise to anticipate and ask before you need to know; it will help if you develop your understanding before actually having to know how something works if it doesn't work or doesn't seem to be working properly and you have to fix it or diagnose the problem (which may only be one of perception).

PMS - Power Management System
Usually a control system, or a scheme implemented in a larger control system (such as a DCS) that is used to control active and reactive power into and out of a power generation facility, "automatically." Usually, my experience is that these PMS things work, just not the way the plant operators and owners want them to work. They usually take a lot of "tuning" and adjustment to get them to work "correctly", and even then, people's definition of "working correctly" seem to change as soon as someone reprograms it. These kinds of systems are used to try to "balance" or control how much power is coming into a plant or going out of a plant at certain times of the day or month or year, and automatically, because operators can't usually be trusted to watch things close enough to do it "manually".

AGC - Automatic Governor Control
Usually some discrete inputs or analog inputs from a remote control facility (grid regulator; grid supervisor) to raise or lower load and/or VAr/Power Factor as THEY see fit. So, essentially the remote facility is in control of generation while AGC is active; they make the decisions about how much real and/or reactive load is being produced and for how long.

AVR - Automatic Voltage Regulator
You are correct; it's provided as part of the turbine-generator. It controls the excitation provided to the generator rotor which is used to control generator terminal voltage, VArs, and/or Power Factor.

Load Shedding - A function that is used to reduce the electrical load on a plant running in "island mode" by opening the supply breakers to non-critical or non-essential load (at least they were deemed non-critical or non-essential when the system was designed, but someone will ALWAYS say--after a particular load has been de-energized--that this load or that load IS critical or IS essential!). When a plant is running in "island mode" it is usually separated from a large or infinite grid and is supplying it's own electrical power. Under some conditions at some plants the electrical load might be more than the capacity of the generator(s) at the plant to provide and still maintain rated frequency, so a Load Shedding system will automatically (again, because the operators can't be trusted to do so manually) open the breakers of supplies to loads that were at some point designated to be non-critical or non-essential. Again, that designation is usually made early on in the plant design and not with the knowledge or consent of owners or operators who consider every load to be critical and essential, and so, controversy usually erupts when ever "automatic" Load Shedding is unexpectedly implemented (which is usually at the worst possible time under the worst possible circumstances).

ESD - Emergency ShutDown
A scheme for an orderly shutdown of a plant or the critical components of a plant in the event of an emergency. It's an attempt to prevent unintentional releases of emissions or fuels or chemicals into the atmosphere and to protect personnel and equipment.

Any of these functions/schemes can be programmed into a DCS, with the exception of AGC which, again, is from some remote location (a "higher" power in the scheme of things!). Now, the AGC inputs and outputs may pass through the DCS, but they are not generally programmed into the DCS.

Best of luck with your plant--especially the programming of the Siemens DCS!

 

Dear CSA,

Wow! Thank you very much for the information, it has been very helpful! I do not have much experience, I am learning and trying to understand how a CHP Plant works before doing anything. It looks very difficult but interesting!

I have been thinking about your answers and I have new questions about it.

First of all, I will write what I have in mind:
* CHP Plant -> Will generate always what the grid needs at every moment.
* The grid -> Will tell the CHP plant the generation requirements.

--- PMS ---
"Control active and reactive power into and out of the power generation facility". Just to know if i have understood it, I will write an example:

* PMS checks the power demand from the grid.

* PMS tries to generate the same power than the demanded by the grid (more or less power will generate problems).

* PMS tells the AGC how much power to generate? Are PMS and AGC communicated?

I also would like to know if the PMS also manages the Load Shedding during the "Island Mode".

--- AGC ---
I guess this is something which comes with the Turbine (like the AVR)? The PMS will tell it how much generate and it will inject more/less gas to the turbine to reach the power. With "remote facility" do you mean the grid? I guess here will be the frequency also controlled.

--- AVR ---
This is something clear for me I think, it is independent of the power generation and it will control the excitation to regulate the voltage.

--- Load Shedding ---
I have seen that normally PMS controls it, some UF Relays must be installed to break the circuits automatically. When the load is more than the generation, then the frequency falls (48.5Hz por example) and the "Under Frequency" relays will break some circuit to stop less important loads and then the frequency will rise to the normal limit (50Hz). I guess this "UF Relays" will be active only during the Island Mode.

I do not know if I am right, maybe it could be something programmed in DCS and we do not need the UF Relays. I do not know what normally is provided.

--- ESD ---
I have asked a lot about this and I also have seen some independent ESD systems (like Honeywell FSC). But I have been thinking about it and, as you say, it could be programmed in DCS (with redundant hardwired specific signals). I will ask the DCS supplier and if they do not provide it I will buy an independent one (which should be communicated with DCS).

--- Frequency problems ---
This is my biggest problem because I can't understand how the frequency is controlled. I know that it depends on the Load (grid?) and the RPM of the generator. During normal conditions, if we have a constant gas input to the turbine and we are generating 50Hz, then if the load changes (grid?) the frequency will do it too, so the control system (AGC?) will increase/decrease the gas input to the turbine so the generator will compensate the load and the frequency will be controlled.

The problem for my CHP plant is that the electricity generation is secondary, our main goal is steam production, so the gas input to the turbine will be controlled by steam requirements... Then my mind can't understand how frequency and power generation will be controlled... I think that the power delivery can't be random, it depends on the grid's demand.

I guess that we always need to generate the same power than the demanded by the grid and we can't generate any other power (more or less). I do not know what happens when the CHP plant do not generate the grid requirements.

I also do not know the difference between an infinite or finite grid, I see it as a load and my generator as a source.

I apologize for my bad english, maybe my explanation is not very good...

All these questions comes because I am going to buy the DCS soon and I want to have as much control systems as possible integrated in it. If all of them can be programmed in DCS then it will be great for me. If not, I will need new suppliers for these independent control systems which will be communicated with DCS, and I always have communication problems during commissioning...

Thank you very much for the information! I'm really grateful for the help.

Best regards,
Daniel

 

Daniel Chamorro,

You are welcome.

When a generator and its prime mover (a combustion turbine in your case) are connected to a grid in parallel with many other prime movers and their generators, the frequency of the generator (and the speed of the combustion turbine) are fixed by the grid. The grid regulators are, or should be, controlling the amount of generation on line to be equal to the amount of load on line (the motors, lights, computers and monitors). The amount of generation must be equal to the amount of load for the frequency to be at rated. So, when your CHP is on line with other power plants, the speed of your generator and prime mover (and the frequency of your generator) are not controlled by the turbine control system or even the PMS; the speed and frequency are controlled by how well the grid regulators match generation and load.

Grid regulators will use AGC to remotely increase and decrease generation of several, or even many, generators/power plants in order to make the amount of generation equal to the load. Usually, when AGC is active the grid regulators have control of the fuel--and, hence, the load--of the combustion turbines. They are raising and lowering loads of prime movers and generators as motors are started and stopped, and lights are turned off and turned on, and as computers and monitors are being used or turned off.

AGC is something that is usually the "master" or off; it's not something that's usually operated in conjunction with some other control mode, because the grid regulators are using AGC to balance generation and load and they don't want their commands to be over-ridden because they are trying to control frequency.

Usually PMSs are used in plants where there is a large load and some generation, such as a refinery or chemical plant. The amount of generation might be more or less than the load of the plant, and the PMS is used to balance the power flow across the "tie-line" between the plant and the grid. Let's say there is an excess of generation at the plant for most conditions, but the grid doesn't want to buy all of the excess generation. The PMS can be programmed to limit generation to the amount that the grid is willing to pay for without the operators having to manually adjust load (operators are REALLY busy people, and just can't be bothered with such minor details as controlling generation; there are simply too many newspapers to be read to allow time for controlling generation or trending steam flows or exhaust temperatures).

The PMS can be used to control reactive current flows, as well. Perhaps the grid has a contract or requirement that at certain times of the day or the year that the plant be operated at a particular power factor or VAr amount; the PMS can be programmed to do that automatically so the operators are free to read more papers and surf more of the Internet.

Again, PMSs are likely used when AGC is not being used, and vice versa.

Some under-frequency relays are active at all times; UF relays protect the generator--and the turbine. Others may only be active at certain times, such when islanding. It all depends on how the plant is programmed.

If your CHP is going to be connected to a large or infinite grid, the power production will be whatever it will be based on the exhaust heat from the gas turbine that's required to produce the steam that's required. In other words, the power production will vary as the steam load varies.

Speed and frequency confuse many people; don't feel alone! Yes, there is a direct relationship between speed and frequency, and it's:

F = (P * N) / 120

where F = Frequency (in Hz)
P = Number of poles of the generator rotor
N = Speed of generator rotor (in RPM)

If your combustion turbine is directly coupled to the generator (even if it's through a reduction, or load, gear) the speed of the turbine is directly proportional to the speed of the generator, and vice versa.

When you are starting the combustion turbine and generator, you will adjust the fuel to make the generator frequency nearly equal to the grid frequency before and during synchronization. Increasing fuel increases speed, and frequency; decreasing fuel decreases speed and frequency--when the generator breaker is open!

When the generator is <b>synchronized</b> to a grid with many other generators (when the generator breaker is closed),, the speed of the generator (and of the directly-coupled prime mover) is directly proportional to the frequency of the grid with which it is connected. There are very powerful magnetic forces at work inside the generator that keep the generator rotor spinning at a speed that is proportional to the frequency of the AC flowing in the generator stator windings. Synchronizing a generator to a grid involves making sure that the generator rotor is in a position to be locked into synchronous speed with the other generators on the grid, all of which are also operating at speeds per the formula above.

As you increase fuel to your turbine when it's on the grid, instead of your turbine and generator increasing speed the additional torque is converted to amperes by the generator which increases the share of the load the generator is providing to the grid. Generators are devices for converting torque to amperes, and motors are devices for converting amperes to torque. So, the generator at your site is actually pumping water at many remote sites, and driving fans and elevators and machinery at many locations, in addition to lights and computers and monitors. When many AC synchronous generators are connected in parallel with each other (when they are <b>synchronized</b>) the frequency of all of them, under normal circumstances, are all the same so their synchronous speeds are all the same. When more torque is applied to any one of the generators that generator can't speed up (by any appreciable amount!) so the generator converts the extra torque to amperes.

In reality, assuming that the load is constant and that no other generators are changing their energy flows to the prime movers the frequency of the entire grid will increase--by an almost imperceptible amount, probably thousandths or hundredths of a Hertz. It's the job of the grid regulators to balance your increase in torque by decreasing the torque (load) of another generator.

As you will learn, your CHP will usually have to call some remote location to tell them when you will be going on line, and they will either need to know or will already know the rate at which you will be loading the unit--so they can reduce the load of some other unit(s) by a similar amount to keep the total generation equal to the total load, or the grid frequency will start deviating from desired.

When the load on the grid exceeds the amount of torque being provided to the generators by the prime movers driving the generators, the frequency will begin to decrease. That's when the grid regulators will use AGC to raise the "load" of some generators and their prime movers to increase the frequency. When the load on the grid exceeds the torque being provided to the generators by their prime movers the frequency will begin to increase. That's when the grid regulators will use AGC to lower the load(s) of some generator(s) and prime mover(s). All to make the amount of generation equal to the load.

If the regulators do a good job, the frequency will be relatively stable. If they don't, or if operators don't do a good job of keeping their units on line and available and not tripping off line intermittently then the grid frequency won't be stable. And, if operators don't understand how their decisions can affect grid frequency they can also have an adverse affect on grid frequency stability.

I hope this answers most of your questions.

 

Daniel,

I think CSA gave a great explanation of the general features, but I would argue that load shedding isn't just for islanded systems. If you are connected to a utility, depending on the reliability of the grid, the utility may also be susceptible to frequency problems. In the case of a problem on a weak utility, the utility frequency may become low, therefore your system frequency will be low. The proper response to this condition usually involves separating from the utility (opening the tie breakers connecting your system to the utility).

You are correct in that most load shedding systems are done through under frequency relays set on various loads. There are usually several levels, the first might begin at 49.3Hz, then 49Hz, then 48.5Hz, or something similar. If the system frequency reaches the first level a group of loads are programmed to trip. If the frequency continues to fall, it may reach the other two levels and cause those loads to trip. More advanced under-frequency schemes even include rate-of-change of frequency to determine which loads are shed. If the frequency is decaying more quickly, you will want to shed more load, and vice-versa.

Load shedding protects the plant from under-frequency problems. We usually have under-frequency problems when we lose a generating unit (it trips offline for any number of reasons), or a utility tie line (the tie breaker opens unexpectedly). So, modern load shedding systems (not frequency based) will actually perform a series of "what-if" calculations to determine the impact that a loss of generation would have on the system(what happens to the system if GEN1 trips, what if GEN2 trips,..etc), or a loss of a tie-line. Knowing this information, the a load shedding system can actually pre-arm itself. So the moment the facility loses a generator unexpectedly, the load shedding system immediately acts to shed the necessary amount of load. This is helpful for two reasons: 1)the under frequency type system has to actually wait for the frequency to fall before it acts, where as the modern load shedding systems reacts immediately, before the frequency has a chance to move much. And 2) The modern load shedding system can calculate a fairly exact amount of load to shed, whereas the frequency based system sheds one level, and if that doesn't stop the decline in frequency, it sheds the next level, and so on. This method isn't very precise.

Of course, the more modern type load shedding systems come at a cost much greater than your under frequency scheme, but it's up to the end user to decide if the price tag is worth it.

If you are interested in learning more about this, you can access IEEExplore.org and search for papers about load shedding. There are several papers about modern load shedding systems.

Cheers,
Nic

 

Dear CSA,

First of all, thank you very much for the information, I am grateful for the help.

I have clearly understood your explanation, for a normal generation plant, you must have the amount of generation equal to the amount of load to rate the frequency. This is normally controlled by the Grid through the AGC which controls the gas input to our gas turbine. Voltage will be always independently controlled using the AVR of the turbines.

I think that our CHP plant is a special case because power generation is not our main goal, we must keep the steam generation rated and, then, export/import electricity to the grid.

Our operational modes (for the moment...) show how the steam flow must change to follow the steam demand of the existing plant (we are giving steam to another plant). I am really sure that this steam demand must be accurately controlled to not to have big changes in both input turbines (ST & GT) because otherwise they will trip due to Frequency problems. As I can see, we can't loosely play with ST (steam) and GT (gas) inputs, this is something that must be controlled with some feedback from the Grid.

I do not know how the Grid works in this case, I guess we must have a contract with them, telling the amount of power given always by us. Then, the Grid will try to have always the same load to rate the Frequency of our turbines.

My team thought that frequency and voltage could be independently controlled so we could play with input turbines because the Grid can absorb anything. Nobody has taken care of the frequency... I have seen a lot of problems since I know that Frequency depends of the Load and the turbine input (speed generator).

Once again, thank you very much for your help, power generation plants are very difficult and I would not be able to understand them without your advice.

Best regards,
Daniel

 

Daniel,

I must not have been very clear. When your turbine-generator is <b>synchronized</b> to the grid where hundreds of other generators and their prime movers are also synchronized the frequency of the "grid" <b>***IS***</b> the frequency--and therefore the speed--of your turbine-generator, and of every generator and its prime mover that are all <b>SYNCHRONIZED</b> together on the grid.

When the generator breaker connecting your turbine-generator to the grid is closed there is current flowing in the stator windings of your generator. Now, if the turbine is working correctly that current is the result of the torque being applied to the generator. But, the point is that when current is flowing in a conductor a magnetic field is created around that conductor. Because we are talking about alternating current (AC), the magnetic fields associated with the current flowing in the stator windings appears to rotate around the stator--at the rate of 3000 RPM probably (I'm presuming a two-pole generator; most large synchronous generators are two-pole machines these days), presuming the grid frequency is stable at 50 Hz.

The generator rotor also is a very large magnet, and we all know how opposite poles of magnets attract each other. Well, the north pole of the generator rotor is attracted to the south pole of the generator stator, and the south pole of the generator rotor is attracted to north pole of the generator stator. And, because the north- and south poles of the generator stator are "rotating" around the stator the generator south- and north poles (respectively) "follow" the rotation of the stator poles.

Now, since the speed of "rotation" of the magnetic field of the generator stator is directly proportional to the frequency of the current flowing in the generator stator windings and since the generator rotor is LOCKED in step with with rotating generator stator fields and can't be spun any faster or any slower than the rotating generator stator field the speed of the generator rotor--and of the directly-coupled turbine--are fixed. And are directly proportional to the frequency grid. If the grid frequency changes, the speed of "rotation" of the generator stator magnetic fields will change, and the generator rotor speed will also change. The attraction of the magnetic fields of the generator rotor and the generator stator <b>WILL NOT</b> allow the generator rotor to spin any faster than the rotating magnetic field of the generator stator.

And this is true for <b>ALL</b> generators (and directly-coupled prime movers) <b>SYNCHRONIZED</b> together on a grid. That's one reason why they call it <b>synchronization</b>--they are all locked in step with each other based on the frequency of the grid.

And the total amount of generation <b>synchronized</b> to the grid must exactly match the total of all the motors and lights and computers and monitors in order for the grid frequency to be stable and at the nominal frequency of the grid.

Even if your turbine stopped providing torque to the generator rotor, as long as the generator breaker connecting the generator to the grid remained closed current will be flowing in the generator stator windings--the current will come from the grid--and a rotating magnetic field will still exist, and the generator rotor will remain locked with the rotating stator field. The grid will be supplying current to the generator, but it will actually become a motor--that is spinning the turbine. This is called "motorizing the generator" and is not a desirable condition to exist for very long, so there are protective relays to open the generator breaker when the amount of "reverse" current exceeds a certain level.

Anyone reading this who is working at a power plant, watch the speed of the generator (and/or prime mover if the prime mover is directly coupled to the generator) as load is "added" to or "subtracted" from the generator by increasing the fuel flow (or steam flow, for a steam turbine) when it is synchronized to a grid with other generators and their prime movers. The speed of the generator rotor will not change as load is added to or subtracted away from the generator. There are imperceptible acceleration changes that occur when the generator is loaded or unloaded, but for all intents and purposes the speed will remain unchanged (now--this is presuming the grid is relatively stable!).

Yes, when you are starting up or shutting down the prime mover and generator, changes in fuel (or steam) flow will cause the speed of the prime mover and generator to change. But, when the generator breaker is closed the speed of the generator rotor is fixed by the frequency of the grid with which it is connected. And, that's true for all generators, and their directly-coupled prime movers. Even if the prime mover stops providing torque to the generator rotor as long as the generator breaker remains closed the generator rotor will continue to spin at a speed that is directly proportional to the grid frequency. (Hopefully not for very long!)

The magnetic forces at work in a generator are very strong. Very strong. VERY strong. <b>VERY</b> strong. And they are the same in every generator <b>synchronized</b> to the grid.

And it is the grid regulators that have to anticipate and respond to changes in the total load on the grid by increasing or decreasing the total amount of generation to keep the grid frequency stable. And this happens when the total generation exactly matches the total load.

There are many similar plants around the world, where steam is the primary product, and electricity is the "by-product". Before people started using the exhaust heat from gas turbines to produce steam, they just burned fossil fuels in a conventional boiler to produce steam. Usually the steam was produced at a very high pressure and it was run through a steam turbine to reduce the pressure (and temperature) to usable levels and then distributed the steam to the facility or places where it's needed.

When producing steam with a conventional boiler to produce electricity, the process is only about 35% efficient at best, when the plant is brand new. However, when using the exhaust heat from a combustion turbine to produce steam to produce electricity the efficiency can be as high as 55-60%. So, for the same fuel nearly twice as much electricity can be produced by using the exhaust heat from a combustion turbine in what's called "combined cycle".

Now, it's also more efficient to use a portion of the steam produced from combustion turbine exhaust in a CHP, or for other large users of steam, such as refineries, paper mills, food processing plants, etc.

The grid regulators will want you to produce electricity at a stable rate and to be reliable (to remain on-line without emergency "trips") to help contribute to the grid stability. However, they will understand how your plant needs to vary its output because of its primary responsibility--and they will have to factor that into their planning for the day, the week, the month, and the year. All they really care about is that the electricity you produce is stable, that it doesn't change wildly during the day, that you call and tell them when you will be synchronizing to the grid and how fast you will be loading the generator(s), and how much power you think will be producing and for how long you plan to remain on line. And, that you call them to tell them when you are planning to take the unit off the grid, and how fast you will be unloading the unit. They need this information to be able to reduce the load of other units (probably using AGC) as you load your unit, and to increase the load of other units as you unload your unit--all to keep the total amount of generation on the grid equal to the total load on the grid. To keep the grid frequency stable and at rated frequency.

For smaller "grids", there is usually one unit that is being used to control the frequency of the grid, and therefore the speed of all the other generators and their directly-coupled prime movers. The governor (control system) of that prime mover is operated in what's called Isochronous Speed Control mode, and it VERY quickly responds to load changes--which would cause frequency changes--and adjusts it's fuel (or steam) flow to keep the speed of the generator rotor stable and at rated. And, therefore the speed of all the other generator rotors stable and at rated.

All of the other prime mover governors (control systems) connected to the grid should be operating in Droop Speed Control mode, to allow the Isochronous governor to control the frequency and to stably provide current to the grid with all the other generators and prime movers.

When you think of a grid with many generators and their prime movers all <b>synchronized</b> together, remember they are powering a total load that is much greater than any single generator and its prime mover could power. They all have to work together to provide power to a load that is much larger than any single unit could provide.

On very large grids, it's most likely that there is no single unit being operated in Isochronous Speed Control mode. But, there are so many units all <b>synchronized</b> together and they represent a very large "inertia" (the load AND the generators and their prime movers!), so that no one prime mover and generator can have an appreciable impact on the grid frequency. Think about it--if the grid load is 6000 MW (that's six GIGAWATTS)--and your turbine is rated at 40 MW or even 250 MW, if you suddenly loaded or unloaded your turbine while the generator was <b>synchronized</b> to the grid, would your turbine be able to change the grid frequency by any appreciable amount? Not likely.

It's the grid regulators, using schemes such as AGC, that have to adjust the total generation to match the total load to keep the frequency at rated. The grid regulators are the "Isochronous governor" keeping the grid frequency at rated.

And, because we are talking about AC grids which are designed to be operated at a particular frequency, therefore the frequency of every device connected to the grid is all the same--motors and generators alike. (In fact, there is no difference between motors and generators--except the direction of current, and therefore, torque into and out of the electrical machine.)

I need to get some sleep, now. Take care. I hope this helps!

 

Daniel,

You might want to check out this thread:

http://www.control.com/thread/1348990642

It's kind of related....

Also, sometimes the software control.com uses inserts unintended spaces in URLs, so remove any spaces if it does....

Also, use the 'Search' feature of control.com; a lot of the questions you might have have probably been asked and answered before on control.com. That's the beauty of forums like this--especially when the originator provides feedback when resolving problems. We like to say here, "Feedback is the most important contribution!"(c) because it lets other reading the threads, sometimes years later, if the information provided was useful--or a complete miss!

 

Dear CSA,

I apologize for the delay answering!

Thank you once again for helping me with this.

I have read your answer two or three times, I makes sense everything. As a circuit diagram, I can imagine several sources in parallel (same voltage controlled by AVR) connected to a load. If my generator gives less current (A) then the grid will use AGC to increase the power from another generator, then my lost current (A) will be taken by the load from that generator to balance it.

It makes sense that if I am connected to an infinity grid, it will not be very sensible to my power generation changes. Anyways, I guess that the grid will give me some working range, to know how much power I will increase or decrease, so they will have better capability of response.

Once again, thank you very much for helping. I apologize for my understanding problems and my bad english.

Best regards,
Daniel

 

Daniel Chamorro,

Don't be offended for not understanding someone's explanation--especially mine. And, your English is fine. If I seem frustrated, it's because we have this running battle here on control.com about whether or not AC generators (alternators) run at different speeds after <b>synchronization</b>. I, for one, believe they do not. Just look up the definition of "slipping a pole" which is what happens when an alternator is driven to run at a speed other than synchronous speed--which is the one that's proportional to the grid frequency with which it is <b>synchronized</b>. A pole can also be slipped if the excitation on the generator rotor is less than that required to maintain <b>synchronization</b>.

I think most people in the power business just equate loaded operation with unloaded operation--meaning that if you vary the energy flowing into the prime that the generator speed will vary. They get that <b>synchronization</b> is important and involved. But, after the breaker is closed, they just mostly continue to think the speed changes with energy (fuel or steam) flow into the prime mover. Why? Because they mostly never look at the tachometer when they are generating power--they are only looking at the wattmeter. And making ass-umptions about how the generator works when the breaker is closed because they know how it works when the generator breaker is not closed.

In any case, just remember your basic power AC power formulas, and think about each component.

F = (P * N)/120

and three-phase power:

P = Vt * Ia * (3^0.5) * PF

Where, P = Power, in Watts (or KW or MW)
Vt = Generator Terminal Voltage
Ia = Generator Armature (Stator) Current (Amperes)
PF = Power Factor, never greater than 1.0

If you remember that the terminal voltage of a generator (which is proportional to excitation--from the AVR) is considered to be relatively stable and doesn't change by very much during normal operation, and that under normal conditions the Power Factor of a load is relatively stable and doesn't change by very much under normal operation, the only "variable" in the equation is Ia--which is a function of the amount of torque applied by the prime mover, which is a function of the amount of energy being admitted to the prime mover. More torque equals more load; less torque equals less load.

It's all downhill from those two formulas.

The electrical power generation fundamentals, anyway.

Oh, and don't forget the laws of magnetic attraction and repulsion!

Best of luck!

 

Dear CSA,

Once again, thank you very much for every explanation and my apologizes for bothering you with so many questions. I am really glad for your help.

I hope that this will be my last clarification for this post, I do not want to steal more of your time.

I think that I have understood that Synchronous Generators work differently depending on where are they connected to. Just to be sure, I think we will have two possible situations:

- Island Mode -

During this mode we must have a accurate control using PMS and Load Shedding because the generation must be exactly the same than the load of the plant to mantain the Frequency as constant as possible. The reason of this control is that, during this mode, the frequency (and speed) will depend on the fuel/gas input to the turbine and the load of the plant.

- Connected to an infinity Grid -

During this mode the output Frequency will be constant due to the magnetic forces produced by the Infinity Power Grid into our stator (the rotor is slipping because it tries to change the speed due to the torque but it does not change due to the magnetic forces which mantain it constant).

The output voltage will be constant due to the AVR regulation (more or less DC current input into the rotor).

Then, the only variable here is the output current, which will depend on the Torque, controlled by the fuel/gas input.

Then, if we have more gas/fuel input (because we need more steam for our plant), the speed/frequency will not change, but the output current will do. Great for us, We do not have to do anything, we only give more current to the grid.

Then, I guess that the "Grid" will have to change the power from one of its generators to compensate our current fluctuation (which will not be much for the Grid because we are very small for it).--> This is something I have thought, I do not know how the Grid works here.

I think that these are the main concepts that I need to know for my plant. I also guess that the Grid must give us some rules, which means, some fuel/gas input ranges to know how fast we will change our torque. They must always know our fluctuations and also must be advised if our turbine trips.

Thank you very much for helping, for your patience, and your time. I am very glad.

Best regards,
Daniel

 

Daniel Chamorro,

The Isochronous Speed Control mode of the governor of the turbine control system(s) at your plant will do the necessary adjustment of fuel or steam flows to the turbine to make sure that frequency remains at rated when operating in Island mode. No PMS or Load Shedding required--unless the expected load when operating in Island mode exceeds the capacity of the turbine being operated in Isochronous mode. Only one turbine can be operated in Isoch mode (unless there is special Isochronous Load Sharing schemes and some method of communicating between the two turbine control systems is in place).

I have (painful) extensive experience with various forms of Isoch Load Sharing and PMSs trying to control multiple turbines operating in Droop Speed Control mode in Island mode; suffice it to say that it rarely works very well, and leads to lots of finger-pointing between turbine packagers and DCS vendors and PMS vendors, and anyone who can possibly be blamed--except the power plant operators who weren't properly trained or knowledgeable about operating in Island mode. In the limited cases where I could convince "management" to switch one turbine to Isoch mode and let the other turbine(s) run in Droop mode it was shown conclusively that some very complicated and expensive PMSs and Isoch Load Sharing schemes weren't worth the (exorbitant) prices paid for them, and, worse, all of the time (man-months) spent trying to make them work correctly. It just takes proper knowledge and training and some supervision by the operators to work correctly--something that is very difficult to program into some digital control system (especially if the programmers don't understand what they're trying to program).

When the alternator is connected to an infinite grid, the rotor does NOT slip--it is LOCKED into <b>synchronism</b> with the rotating magnetic fields of the generator stator. As the torque input to the generator from the prime mover is increased, the "load angle" between waveforms increases (and decreases as the torque input decreases). To have these load angle changes there is a very slight, momentary increase in acceleration, but the rotor does not slip. If it slipped there would be catastrophic damage; it had better not slip.

When the amount of torque being provided to the generator rotor is exactly equal to the amount required to keep the generator rotor spinning at synchronous speed (which is pretty small) while the generator is connected to an infinite grid the load on the generator will be zero. If the torque being input is decreased from this point the generator will become a motor with current (watts) flowing "into" the stator and keeping the generator rotor spinning at synchronous speed. In this case, the "motorized generator" is providing torque to keep the generator rotor spinning at synchronous speed. The "motorized generator" is making up the difference between the torque required to keep the generator rotor spinning at synchronous speed and the amount being supplied by the prime mover by converting amperes (from other generators and their prime movers on the grid) into torque.

If the torque is increased above the minimum required to keep the generator rotor spinning at synchronous speed with zero load, then current (watts) will flow out of the generator stator to the load. In this case, the torque that would have increased the speed of the generator rotor were it not <b>synchronized</b> to the grid is converted to amperes by the generator and is used to power additional load on the electrical grid.

The governor function of the prime mover control system is controlling the energy being admitted to the prime mover that is being converted to torque and being applied to the generator rotor.

Just about the same thing happens with generator terminal voltage. The AVR controls the excitation that is applied to the windings of the generator rotor to control the generator terminal voltage. If the excitation being applied to the generator rotor windings is exactly equal to the amount required to make the generator terminal voltage equal to grid voltage when connected to an infinite grid then zero VArs will be seen on the generator VAr meter, and the generator's Power Factor meter will read 1.0 (Unity).

If the excitation being applied to the generator rotor windings is decreased below the amount required to keep the generator terminal voltage equal to the grid voltage, then leading reactive current will "flow" in the generator stator windings, the generator VAr meter will move in the Leading direction, and the Power Factor meter will also move in the Leading direction, to some number less than 1.0.

If the excitation being applied to the generator rotor windings is increased above the amount required to keep the generator terminal voltage equal to the grid voltage, then lagging reactive current will "flow" in the generator stator windings, the generator VAr meter will move in the Lagging direction, and the Power Factor meter will also move in the Lagging direction, to some number less than 1.0.

In the same way there is a certain amount of torque required from the prime mover just to keep the generator rotor spinning at synchronous speed at zero load, there is a certain amount of excitation required just to keep the generator terminal voltage equal to grid voltage at zero VArs and Unity Power Factor. If the amount of torque/excitation is reduced below that amount then "less than desirable" things happen (motorizing the generator is not a good thing for some prime movers; Leading Vars are generally considered to be undesirable). If the amount of torque/excitation is increased above that amount then "desirable" things happen (real watts being produced by the generator is desirable and good and generally produces revenue which makes the bean counters happy; some small amount of Lagging VArs are generally considered to be acceptable).

If the generator were simply running at synchronous speed with the generator breaker open (that is, NOT connected to an infinite grid) any increase in torque will cause the speed to increase, and any decrease in torque will cause the speed to decrease. Any increase in excitation will cause the generator terminal voltage to increase, and any decrease in excitation will cause the generator terminal voltage to decrease. When the generator is <b>synchronized</b> to an infinite grid any increase in torque can't really have any appreciable change in grid frequency or prime mover speed, and the difference in torque is converted to amperes flowing "out" of the generator stator. When the unit is <b>synchronized</b> to an infinite grid any increase in excitation will try to increase generator terminal voltage--which is equal to grid voltage--but that increase in excitation can't increase generator terminal by the same amount as when the generator breaker is open so the difference in excitation is converted to Lagging reactive current (Lagging VArs).

The other thread I posted has some information about what happens to the magnetic fields of a synchronous alternator is loaded; it is usually necessary to increase excitation to prevent Leading VArs from exceeding some amount, or to "produce" some Lagging VArs.

And, grid voltage does changes throughout the day, not by much in many locations, but in some locations the variations can be a couple of hundred volts. And as the grid voltage

The grid in your part of the world works the same as the grid in every other part of the world: If the load on the grid remains constant as you <b>synchronize</b> your generator and its prime mover to the grid and start increasing the load on the generator by increasing the fuel (or steam) flowing into the prime mover, the grid frequency will increase. The amount of frequency increase is dependent on the relationship between the change in load from your machine relative to the entire load on the grid--the amount all the other generators are supplying to the grid. On very large, "infinite" grids the amount your generator/prime mover will be adding to the grid will likely be a very small fraction of the total load--which means the increase in frequency will be a very small fraction of the total frequency. But, somewhere someone or some unit operating in Isochronous Speed Control mode (not really likely, but it makes for good theory!) must decrease its power production by an equal amount to keep the grid frequency unchanged.

I hope this helps!

 

Dear CSA,

Thank you very very very much for this explanation, now I have everything clarified. I have finally understood it.

I apologize for my bad understanding once more, it has been quite hard for me to take all these concepts, sorry for making you to write so many replies.

Once again, thank you a lot for helping, it has been very very helpful.

Best regards,
Daniel

 

Daniel Chamorro,

You are most welcome for any help I may have provided.

I congratulate you for being pro-active in your understanding of basic power plant fundamentals. Best of luck! We're always here if you have more questions. We don't always have all the answers, but we have a lot of them.

 

Dear CSA,

I will write a new thread talking about normal control architecture of a generation plant (PMS, AGC...) and how is it interconnected to DCS.

This post was supposed to be about that but, due to my curiosity, we finished it talking about frequency problems.

Thank you very much once again!