Generator Load Sharing

B

Thread Starter

bspace321

Hi all

I've been researching for days about synchronous generators and cannot get my head around how real power output of generators can be adjusted when paralleled to the grid or to each other.

I'm across the reactive power side of things, increasing terminal voltage adjusts amount of reactive power absorbed/produced by the generator (i.e. terminal voltage via excitation increased implies producing VARs and decreased implies absorbing VARs) and I understand how generators operate when connected on their own (i.e. load placed onto generator creates opposing force to slow down prime mover, reducing generator output frequency, more fuel is added to prime mover then generator output frequency restores to nominal).

What I don't understand is how do you control the amount of real power the generator produces, when connected to the grid or in parallel with another generator.

My understanding so far is follows (correct me if I'm wrong):

Let's start with the generator output CB open. Generator is started, rotor is excited by DC voltage. Fuel is added to the prime mover and the prime mover begins to spin. As the prime mover spins, a magnetic field is induced in the stator windings and a generator terminal voltage is produced (the generator is currently unloaded). Synch checks are done to ensure stator output frequency, phase and voltage are the same as the grid.

Generator CB is then closed onto the grid (which is just a whole bunch of other generators). The grid induces a voltage back onto the rotor and hence rotor will slow down. Fuel is added to the prime mover to bring the rotor back up to nominal speed, the same way it would if a resistive load was placed onto it.

Now the prime mover is receiving enough fuel to spin whilst connected to the grid, but as I understand it no power is delivered to the grid yet.

More fuel is added to the prime mover and this is where I am lost. If we add more fuel to the prime mover, does it not begin to accelerate creating a gap between the stator magnetic field (from the grid) and the rotor magnetic field? If this is the case, then the rotor will be phase shifted from the stator magnetic field? Looking at the two wave forms, you would have the grid waveform at nominal frequency and the rotor induced waveform phase shifted by this 'gap'.

If there is a phase shift, let's assume it is 90deg, as I've read that 90deg equates to full load output of the generator. Then won't the connected load see the grid voltage plus the induced voltage from the rotor? Adding two phase shifted waveforms would result in higher RMS voltage across the load? This is bad?

Sorry I'm probably way off here, but thought I could get some help understanding what is going on as it's driving me crazy.
 
The thing about AC power generation is that when two or more (or two hundred or two thousand or more) synchronous generators are <b><i>synchronized</b></i> together on a grid no generator can spin faster or slower than any other generator based on the construction of the generator. There's this little formula that relates speed and frequency as follows:<pre> F = (P * N)/120
where F=Frequency (in Hz)
P=Number of poles of generator
N=Speed of generator rotor (in RPM)</pre>You can solve the formula for speed or frequency by rearranging the terms based on algebraic principals. But, basically, the formula related speed and frequency.

When multiple generators are synchronized together, it's the two magnetic fields inside each generator that keep the rotors locked into synchronous speed per the formula above. ALL generators operate at their synchronous speed. For a 50 Hz grid, a two-pole synchronous generator will operate at 3000 RPM; a four-pole generator will operate at 1500 RPM, and so on based on the number of poles.

One, or six, or sixteen or sixty synchronous generators synchronized to a 50 Hz grid with other generators can run at 51.2 Hz, or 49.6 Hz. They all have to run at 50 Hz.

When additional energy flows into the prime mover driving the generator it would seem logical that the prime mover and generator would increase speed--but it can't. The two magnetic fields inside every synchronous generator prevent the generator rotor from spinning any faster or slower than its synchronous speed (based on the number of poles of the generator rotor). And, the generator converts that additional torque into amperes.

And the formula for 3-phase electrical power is:<pre> P = Vt * Ia * 3^0.5 * PF
where P=Watts
Vt=Generator Terminal Voltage
Ia=Generator Stator Amperes
3^0.5=square root of 3 (1.732)
PF=Power Factor</pre>Generators run at a fairly constant terminal voltage, so that term can be considered to be fixed. And, the square root of 3 never changes, so that term is fixed. And, if for the purposes of this discussion, we consider the PF of a generator output to be 1.0 (resistive), it is also fixed. That means to produce more power the generator stator amperes have to increase. And, that's what a generator does--it converts torque from the prime mover to amperes. In exactly the same way that an electric motor converts amperes into torque. And generator drive motors.

What happens in an electrical generation and distribution system is that a generator converts torque into amperes, which are then transmitted and distributed to various locations via wires, and then motors convert the amperes back into torque. It's as simple as that.

The additional torque being provided to the generator rotor by the generator's prime mover that would tend to increase the generator's speed is converted into amperes because the generator speed can't increase when it is synchronized to a grid with other generators.

Conversely, when the generator prime mover produces less torque and the generator rotor would tend to slow down--but it can't when it's synchronized to a grid with other generators--causes the generator to produce fewer amperes, which means the electrical power output of the generator decreases.

These are AC power generation fundamentals. When synchronous generators are synchronized to a grid with other synchronous generators, all the generator spin at speeds which are proportional to their construction (number of generator rotor poles). And, when the torque being provided to a generator rotor increases--which would tend to increase the generator rotor speed--the generator, which can't speed up (or slow down) converts the torque to amperes. More torque means more amperes; less torque means less amperes.

If the amount of torque being provided to the generator rotor by the prime mover is not sufficient to keep the generator rotor spinning at its synchronous speed then amperes flow into the generator from the grid to keep it spinning at its synchronous speed. That's called reverse power, and most generator rotor prime movers don't like to be spun by the generator, so protective relays open the generator breaker to protect the prime mover.

Other than the above, most of your understanding is basically okay (except for the part about the generator slowing after initial synchronization and the prime mover having to be sped up). Once the breaker closes the speed of the generator rotor--and the prime mover driving the generator rotor--is fixed by the frequency of the grid with which the generator is synchronized. Period. Full stop. It's can't go faster or slower than its synchronous speed. Period. Full stop.

Generators convert torque to amperes.

Motors convert amperes to torque.

Wires are used to transmit torque from generators to motors.

And the speed of synchronous generator rotors is directly proportional to the frequency of the grid they are synchronized to.

Think about it. On a properly regulated grid with stable frequency, every device connected to the grid sees the same frequency--both loads (motors, etc.) and generators. It has to be. If generators could spin at any speed, why would it be necessary to synchronize them with such sophisticated equipment? Why not just connect the generator to the grid at any speed?

Hope this helps!
 
So, as has been proven and said many times in the past, I'm NOT the best proof-reader of my own writing.

<b>>>CORRECTON<<</b>
One, or six, or sixteen or sixty synchronous generators synchronized to a 50 Hz grid with other generators can run at 51.2 Hz, or 49.6 Hz.

The above sentence SHOULD HAVE BEEN WRITTEN TO SAY:

One, or six, or sixteen or sixty synchronous generators synchronized to a 50 Hz grid with other generators <b>CANNOT</b> run at 51.2 Hz, or 49.6 Hz.

My sincere apologies for any confusion.

All generators run at their synchronous speeds (based on the number of poles of the generator rotor) when synchronized to a grid with other generators. The two magnetic fields inside each generator FORCE them to act as ONE SINGLE LARGE generator, supplying one single large load (the total of all the motors and televisions and tea kettles and lights and computers and computer monitors). There can only be ONE frequency for all the generators, and for all the load(s).

It is patently false for textbooks and references to say that synchronous generators slow down as load increases. It just doesn't happen in the real world. And by load increasing, I'm referring to the amount of power being produced by a generator and its prime mover.

Watch the speed (and frequency) of the synchronous generator(s) at your site or ship as it(they) are loaded or unloaded after they are synchronized to a grid with other generators. Unless the grid is small, you will not see any appreciable change in speed (or frequency) unless you have a highly accurate tachometer and/or frequency meter. And, on a well-regulated grid the frequency should stay relatively constant--because AC power is transmitted best when the frequency is at or near rated. And devices work best when the frequency of the grid they are connected to is at or near rated.
 
G

G.A.abobaker

Hi Mr. CSA,

The statement was a little bit confusing but it was Ok. in fact i have another question. which is, if i need to start a isolated (independent) power plant (say 50 MVA seam turbine) using (temporarily) the national grid (infinite bus), and then to put all the loads of that isolated system on the steam generator. how can i share the load between these two power sources? and how can i increase the loads of the steam turbine to eventually take the all loads and to get rid of the other source (national grid) and finally isolate it?

what would make the loads being withdrew from steam generator while the grid still exist?

many thanks for your detailed explanation.
 
G.A.abobaker,

I can say the same thing; your question is a little bit confusing but I will try to answer as best I can.

Here's what I think you're trying to ask. You have a transmission and distribution system that is capable of powering a load independently of an infinite grid at some point in time. The load is being powered by the national grid when the steam turbine-generator power plant is being started, and the auxiliary loads of the power plant are also being powered by the national grid when the power plant is being started.

When the steam turbine-generator reaches rated speed, it would then need to be synchronized to the national grid. AND, at some point the auxiliary power supply to the steam turbine-generator power plant has to be switched from the national grid to the steam turbine-generator. There would likely be a momentary interruption of power as the switching of the auxiliary power is made from the national grid to the steam turbine-generator output depending on how much time the transfer requires (though it could be done in less than one second with the proper switchgear), and this is going to require some dedicated switchgear and protection to accomplish. (There will have to be a "tap" off the steam turbine-generator output--likely before the generator breaker--that would be used to provide the auxiliary power for the power plant AFTER the auxiliary power supply from the national grid to the power plant was opened.)

There will need to be some kind of method of determining, approximately, the amount of load which is to be supplied by the steam turbine-generator power plant when it is separated from the national grid. This amount will have to include the auxiliary load of the steam turbine-generator power plant. The steam turbine-generator will have to be loaded up to equal this amount of power while still synchronized to the national grid in anticipation of separating from the national grid.

Once the steam turbine-generator is loaded up to the amount of the load to be powered by the steam turbine-generator independent of the national grid PLUS the amount of the auxiliary load of the steam turbine-generator power plant, the power plant AND the load to be powered by the plant independent of the national grid must be separated from the national grid (again through dedicated switchgear).

Now, the steam turbine-generator will be powering the load to be powered independently of the national grid PLUS it's own auxiliary power load, and at approximately the right level (MW) and at approximately the correct frequency. At this point, the steam turbine governor should be switched from Droop Speed Control to Isochronous Speed Control--so that any changes in load (either the load being powered independently of the national grid OR the auxiliary load of the power plant) will be handled automatically by the steam turbine generator WHILE maintaining the desired frequency.

That's about it--if I understand the question correctly.

Now, if the steam turbine-generator power plant needs to be shut down for any reason WITHOUT interrupting the power to the load being powered by the plant, it will first be necessary to re-synchronize the steam turbine-generator <b>and it's load(s)</b> to the national grid. (Usually, the steam turbine governor would be switched back to Droop Speed Control immediately prior to re-synchronizing the unit with the national grid--or it would have to be very quickly switched back to Droop Speed Control immediately after re-synchronizing to the national grid to avoid instability of the steam turbine-generator output (load)).

Once re-synchronized to the national grid the load on the steam turbine-generator can be reduced to approximately zero, and then the generator breaker can be opened. The national grid will be providing the power to the load which was being powered by the steam turbine-generator independently of the national grid, BUT the steam turbine generator will still be supplying the auxiliary load of the steam turbine-generator power plant.

At this point, the steam turbine-generator power plant auxiliary power supply will have to be switched over to the national grid (by opening the steam turbine-generator auxiliary power supply breaker and closing the national grid auxiliary power supply breaker--which will cause a momentary interruption in power to the power plant auxiliaries depending on how long the transfer requires). At that point, the power plant can then be shut down using national grid power.

Now, without understanding exactly how your "plant" is powered and connected to the national grid it's extremely difficult to say any more. It would take some "special," dedicated switchgear to accomplish the above, and probably even more to accomplish something other than the above. And, that switchgear would likely have to include multiple synchronization circuits (one to synchronize the steam turbine generator to national grid, and one to re-synchronize the steam turbine-generator back to the national grid to avoid blacking-out the load being powered independently of the national grid when trying to take the steam turbine-generator and its power plant off-line in a controlled and orderly fashion without causing disruption to the load).

I hope I've understood the question correctly, and if I haven't I hope you will read and re-read the information and apply it to your situation because the circumstances you described were incomplete at best and it would probably take a LOT of back-and-forth to answer your specific question or situation (if there even is a real situation and this isn't just a what-if scenario which hasn't really been properly thought-through). I does the best I can with what I was given to work with--which wasn't very much in the way of detail and seems to have made several assumptions which I've had to try to fill in.

It's also made more difficult because what you should be providing is what's called a one-line diagram of the electrical system at the "plant" which would make it much easier to provide specific details about which breakers to open and close when.

Hope this helps! I'm sure it's not the exact details you were expecting, but then there wasn't enough specific information to go on.
 
Many thanks Mr. CSA about explanation.

>Hope this helps! I'm sure it's not the exact details you
>were expecting, but then there wasn't enough specific
>information to go on.

You are right. i didn't give you enough details.

The idea is to start up a power plant supplying chemical plant. the island power system consists of Gas turbine and steam turbine. gas turbine originally intended for starting up. unfortunately gas turbine under emergency maintenance. to start up the steam turbine separate power source needed to start up steam boiler. solution is to connect national grid to that power island (in the same switch gear). then to start the steam turbine, synchronized it with national grid and then put loads on steam turbine. laterally to isolated the national grid.
 
Hi CSA,

Your above explanation have cleared most of my doubts.
But I would like to know about the role and function of AVR system. My understanding is that its function is to vary the field current in rotor to produce more or less excitation when ever the terminal voltage increases or decreases. As you explained above, if the terminal voltage of generator remains constant once it is synchronized, then what is the purpose of AVR?

Kindly clarify.

<b>Moderator's Note:</b> There have been multiple threads on AVR and excitation on control.com. I suggest you search are archives for information. For directions on formatting search options, click the Question mark (?) next to the Search Box. Just a note, three letter acronyms like AVR all by themselves don't work when you search. You need to add additional terms such as, +excitation +AVR in the search field.

If you don't feel your question is adequately addressed, try responding to one of the related posts with a request for more specific information.
 
esdauto18,

If you haven't tried the Search feature of control.com, it's fast. The syntax of search terms was well explained by the Nice Moderator, and there is Help available, as well.

So, the generators usually driven by GE-design heavy duty gas turbines are synchronous generators (as opposed to non-synchronous generators). Technically they are really called alternators, but nobody uses that term any more.

Synchronous generators use a rotating magnetic field to produce the generator terminal voltage. Under most conditions, you are correct: The generator terminal voltage is constant. (Most generators can only change the generator terminal voltage by approximately plus- or minus 5% of nameplate rating.) However, during any given day the grid voltage may, and usually does, change as the types of loads on the grid change (the number of induction (non-synchronous) motors, mostly--which are used for refrigerators, air conditioners, fans, pumps (some VERY large water pumps for irrigation districts and water treatment facilities (fresh water and sewage water, etc.). Even the number of fluorescent lights can have an effect grid voltage in some parts of the world. So, even if the watts (real power) being produced by the generator set stays relatively constant during the day, the reactive current (also known as VArs, Volt-Amperes Reactive) can, and usually does, change.

You have asked about AVRs (not VArs, AVRs--isn't this fun?!?!?!) in another thread. The purpose of an AVR is to keep the generator terminal voltage at a setpoint. Most generator set operators don't realize they are changing a generator terminal voltage setpoint when they are making an adjustment using the AVR, but that's what's actually happening as they watch the VAr or pf (power factor) meter when making the AVR adjustment. So, the AVR is trying to keep the generator terminal voltage constant (at the setpoint) as the grid voltage is changing.

To vary synchronous generator terminal voltage (since the synchronous generator is always running at a constant speed to produce a stable, and constant frequency--regardless of the amount of load being carried by the generator) one varies the amount of DC (Direct Current) current applied to the rotating generator field. The rotating generator field is a one or more conductors wrapped multiple times around the length of the rotor--these are called windings. (There are rotor windings, and there are stator, or stationary, windings. Only DC is applied to the rotor windings, and that produces voltage in the stator windings as the rotor is being turned by the prime mover. You can find all kinds of videos and references to how AC is produced by using your preferred World Wide Web search engine.)

Another thing that happens is that as the amount of real power (watts) increases the amount of amperes flowing in the stator (the stationary part of the synchronous generator) increases. And this causes the strength of the magnetic field of the stator to increase (more amperes flowing through a fixed number of turns of a conductor (the stator windings) causes the resultant magnetic field to increase). This stationary magnetic field reacts with the rotating magnetic field of the generator rotor and causes the rotating magnetic field strength to decrease somewhat. If the rotor field strength is reduced, then the generator terminal voltage will also be reduced.

Tying this all together, if the amount of DC current (called "excitation") being applied to a synchronous generator rotor is exactly equal to the amount required to make the generator's terminal voltage exactly equal to the voltage of the grid at that moment in time the amount of reactive power (VArs) will be zero (0). And the power factor will be "1" (also known as "unity power factor"). If the synchronous generator terminal voltage is less than the grid voltage at any moment then leading VArs (reactive current) will start flowing in the synchronous generator's stator windings (along with the real amperes associated with the watts being produced by the synchronous generator). And, if the synchronous generator terminal voltage is greater than the grid voltage at any moment there will be lagging VArs (reactive current) flowing in the synchronous generator's stator windings.

Most power plants that are synchronized to grids want to produce as few VArs as possible (minimal reactive current). That's because they don't usually get paid for producing VArs--only for producing watts. ALSO, too many leading VArs are generally not good for synchronous generators (causes unwanted heat in the windings, which can damage insulation). AND, if the excitation being applied to the synchronous generator rotor by the AVR (the exciter, or the excitation control system) is too small then serious mechanical damage can occur to the generator, the coupling between the generator and the prime mover, and even the prime mover (it's called "slipping a pole"--and it's VERY bad).

Most synchronous generators are capable of producing much more lagging reactive current (usually referred to as "positive VArs") than leading reactive current (usually referred to as "negative VArs"). To do this, the excitation control system (the AVR, or the exciter) has to be capable of producing lots of DC current (and voltage) to be applied to the generator rotor. Too much lagging reactive current though can also produce unwanted heat in a synchronous generator, so this too has to be limited under normal operating conditions.

There are many ways to produce the DC to be applied to the synchronous generator rotor windings. But, the AVR, or the excitation control system, or the exciter, is how that DC current (and voltage) is controlled and limited and held stable--to produce stable generator terminal voltage, whether that generator terminal voltage is equal to the grid voltage, or less than the grid voltage or greater than the grid voltage.

To sum up, the AVR is generally used to control the reactive current of a synchronous generator. If the excitation being supplied by the AVR is exactly equal to the amount required to make the generator terminal voltage equal to the grid voltage, then zero (0) reactive current will be flowing in the generator's stator windings. (That's good.) However, if anything happens that causes the synchronous generator's terminal voltage to be less than the grid voltage (either the operator reduces the AVR setpoint, or the operator increases the amount of watts being produced by the generator, or the grid voltage increases because of load changes on the grid) then there will be leading (negative) reactive current flowing in the generator. Too much leading reactive current is not good (causes unwanted heating in the generator).

OR, if something happens to cause the synchronous generator's terminal voltage to be greater than the grid voltage (either the operator increases the AVR setpoint, or the operator reduces the amount of watts being produced by the generator, or the grid voltage decreases because of load changes on the grid) then there will be lagging (positive) reactive current flowing in the generator. And excessive lagging reactive current is also not good (causes unwanted heating in the generator).

So, the AVR, is used to control the direction and amount of reactive current. It's also used during synchronization to make the synchronous generator's terminal voltage at least equal to or, usually, slightly greater than, the grid voltage (so that either zero reactive current or a small amount of reactive current will be flowing immediately after synchronization). The AVR controls the amount of DC current (and voltage) being applied to the synchronous generator's rotor windings--and that affects the strength of the generator rotor's magnetic field, which affects the magnitude of the generator's terminal voltage, which can affect the reactive current of the generator.

Now, all this talk about generator terminal voltage versus grid voltage can be confusing. In general, when a synchronous generator is synchronized to a grid with many other generators the two voltages are generally considered to be equal. BUT, if you have a voltmeter (or two of them, one for the generator terminal voltage and one for the grid voltage) with enough resolution (which most don't have) you can see changes of tens or hundreds of volts as excitation is varied. But, most displays or voltmeters only show one value of voltage, and that is okay. It's really the relative difference between the two that affects the reactive current flow, and that can be measured in tens or hundreds of volts with a high resolution means. We're not exactly interested in the actual value of generator terminal voltage versus grid voltage--EXCEPT during synchronization, and then the difference IS important!--we're really interested in the amount of reactive current flow (which is relative to the difference in voltages). And, so that's why the operator doesn't usually (almost never in most cases) look at the generator terminal voltage meter when making AVR adjustments--they only look at the VAr meter or the power factor meter and adjust the AVR output to make the VAr meter or the power factor meter equal to the desired value.

As a very important aside, the watts being produced by a synchronous generator are a function of the energy flow-rate into the generator's prime mover. And, the VArs (the reactive current) being "produced" (or "consumed") by a synchronous generator is a function of the amount of excitation applied to the generator rotor windings by the AVR.

Isn't this fun???!!!?!?!

Hope this helps! I know it's a lot--but, it's all intertwined and it's all important. Notice I didn't use any maths; I generally try not to. I prefer to describe what the maths can predict or be used to analyze. But, what's happening is more important than the maths--again, the maths can be used to predict or analyze what's happening. We need to what's supposed to happen when, and why. And how.

Welcome to control.com. The Speedtronic (Mark*) turbine control community has been very active here for almost 15 years (I think)!. We thank the Moderators, the host, and the sponsors for keeping this site going and on track (though sometimes some of us stray--I'm one of them who tends to editorialize once in a while; sorry!).

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Again, welcome. And, don't be afraid to share your experiences when someone posts for help or information and you have a relevant experience or knowledge!!!
 
thank you for your explanations, we (it lest me) noticing how much care you take to your sentences to make it full of meaning. although the terms reactive power (VAr) still not so clear as much as the active (wattage). I myself still have to feel the difficulty when ever try to imagine the reactive power. I didn't work in generator fields. Although that I worked as an electric construction man in area of generation and high yards, have installed panels and wiring in GE generators control room. but I would be more self confident if i had hold the knob of the control. as you said if a drawing or diagrams could be attached to the explanation would be very helpful.

many thanks again
 
Thanks for the kind words. I'm going to try to keep this as "simple" as possible--and I'm really only offering you a way of thinking about reactive power: VArs. It's my own analogy--a way of describing something that is difficult to describe. A way of trying to understand something that is difficult to understand. My analogy is NOT technically correct--but is just an attempt at trying to understand what a "VAr" is and what it "does" and how it is "produced" and "consumed."

The majority of electric loads on a transmission and distribution system are electric motors--driving things like air conditioner compressors; air conditioner blowers (fans); refrigerator compressors; freezer compressors; water pumps (fresh water, and sewage water); fans; elevator motors; crane motors; you name it. And, there are two basic types of AC (Alternating Current) motors: Synchronous and Induction. And, the most common type of motor used for just about every application above is an induction motor--which doesn't have any slip-rings or brushes.

Induction motors rely on the phenomenon of induction to create a magnetic field on the motor's rotor, and that magnetic field is attracted to a magnetic field which is created when alternating current flows in the stator windings (the stationary windings of the induction motor). And it's that reaction between the two magnetic fields that results in the rotation of the motor's rotor--which is how alternating current (amperes) gets converted into torque, which is what air conditioning compressors and blowers, and water pumps, and crane hoists, and elevator sheaves, etc., need to do work (make us or our beverages cold; make water flow under pressure; lift boxes or people; etc.).

In my analogy, it's the act of inducing that second magnetic field in the rotor of an induction motor that "consumes" VArs (Volt-Amperes Reactive--or, reactive power). If we think of VArs as being produced and consumed, just as Watts are produced (by generators) and consumed (by electric motors, and lights, and computers and computer monitors, and televisions, and tea kettles), then you can sort of understand what a VAr is. Remember: this is just an analogy--however, thinking of VArs as being produced and consumed can be very beneficial. (Many people like to think of electricity as flowing water. The water pressure is like voltage, and the flow-rate of water is like amperes. That's another analogy.)

Now, the whole "real" power versus "reactive" power thing. Real power is something we can "see" and it's generally considered tangible ("real")--it's expressed in horsepower (originally). And reactive power is generally something we can't "see" and is considered intangible ("not real")--except that it is real in the sense that without it induction electric motors wouldn't turn. And, since induction electric motors are the overwhelmingly most common type of motors in use around the world (they are the least expensive and easiest type of electric motor to build and operate!) we would have to use more expensive electric motors that require more maintenance and repair. VArs don't "move mass a certain distance in a specific time period" (the definition of a horsepower!)--but they make it possible for induction electric motors to do that.

So, although it's just an analogy--try to think of VArs as just like Watts: They are "consumed" and "produced." They are "consumed" by induction electric motors to create the necessary second magnetic field on the motor's rotor to make the rotor turn. And, they can be "produced" by alternating current synchronous electric generators.

Many HMIs refer to leading VArs at the generator terminal as "negative" VArs, and generally, leading VArs are considered to be "flowing into" the generator from the grid. Lagging VArs at the generator terminal are "positive" VArs, and generally, lagging VArs are considered to be "flowing out" of the generator on to the grid. (There's a saying: Lagging VArs "feed" a lagging load. (The quotation marks are mine.))

Hope this helps! Again--it's just my analogy. It's technically incorrect (as VArs are really MUCH more than that), but it's a way that help me (at least) understand and think about VArs.
 
I'm presuming I understood ghidan's question(s)--perhaps I didn't, and he gave the 'Thumbs Down' to my previous response. If that's the case, ghidan, can you please clarify your question(s) so I can try again?

If it was someone other than ghidan who clicked on 'Thumbs Down' can you tell what it was about the analogy that you didn't like? How can one explain VArs without vectors and sine waves and maths? And how does using vectors and sine waves and maths explain what VArs "do"?

Because electric motors (and fluorescent lights) cause shifts between the voltage and current sine waves of an AC (Alternating Current) transmission and distribution, and left unaddressed the shift can be very bad for the customers of and the operators of the transmission and distribution system--not to mention the generators synchronized to the transmission and distribution system.

How does one describe that without drawings and graphs?

Isn't a VAr a way of expressing what's causing the shift between the voltage- and current sine waves? Or of expressing the magnitude of what's causing the shift between the sine waves? Isn't the magnitude of the shift related directly to the magnitude of the number of reactive amperes flowing in the system?

Real Power: Volts multiplied by Amperes (when the voltage- and current sine waves are in phase with each other)--such as in a purely resistive load (an incandescent lamp; the heating element in a tea kettle)

Reactive Power: Volts multiplied by Amperes which are NOT in phase with each other--such as in a load with reactance, which can be either inductive or capacitive in nature (think of an induction electric motor; or a fluorescent light fixture)

Reactive power results when a portion of the current flowing through a reactive component is returned to the system on the alternate portion of the current sine wave flowing through the reactive component. So, reactive power flows back and forth without doing any real ("mechanical") work. (That's real descriptive without drawings and vectors and graphs and maths.)

I read that reactive power is just AC power that flows back and forth in a power system--but doesn't do any real work (it doesn't move any mass any distance in any particular time period). (Also, real descriptive, wouldn't you say?)

Another World Wide Web site says, "Reactive power is a necessary evil for induction machines"--that is, induction electric motors (as well as transformers). With which I whole-heartedly agree--but which also isn't very descriptive.

Here's a youTube video (some parts of the world can't access this site):


But, does any of that really explain what a VAr is? Or does? VArs are calculated by mutiplying the magnitude of the voltage and current sine waves at some point in an AC power system at any instant in time. If the two sine waves are in phase with each other, then the load is purely resistive and only real power (Watts) flows in the circuit. But, if the load has either capacitance or inductance (or a predominance of one or the other), the product of the out of phase sine waves at any instant in time at any point in the AC power system is called VArs (Volt-Amperes Reactive).

But, I still ask: How does that explain what a VAr "is" or "does"? Can't we just agree that VArs are the way to calculate or express the effect of inductive and/or capacitive loads on the system? And, by extension can't we agree that VArs are "consumed" (because they are a necessary evil for induction electric motors--the overwhelming majority of the loads on an AC systm)?

What hasn't been said is that, left unchecked, if too many induction electric motors (air conditioner compressors and fans; refrigerators; etc.) are connected to the grid at any one time then bad things start happening to the grid. And, so, grid operators have to have a way of countering the inductive loads and they typically do that by changing the excitation of synchronous electric generators. They can also use fixed capacitors, but they are variable--they can only be switched in or switched out (and when the switching occurs if you're standing near the capacitor banks, usually, there is a big "thud" (a dull, low bang) that can be felt. Sometimes the high tension (voltage) lines (wires) will actually move ("swing" or "shake") when large capacitor banks are being switched in or out (on or off).

So, can't we agree that VArs can be "produced" to counter the effects of the VArs being consumed. Can't we all agree on those two things?

If not, I'm extremely keen to hear how someone else can explain VArs. Simply, and succinctly. Without being able to use drawings and graphs and maths.

Thanks!
 
ghidan,

Let's try a slightly different approach.... I'm not trying to describe what VArs "are"--I'm trying to describe what VArs do. Or, the effect of VArs on the system. The effect is to shift the voltage and current sine waves out of phase with each other (on an AC power system there are BOTH voltage and current sine waves, both at whatever the system frequency is (50 Hz or 60 Hz)). So, what VArs do is to shift the voltage and current sine waves out of phase with each other. And, one kind of VAr can offset the other kind of VAr.

I guess that's not the same as what a VAr is--but, for me at least--if I can understand what something does or how it affects other parameters I can usually begin to understand what something is, especially when it's an intangible thing, like reactive current is. There's no real physical way we visualize VArs, except maybe for the heating they cause; but that's not generally they way they are quantified. And just to say it's current flowing back and forth in a system that doesn't do any work (lifting or pumping or whatever) doesn't really describe it either.

You should be able to use your preferred World Wide Web search engine and the term "Volt Ampere Reactive" to find lots of different explanations, most probably better than mine because many include drawings and such.

Finally, we can't use drawings or charts or graphs in the threads on control.com. It's a security thing, and, we have to respect the owners and Moderators of the website and their desire to protect themselves--and us!!! My wife says engineers can't talk without a paper and pencil (to draw and make graphs and lists), and I'm certainly a good example of that, though I try with my responses on control.com, and that's why they get so wordy sometimes--at least that's my excuse and I'm sticking to it!
 
Dear Sir,

your reply are so much helpful

I have one doubt still in my present plant

2 no's 20MVA, 33/11kv transformers are connected cement plant load. both transformers are under parallel operation on secondary side (11KV) which is load center. load sharing of the these 2 transformers are different 70% (8MW) and 30%(4MW) respectively. Now, we added a steam generator (11KV) output 9MW to same load center by one extension panel.

Then how the Generator load sharing will effect on transformers load calculation?
 
Breddy...
Most of the original forum-topic was related to different loading of generators, i.e., different Power (Watts) and different Reactive Volt-Amperes (VAr) !
Your question is based on what is called an Optimum-Power-Arrangement, or OPA, i.e, 3 generators, having different capacities, all connected to the same 11-kV load-bus ! And, presumably, some of the power generated is transferred to a 33-kV load-bus, perhaps a grid connection, via two like capacity 11/33-kV Xfmrs !
An OPA is an elaborate and complicated study involving performance and efficiency of each electrical component ! Thus, I suggest you re-post your question as a new forum-topic.
Regards, Phil Corso
 
Another thing that happens is that as the amount of real power (watts) increases the amount of amperes flowing in the stator (the stationary part of the synchronous generator) increases. And this causes the strength of the magnetic field of the stator to increase (more amperes flowing through a fixed number of turns of a conductor (the stator windings) causes the resultant magnetic field to increase). This stationary magnetic field reacts with the rotating magnetic field of the generator rotor and causes the rotating magnetic field strength to decrease somewhat. If the rotor field strength is reduced, then the generator terminal voltage will also be reduced.
So is it safe to say that excitation and governor controls are not independent in practical operation? Also what happens in the stator and rotor magnetic fields if the reactive power is increased but the watts are unchanged?
 
Selk,

There's increasing LEADING and increasing LAGGING VArs.... This explanation presumes the generator is synchronized to a grid with other generators and their prime movers.

In the case of increasing leading VArs the excitation being applied to the generator rotor is reduced, which reduces the heat being generated by the current flow in the rotor windings. Decreasing the excitation too much can (should) lead to an under-excitation alarm, and if increased further to an under-excitation trip (or Loss of Field trip). When the magnetic strength of the rotor field gets decreased too much there can also be stator end-turn heating issues, but the biggest fear is weakening the rotor field so much that the rotor actually "jumps" due to the torque being applied to it by the prime mover. When this happens it's called 'slipping a pole' and it can lead to catastrophic failure of the rotor and coupling between the generator and the prime mover. It's not a good thing; not at all. It's the interaction between the two magnetic fields in the generator that keep the generator locked into the same frequency (speed) as the system with which it is connected (a grid). The other thing that happens when excitation is reduced is that it tries to "buck" (reduce) the system/grid voltage, which is sometimes not good for system/grid stability.

In the case of increasing lagging VArs the excitation being applied to the generator rotor is increased, which increases the amount of current flowing in the rotor windings which increases the heat of the generator rotor windings. This also causes the generator to try to "boost" (increase) the system/grid voltage, which is sometimes not good for system grid stability. It also somewhat weaken the stator winding field strength, but not usually by much.

One has to remember that a generator's nameplate rating is based on how much heat can be removed (transferred) from the generator windings (stator AND field) in order to not cause problems with the insulation of the windings, and for the stator end-turns as well. There are magnetic field distortions of the two magnetic fields present in any synchronous generator caused by excessively increasing or decreasing the rotor field current but as long as they aren't too excessive and don't last for too long and there's no lack of cooling then everything should be alright.

But, remember, VArs can be increased in either the leading or lagging direction.

The power factor of a generator is a measure of the efficiency of the generator at producing real power--watts, kW, MW. The more VArs a generator produces tends to reduce the amount of watts/kW/MW that can be generated, especially since in most cases (for larger generators) the excitation power actually comes from the generator terminals, either voltage or current. Some generators "redirect" power applied to the generator rotor from the prime mover to produce excitation current, which also somewhat reduces the real power which can be produced as excitation is increased.

I'm encouraged to see you seem to be searching the archives of Control.com for more information! There is a LOT of information here and many questions have been asked and answered many times. Keep reading! If you have questions (not doubts--questions) we are here to help.
 
Thanks a ton for your efforts on this forum! It is really helpful to me and others. For me, I'm Just making a slow progress on understanding of Generator operation.
 
Selk,

To answer your other question, it is correct (and safe) to say that excitation and governor controls do interact with each other. Generally, they are separate systems BUT usually to make it easier for operators the ability to change excitation is included on the same HMI display as the governor controls (the ability to change how much real power (kW; MW) is being carried (produced by) the generator.

If a generator and its prime mover are synchronized to a larger system/grid--which involves "matching" generator terminal voltage to grid voltage during the synchronization process--and the generator is loaded (by increasing the energy flow-rate into the prime mover using the governor controls) BUT the operator DOES NOT make any further adjustments to the excitation system what will happen is that as the real load (kW; MW) on the generator increases the reactive current flow of the generator will usually increase in the Leading (negative) direction. Why? Because as the current flowing in the synchronous generator's stator windings increases (which increases the strength of the stator winding magnetic field) it tends to collapse or weaken the magnetic field of the generator rotor--so the generator terminal voltage will decrease below the system/grid voltage. This causes reactive current to flow into the generator from the system/grid.

So, what happens, usually, is the operator has a certain power factor (which is another way of expressing reactive current versus real power (I have to be very careful here when talking about real power and reactive "power")) which is to be maintained. So, as the generator is loaded (using the governor controls) the operator will probably be making small adjustments to the excitation to maintain the desired power factor. This will most likely be to increase excitation to strengthen the rotor magnetic field so that the generator terminal voltage remains equal to or slightly above the system/grid voltage and reactive current flow is either zero VArs or slightly Lagging (positive) which means the generator is "producing" reactive current and sending it out to the system/grid.

SOME prime mover-generator control schemes will actually do this for the operator--keep the power factor at some desired setpoint as the prime mover energy flow-rate is increased. Some plants have a way to set a power factor and have either the governor or the excitation control system (the AVR is it's often called) adjust excitation to maintain that setpoint (the setpoint can either be VArs, Leading or Lagging, or power factor, Leading or Lagging), though many system/grid operators either frown on using VAr- or Power Factor Control these days or forbid it entirely (as it can make system/grid disturbances worse--just as Pre-Selected Load Control can make system/grid instability worse).

Here's another way to think about AC power generation. The generator has to be brought up to rated speed and the speed (frequency) of the generator has to be made to be equal to or just slightly greater than system/grid frequency during synchronization. (Usually, the generator frequency (speed) is made just slightly higher than system/grid frequency so that when the generator breaker is closed the extra energy flowing into the generator prime mover gets converted to real power by the generator which means that real power will flow out of the generator and on to the system grid. Yes; when the generator breaker closes the generator--and the prime mover driving it--will slow down by whatever amount it was above the system/grid frequency (for GE turbine control systems that's usually around 0.3% of rated speed/frequency--which isn't very much, but it can result in a real power of as much as 2-5 MW depending on the machine and how the controls are tuned). BUT that's the ONLY time the generator speed changes AS LONG AS THE GENERATOR BREAKER REMAINS CLOSED AND THE SYSTEM/GRID FREQUENCY IS STABLE. So, this textbook crap about synchronous generators slowing down as load is increased is ... crap.

What happens when, while the generator breaker is closed, the amount of energy flowing into the prime mover drops below the amount require to maintain rated speed (also called synchronous speed) of the generator? Well, in that case real current (amperes) flows INTO the generator and it actually becomes a motor--yes, a motor. This is called "reverse power" and is also referred to as "motorizing the generator." And the speed of the generator and the prime mover driving it will remain at that determined by the frequency of the grid!!! It doesn't slow down when the energy flow-rate into the prime mover drops below that required to maintain synchronous speed--it remains at synchronous speed because it's synchronized to the system/grid, drawing power from the grid to remain at synchronous speed. (And, because the generator becomes a motor it is actually spinning the prime mover at this point--which some prime movers DO NOT tolerate very well (steam turbines; reciprocating engines don't like to be spun by the generator; gas turbines are not so affected by being spun by the generator).)

During synchronization generator terminal voltage is adjusted when the prime mover and generator are at/near rated speed. And, just like the prime mover speed is usually made slightly higher than grid frequency (speed) the generator terminal voltage is usually made equal to or slightly higher than system/grid voltage. When the generator breaker closes this means that reactive current will either be positive or zero VARs, which is desirable (just as positive watts/kW/MW are desirable at the time of synchronization). When excitation is made exactly equal to system/grid voltage there will be zero VArs flowing into or out of the generator (that's "unity" power factor, or 1.0 power factor). If excitation is increased from this condition reactive current (VArs) will begin to flow out of the generator (positive VArs). In this condition the generator is said to be "boosting" the system/grid voltage (increasing the system/grid voltage). Conversely, if excitation is decreases from this condition reactive current (VArs) will begin to flow into the generator (negative VArs). In this condition the generator is said to be "bucking" the system/grid voltage (decreasing the system/grid voltage).

So, in many respects it's possible to consider real power and reactive power as similar. If the energy flow-rate into the prime mover is exactly equal to that required to spin the generator at the same speed (frequency) as the system/grid frequency which the generator is synchronized to the real power flow will be zero (watts; kW; MW) as indicated by the generator stator amperes. Increasing the energy flow-rate into the prime mover DOES NOT result in increasing the speed of the prime mover or the generator it is driving--it DOES result in an increase of amperes flowing out of the generator onto the system/grid. Decreasing the energy flow-rate from this zero If the excitation is exactly equat to that required to make the generator terminal voltage exactly equal to system/grid voltage the reactive current will be zero (VArs). Increasing the excitation flowing in the generator rotor, while is does result in a generator terminal voltage increase it DOES NOT result in the same increase as when the generator breaker is open and the machine is running at rated speed. It DOES result in an increase of reactive current (VArs) flowing out of the generator onto the system/grid.

And, remember: A generator converts torque (from the prime mover) into amperes. Just a motor converts amperes into torque. Electricity is the medium used to transmit torque from a place where it is abundant or produced to places where it can be used to do work (pump water; drive refrigeration compressors and fans; etc.). And do so using wires. Instead of building torque producing machines everywhere they are needed.

Pretty cool, huh?

It's all pretty much about F=(P*N)/120, which is explained above and in many threads on Control.com. An AC system/grid is supposed to run at a relatively constant frequency, and EVERY synchronous generator synchronized to that system/grid runs at its synchronous speed, because of the magnetic forces inside the generator. As the system/grid frequency goes up or down, so does the frequency (speed) of all the generators (and their prime movers) synchronized to that system/grid. All because of magnetism.

Even cooler, huh?

There's all kinds of mathematical formulae which can be used to explain and predict the above--but they don't really explain, in real world terms, what is really happening in a generator and the prime mover driving it, especially when the generator is synchronized to a system/grid with other generators and their prime movers. Isochronous Speed Control is one method to control system/grid frequency; it used to be the ONLY automatic method--and it's still the best method--but people HAVE TO UNDERSTAND AC power generation for it to have a chance of working properly. Droop Speed Control is how multiple generators and their prime movers can work together to stably power a load (loadS) greater than any single generator and its prime mover could ever power. It's NOT the job of the Droop machines to control frequency--they do, and can, assist with supporting grid frequency during a frequency disturbance but it's not their primary job to control frequency. That's either the Isoch machine's job, or the system/grid operators jobs to properly respond to a grid frequency disturbance and return the grid frequency to normal.
 
Although this response was more about islanded power plant operation, it may be of help in understanding how Droop Speed Control works. While I hesitate to mention this on this forum, Droop Speed Control is proportional control--there is no "reset" or "integral" action to speak of. (Yes; GE uses a form of Droop Speed Control that has an inner integral loop (they call it "Constant-Settable Droop"--a really poor name for the function is performs), but in reality it's still primarily proportional control. Not many people know about PID and proportional control. Especially machine operators.)

Parallel Operation of Generators in Island mode- Droop/Isochronous | Automation & Control Engineering Forum

The question often comes up, "Why do we still use Droop Speed Control? It's OLD technology!" Well, because it's been around since the "birth" of AC power generation and there are thousands of machines around the world that use it and it's actually very ingenious and simple. (I know; it doesn't seem simple to a lot of people, but it really is--once one gets past all the mythology and misperceptions about it.)

Since there are SO many machines using Droop Speed Control when new machines are developed and added to grids it's easier to continue using Droop Speed Control so that all the machines on the system/grid use the same load-sharing method. Instead of trying to force companies and owners to retrofit their machines to be compatible with newer machines and newer technology. There's a saying, "If it ain't broke--don't fix it!" Droop Speed Control is really absolutely ingenious and super simple--REALLY!

When AC power generation was being "birthed" there was NO WAY to get the load of the generator (watts; kW; MW) into the control systems used at that time. Most of them were "links and levers and springs", there wasn't hydraulics and of course there wasn't even analog electronics to speak of. How does one get amperes and watts/kW/MW into a links and levers system? (Not easily.) Since the most important aspect of any AC power generation, transmission and distribution system is stable frequency, and since frequency is directly related to speed (F=(P*N)/120) and every governor (control system) could recognize speed and respond to speed changes the natural progression was to develop a method that relates speed and load. Droop Speed Control does that. And, since EVERY machine synchronized to a system/grid of any size knows how to recognize speed and changes in speed using a system that relates speed and load makes all the machines alike. And as was said, multiple generators connected to a system/grid all act as one generator running at the speeds that are directly related to frequency--which is so important to keep stable. In this way, by connecting multiple generators and their prime movers together (synchronizing them!) a system can drive a much larger load (loads, actually, since they all seem like one load to the system/grid) than any single generator could power by itself. But, to do that there must be a way for all those generators synchronized together to stably (without oscillation and without improperly responding to changes in the load(s) on the system), and Droop Speed Control is that method. And, it is all done with speed and a speed reference that is related to load. All the governors, from 140 year-old governors to super-sophisticated digital microprocessor-based electronic turbine control systems using the same method means they can all "play nice" together.

You may have heard of 4% Droop regulation, or 5% Droop regulation. That means that when the machine's speed reference is increased (while the generator breaker is closed and synchronized to a well-regulated grid) to either 4% or 5% that the machine's output will be at or very near the nameplate rating of the prime mover. It also means that, for machines with 4% Droop regulation, every 1% change (out of a total of 4%) in the machine's speed reference results in a 25% change in the load of the machine. (For machines with 5% regulation, every 1% change (out of a total of 5%) in the machine's speed reference results in a 20% change in the machine's load.) That's for loading and unloading. (Of course, if the same amount of energy was flowing into the prime mover as with a 101% speed reference while the generator breaker was open the prime mover would probably trip on overspeed.... Remember, it's just a way of relating speed and load when the generator breaker is closed.)

Droop Speed Control compares the actual prime mover speed when the generator breaker is closed to the machine's speed reference, and calculates the energy flow-rate into the prime mover based on the difference between the two "speeds" (the actual speed and the speed reference). For a machine with 4% Droop regulation, an increase of the machine's speed reference from 101% to 102% would mean the load would increase from 25% of prime mover nameplate rating to 50% of prime mover nameplate rating.

So, what happens, as can be seen from the above paragraph, increasing the machine speed reference above 100% speed (which should correspond to the machine's synchronous speed--the speed directly related to the frequency of the system/grid the generator is synchronized to) the load of the machine will increase. So, what's happening, in essence, is that the machine is being told ("commanded") to go faster. BUT, because the generator breaker is closed the machine CAN'T go any faster than the speed directly related to the system/grid frequency because of the magnetic forces inside the generator (the rotor magnetic field and the stator magnetic field). So, the generator does what it does: It converts torque (the torque from the increased energy flow-rate into the prime that's being applied to the generator rotor) into amperes. (And all of this occurs at a relatively stable (constant) voltage because of the AVR trying to maintain the generator terminal voltage equal to the terminal voltage setpoint.) So, increasing the machine speed reference DOES NOT cause the machine speed to increase, but IT CAUSES the load being carried by the machine to increase (because synchronous generators convert torque to amperes).

So, in the opinion of many of my colleagues--and myself--as well as a former contributor to Control.com the term "droop" comes from the fact that the actual turbine speed doesn't increase, it lags the speed reference, or, it "droops" below the speed reference. And that's how it works. It's proportional control, proportional speed control.

The formula for Droop Speed Control basically is this:

Energy flow-rate into prime mover=((Actual machine speed - Machine speed reference)*Gain)+Offset

The gain and offset are fixed values (meaning they are not variables). The offset is the amount of energy flow-rate that equals synchronous speed of the prime mover and generator. And the gain, well, that's calculated using the Droop regulation percentage. (ALL of this has been covered several times on Control.com by CSA.)

What does this mean? It means that instead of one variable (machine speed reference) there are two variables (*machine speed reference AND actual speed). Because the actual speed--which should be a relatively stable value because the system/grid frequency should be stable--can change when the system/grid frequency deviates from normal. So, under normal operating conditions the actual speed is stable and relatively constant, BUT when the grid frequency deviates from normal that cause the error between the actual speed and the speed reference to change which changes the energy flow-rate into the prime mover. This is the (very important) second feature of Droop Speed Control

To sum up (because I know you're waiting for this!), Droop Speed Control is proportional speed control, which means the frequency of the system/grid and the frequency of the generator ARE NOT it's job to control. Droop Speed Control is how multiple machines stably share the load--because when the machine speed reference is stable (not changing) and the actual speed is stable (not changing--which is what systems/grids stive for, stable, rated frequency) the difference between the two is stable (not changing). Changing the machine speed reference (which DOESN'T chage the actual speed!) changes the difference between the actual speed and the machine speed reference which changes the energy flow-rate into the machine's prime mover which changes the power output of the generator.

And, when the actual speed does change because the system/grid frequency changes well then the energy flow-rate into the prime mover will change.

That's what and how Droop Speed Control works and what it does. Remember: It's about the difference between the actual machine speed and the machine's speed reference. Changing the machine's speed reference when the actual speed is stable and constant (which it SHOULD BE on a well-regulated system/grid) changes the energy flow-rate into the machine's prime mover. When the load is stable--because the actual machine speed and the machine speed reference is stable--and the grid frequency changes, the energy flow-rate into the machine changes. Two variables instead of one. That makes it more difficult for most people to understand. And leads to a lot of misunderstandings and misperceptions. And the way many textbooks and reference books describe Droop Speed Control leads to even MORE misunderstandings and misperceptions.
 
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