Excitation Control

thank you so much.

please can some one explain me about the excitation and avr....and how the avr gets power and about its connections and then about the exciter.
can mail me also on [email protected].

from the basic of avr how it is connected and power and how it control.
 
Dear Sir,

I am owning a 400KW CHP unit powered by Natural Gas. And at Present my Operator is increasing and decreasing Flow rate on KW Load basis. But it has chances of Manual Failures or Fatigue.

So i am searching whether there is an Automatic Valve to control flow rate by giving KW input signal. Any Electronic Controller and specialized valve is used for my Purpose??

Pls Email me to [email protected]
 
Dear All,

It's interesting that this topic poped up.

A client mentioned to me, he uses a genset (400kw) to run a process.
This engine was damaged beyond repair (con rod went through the engine block) and I suspect, its a result of an incorrect AVR controller.

In his rush to get his process up and running, they decided to retro fit and use another engine of similar Hp rating, but was not made for a generator application.(Truck)

I tried and advised against doing this without success.

Contributors, highlight the dangers PLEASE!!
 
You have stated the following :
Fuel is watts, or KW, or MW. Fuel is REAL power.

Excitation is VArs. Excitation is REACTIVE power.

Mr.CSA ,

I do not understand why excitation just effect the Reactive power only , can you explain that using equations.

what I know if now the generator is connected to the GRID it is synchronized with the GRID frequency and Volt (constant V&F) , so increasing the excitation current will increase the stator current and since P & Q are function in Current both of them shall increase not only VARS. Please make it clear for me.

In addition for increasing the speed (fuel rate) how it effect the power and the Volt is constant since the generator is connected to the GRID.
 
mohamed,

There is current, and there is reactive current.

You're on the right track, with P & Q. The power triangle pretty much is all the maths and formula I need. Except for F = (P * N)/120.

I know that when I hold excitation constant and increase the energy flow-rate to the prime mover and the AC synchronous generator is synchronized to a grid with other generators and their prime movers that the speed <b>DOES NOT</b> increase but the amperes flowing in the stator DO increase, and the wattmeter increases and the VArmeter doesn't really move very much.

Yes, it does move, but it's because of the EMFs and counter-EMFs and back-EMFs and interactions between magnetic fields changing.

I also know that when I'm troubleshooting a wildly fluctuating wattmeter the cause is never wildly fluctuating excitation; it's always a wildly fluctuating energy input to the prime mover.

And when I'm troubleshooting a wildly fluctuating VArmeter the cause is never a wildly fluctuating energy input to the prime mover; it's always a wildly fluctuating excitation current/voltage.

I will maintain, without resorting to equations and formulas, that real power, P (watts), is a function of energy flow-rate to the prime mover driving the generator. And that reactive ..., er,... uh,... power (there, I said it! It feels so good!)--reactive power--is a function of excitation.

But, I think the problem with your question is that there is current and there is reactive current. Current is the result of increasing the torque being applied to the generator rotor by the prime mover. Reactive current is the result of increasing the excitation above or below that required to maintain the generator terminal voltage equal to the grid voltage. The two currents are not the same.

And, another problem with your statement/question is that increasing the torque applied by the prime mover to the generator does not increase the speed--other than a very small, instantaneous change in acceleration. And the acceleration rate returns to zero, meaning the frequency remains, for all intents and purposes, constant (on a well-regulated grid).

www.wikipedia.org has lots of formulas and equations and explanations of the power triangle, using P, Q and S, and angles and all manner of other "justification."

I like to think of S as the total amount of energy being produced by the generator (as a consequence of both the energy from the prime mover and the energy from the exciter). S is the sum of real (P) and reactive (Q) power. When reactive power is zero, and P is increased, S increases.

When P is constant and Q increases then S increases.

S changes when either P or Q changes. If both change, S changes.

I don't know how else to explain it in layperson's terms. I'm not a mathematician, or a professor (or a former professor). I'm a technician and a former operator who's always trying to relate the things I learned in university to real life. The texts I read, and the instruction I received, were very misleading.

In hindsight it's possible to understand how the authors and the professor could come to the explanations because they didn't have a lot of real-world experience operating and maintaining and troubleshooting equipment operating with the principles they were trying to explain. A great example is how so many texts and reference materials explain droop by saying the no-load speed is 105%, and the full load speed is 100% for a machine with 5% droop. When the full load speed is really 100%, and the no-load speed is also 100% for a machine with 5% droop.

And I, also, struggle with explaining this to people. I know it works, but I'm not the best at explaining it to others.

It's the same with real and reactive power.
 
A

Anil K Panjani

Quite interesting explanation CSA.

I would like to know if there is any possibility of exciter rotor failure due to problem in excitation system. One of the exciter of frame 7 generator has failed severely during operation and it looks like an explosion has taken place inside the exciter.

Your view on this.

br/anil
 
the concept is simple -

1. when you increase excitation keeping the torque on prime mover constant reactive power changes ,you can analyse by drawing phasers when you increase excitation voltage is increased but its in phase with the second generators voltage so the synchronising current is 90 degree lagging to it because current is (E new - E old)/Xs Xs is synchronising reactance (rs is almost negligible which gives 90 degree lagging current) so current is reactive and so active power remains unchanged.

2. when fuel is increased excitation is constant since speed of prime mover is locked due to synchronisation the generators operating in parallel will share the loads and this can be only possible if E1 and E2 (of two generators) will get displaced by some angle (in earlier case they were in same phase but magnitude wise different here they are magnitude wise same but are displaced by some angle)this angle is very small .draw the resultant in phaser and observe that current is almost in phase with both the e1 and e2 so reactive power will change.
 
Hi CSA,

thanks for your explanations, really clears a lot up. One thing I can't seem to see is when 2 generators are synchronised with each other and sharing the same load, should the currents they are producing be the same if set up with droop control?
 
Hi, disco,

If only two generators are synchronized together and sharing the same load then one generator should be operating in Isochronous speed control and the other should be operating in Droop speed control. In this manner, the Isochronous unit will adjust its power output automatically as load is increased or decreased to keep frequency very close to rated. The Droop unit will not do anything as load changes (automatically it won't do anything) as load changes and the Isochronous unit varies its load to maintain frequency. The amount of load carried by each unit is basically a function of how much load is being carried by the Droop unit.

Here's an example. Suppose the total load is approximately 1.0 MW and the two generator-sets are each rated at 1.0 MW. When only one unit is operating it should be operated in Isochronous speed control to automatically maintain rated frequency as load changes. The second, unit, when synchronized to the first unit should be in Droop speed control when it's generator breaker closes. Let's say at the present time the total load is approximately 0.8 MW, and the Isochronous unit was supplying all of the power and then the second unit was synchronized to the Isochronous unit. As the load on the second unit, which should be operating in Droop speed control, is increased the load on the Isochronous unit will decrease (we are presuming the load is stable at this time and is not changing). So, as the operator increases the load on the Droop unit to 0.1 MW the load on the Isochronous unit will automatically decrease 0.1 MW to 0.7 MW, and as the operator increases the load on the droop unit to 0.2 MW the load on the Isochronous unit will automatically decrease to 0.6 MW. The total load is still 0.8 MW, but the share of the total load being carried by each unit is determined by how the operator decides to split the load--by controlling the load on the Droop unit (yes, the Droop unit--because the Isochronous unit is automatically adjusting its power output as necessary to maintain rated frequency). If the load on the Isochronous unit gets too close zero MW, the operator will need to unload the Droop unit so that the Isochronous unit will trip on reverse power if the total load decreases such that the load on the Isochronous unit dropped below zero MW.

Now let's say the Isochronous unit needs to be shut down for maintenance (an oil- and air filter change, for example). The operator would increase the load on the Droop unit until the load on the Isochronous unit dropped to zero MW, then the operator would open the generator breaker of the Isochronous unit, and quickly switch the governor of the Droop unit to Isochronous so it would automatically adjust its load to maintain rated frequency as load changes.

In this scenario, when one unit is operating in Isochronous speed control and the other is operating in Droop speed control the amount of load on each machine is a function of how much load the operator chooses to put on the Droop unit. If the operator puts 50% of the present total load on the Droop unit, then 50% of the total load will be on the Isochronous unit--and the current outputs of both units will be the same. (Operators cannot change the load on the Isochronous unit by manually adjusting the governor of the Isochronous unit. Isochronous speed control automatically adjusts its governor and the load being carried by the unit to maintain rated speed--as the total load on the system changes. If an operator tries to change the load on the Isochronous unit, what will happen (unless there is some kind of unusual Isochronous load control scheme in use) is that the frequency of the system will change from rated. The load on the Isochronous unit is a function of how much of the total load is being carried by the Droop unit, and how much the total load is changing.)

It is possible to have both turbines in the same condition operating in Droop control--however every time the load changes (every time someone starts or stops a motor, or turns a light on or off, or turns a computer and its monitor on or off) then an operator is going to have to manually change the load of one of the two Droop units in order to maintain rated frequency. Droop speed control doesn't care if the frequency is higher or lower than rated--and by that I mean it doesn't try to automatically adjust its load to maintain rated frequency.

Droop speed control units presume there is a unit operating in Isochronous speed control somewhere on the grid that will adjust its load to maintain rated frequency. (On very large, "infinite" grids, this is not the case; grid operators adjust the loads of one or many Droop units to maintain grid frequency as load changes. Sometimes this is done via some automatic control system; sometimes it's done manually by the grid operators.)

So, if two generator-sets are synchronized together supplying a common load and both are operating in Droop speed control mode, then the operator is the one who has to sense changes in load (when the frequency changes) and adjust the load on one or both units to maintain rated frequency--which is not automatic control at all. When the operator gets the loads on the two units to the point that the frequency is at rated, if the load doesn't change the frequency will remain at rated. But, if the load changes, the frequency will change and the operator will have to change load on one or both units to get the frequency back to rated.

If two generator-sets were synchronized together supplying a common load and both were operating in Droop speed control, it would be possible for the operator to adjust the loads on the two units such that the current being produced by each machine was equal (which would mean the same share of load being carried by each machine: 50% of the present load). But, as soon as a motor is started or stopped, or lights are turned on or off, or computers and computer monitors are turned on or off, the frequency of both machines will change and the load on both machines will change--until the operator makes an adjustment to one or both units to return the frequency to rated. The share of the load on each machine is determined by how the operator adjusts the load on each machine.

Now, some sites use a load-sharing controller/scheme to adjust the loads on multiple units all operating in Droop speed control mode. Why? Probably because someone felt it was simpler than relying on operators to balance loads so the Isochronous unit would not be over- or under-loaded. And, probably because someone (in the purchaser's organization or the plant design organization) had a bad experience with operating an island load with one generator-set operating in Isochronous speed control mode. Isochronous speed control mode can be difficult to tune (if the governors of the generator-set prime movers are not similar). And, it takes some training and experience for operators to understand how to control load on an island without tripping the generator(s) or causing frequency fluctuations--and most operators don't ever get that training, except by experience. And, that usually means bad experience (tripping; frequency fluctuations; etc.).

Does this help?
 
Hi, disco,

There are many descriptions of Droop speed control that use the word "share". Share can be interpreted to mean several different things. In this context, "share" means that units operating in Droop speed control will not try to hog all of the load or give up all of the load when the load changes. If two units are synchronized together and supplying a load they will fight each other to try to maintain frequency--and the fight is VERY ugly, with violent load swings and likely breakers tripping and black-outs. (There are some Isochronous Load Sharing control schemes available but they are really just de-tuned Isochronous units and they require additional communication and control between the units. They work, but usually not very well-and again, they still require human, manual supervision to work well.)

Sharing the load also means that when the load on the system (whether it be one Droop unit or hundreds of Droop units) exceeds the torque being produced by the generator prime movers and the frequency begins to decrease that any Droop unit not operating at its rated power output will pick up part of the load in order to help keep the frequency from spiraling downward (to stabilize the frequency), and the amount of the load they will pick-up is proportional to their rating and to their Droop setpoint. In other words, they will "share" the load change when the frequency changes (decreases or increases) in proportion to their Droop setpoint and the amount of the frequency change. (This is kind a of a difficult concept to explain and to understand without an example, and that can fill a large pamphlet/small book.)

Sharing load (current), again, is kind of a poor term to describe Droop speed control--which is first and foremost a governor mode that permits many generators and their prime movers to stably produce power at a desired frequency to a load that is much larger than any single generator and it's prime mover could provide by itself. Again, two or more units trying to operate in Isochronous speed control when synchronized together (without some kind of Isochronous Load-sharing scheme) will not control frequency very well, and their power outputs will not be very stable or constant (unless the load is very stable and constant). Units operating in Droop speed control will not have such large (violent) load swings; in fact, they are, by definition, producing power at a very stable rate.

It is a side-benefit of Droop speed control, that as frequency begins to drift from rated that it will change the power output in a manner that tends to help stabilize and support grid frequency from spiraling out of control (low or high)--until such times as operator(s) somewhere make the appropriate changes to one or more Droop units to return the system frequency to rated.

So, be very careful to understand exactly how the word "share" is being used when trying to explain Droop speed control.

Again, the most important aspect of Droop speed control is that it allows multiple units to participate in supplying power to a load that is much larger than any single unit could supply by itself--and do so in a stable and controlled manner. This is opposed to what happens when two or more Isochronous speed control units are synchronized together (without some form of Isochronous Load-sharing--which is not ever fully automatic and requires additional communication and control). AC power systems operate at desired frequencies, and since generator speed, and hence prime mover speed, is proportional to frequency the frequency can be sensed and controlled by monitoring speed.

At the present time, there are really only two modes of governor control for generator prime movers: Isochronous and Droop, both modes of speed control (and, again, frequency and speed are directly related). And only one of them is the mode that allows multiple generators to "share" in providing power to a much larger load than any single generator could provide by itself without load and/or frequency excursions: Droop speed control. The alternative, Isochronous speed control, doesn't allow multiple generators to be synchronized together and stably "share" in providing power to large load.

There are side-benefits to using Droop speed control, but the primary one is that it allows multiple generators and their prime movers to be synchronized together, acting as one generator, to power a load that is much larger than any single generator and its prime mover could supply by itself. And do so in a very stable and controlled fashion--which Isochronous speed control isn't capable of without external communications and control schemes.
 
<b>CORRECTION:</b>

> If two units are synchronized together and supplying a load they will fight each other to try
> to maintain frequency--and the fight is VERY ugly, with violent load swings and
> likely breakers tripping and black-outs.

It should have read:

If two <b>Isochronous</b> units are synchronized together and supplying a load they will fight each other to try to maintain frequency--and the fight is VERY ugly, with violent (large) load swings and likely breakers tripping and black-outs.

Again, in the power generation industry there are really only two modes of operation: Isochronous speed control and Droop speed control. Speed control is critical because AC power systems are supposed to operate at a particular frequency, and speed and frequency are directly related. And without some special control communications and schemes and de-tuning multiple generators-sets using Isochronous speed control is not well-suited for large or "infinite" systems. Droop speed control is the preferred method for allowing multiple generator-sets to be synchronized together and stably participate in supplying large loads.
 
Thanks for the info. Very much appreciated. I am just trying to get my head around it all. We have an issue at the moment when running 2 gensets in parallel we are getting blackouts when running running them on full load. They are operated in Droop speed control and the voltages and frequency don't change but the current in one seems to always be a lot higher than the other and I couldn't explain why their currents were different if they were supposed to be load sharing. (I assumed they would share 50% of the load each).
 
disco,

I'm always curious when I hear people say their islanded units are always operated in parallel in Droop mode with no unit in Isoch mode, or when they say their islanded units are always operated in parallel in Isoch mode. The only way this could occur is if there is some kind of external or interconnected control scheme between the two governors, or if the load is very stable. For one example, use your preferred Internet search engine and look for "Woodward DSLC". You should find some information about an external control system that can control multiple generator-sets operating in Isochronous control.

Because, unless there is some kind of control scheme for either of the above scenarios which "supervises" the generator-sets and balances load while maintaining frequency, it's pretty hard to understand how simple governors could do so without frequency excursions and a lot of operator adjustments.

It's a rather common misconception, actually, that two similar or identical generator sets will equally share the load when paralleled together and supplying a small "island" load (independent of a larger grid and other generators and their prime movers). Again, the only "communication" every governor shares with every other governor is speed--which is directly proportional to frequency on synchronous AC machines. Something has to tell them to change their energy flow-rates in order to "balance" (equally share) the total load. That could even be a human operator, presuming the load wasn't changing very rapidly.

The unit with the higher current is supplying more power to the total load. And if that is causing the prime mover to be running at full rated power output then it's conceivable that the unit could be tripping on excessive power, and that overloads the remaining generator resulting in a blackout.

My guess is that the one generator with the higher current is definitely at or near it's rating, and that when additional motors or lights or computer and computer monitors are started/turned on the one machine goes into overload and that starts the blackout.

Some operator, or some automatic control system, needs to be adjusting the load to more equally balance the loads on the two so that an increase in load doesn't result in a blackout. On two machines running in Droop with no external control scheme that can be a tricky thing to do while maintaining frequency.

And, that's the part that really piques my curiosity--when you (and others) say the frequency is stable. When the load is stable, I would say that's probably true for two simple governors operating in parallel in Droop mode. But, when the load changes, the frequency isn't going to be at rated, and it may not be very stable, either. If you want good control of frequency with two generator-sets operating in parallel to power a load independent of a larger grid then one of them should be in Isochronous mode--but someone, or some control system, needs to be continually adjusting the load on the Droop machine to make sure the Isochronous machine from reaching maximum, and from reaching minimum, too.

There's just something that we don't understand about the configuration of the units at your site. But, I can definitely say that without some other "intervention" two similar generator-sets will not automatically equally share load. Someone or something has to do that--either a human or a control system programmed by a human which is sending signals to both generator-set governors.

Hope you can write back with more details!
 
One more question:

where is the limit point between Generator terminals and grid?

The other day, by increasing excitation, we detected voltage increased in MV auxiliary bus-bar.

Can anyone explain this matter, as I thought the point where aux. transformer is located is constant voltage (grid voltage)?

best regards.
 
One more answer:

You did not say how much you say this MV auxiliary bus-bar voltage change. 10V? 100V 1000V?

What was the pf of the generator at the time of this incident? What was the reactive current value (MVars)? What was the load (MW)?

Some sites are more able to have an effect on grid voltage than others. Some can have no appreciable effect at all; others can have a profound effect. The factors are many and include distance from nearest generator; size of generator in relation to nearest generator(s); reactance of transmission lines and transformers. Even the load characteristics can cause changes in the ability of a generator to effect grid voltage; at some time of the day the load may be nearly resistive, while at other times it may be highly inductive or somewhat capacitive in nature.

AC power systems are typically explained in terms of ideal systems, but rarely do they actually follow ideal characteristics. This actually happens a lot: When things are first noticed, they are considered to be abnormal. Or, more often, when control systems are upgraded or modified to display new/additional information all of a sudden the refrain is, "That's never happened before!" when, in fact, it was happening all along, but it wasn't visible/displayed or being paid attention to previously.
 
One more QUESTION:

My question is that: if torque on prime mover increases so as current increases in stator winding, so as stator magnetic field will try to go ahead rotor magnetic field, which is not allowed in alternator.

Hence when we open governor for more steam admission to have increased the load what exactly controls the two fields (ROTOR and STATOR Magnetic field) to be in intact position. Do we increase the excitation gradually according to increased load to maintain the terminal voltage? because when torque increases terminal voltage gets down which undesirable operation.
 
QUESTIONs are good; doubts are not.

I suggest you look at some YouTube videos about synchronous generators, or consult a site such as www.wikipedia.org for some videos or pictures of synchronous generator construction and operation.

The stator (also called the armature) consists of windings inserted into slots--and they are not movable. However because of the nature of alternating current, as it flows through the stator windings it creates magnetic fields that "rotate" around the stator. But, they are not "movable" and the rate of rotation is fixed by the frequency of the alternating current.

In a synchronous motor or generator, the rotor is another magnetic field and as we all know a North pole is attracted to a South pole and a South pole is attracted to a North pole. So, as the stator magnetic fields rotate the rotor magnetic fields "follow" them--and they are locked, synchronized, with the stator magnetic fields. As long as the torque being applied doesn't exceed the strength of magnetic attractions (which can be because the torque is too high, or because the magnetic attractions are too weak--usually because of low excitation).

So, the stator (armature) magnetic field "rotation" is fixed by the frequency, and the rotor magnetic fields are synchronized (locked) into the same speed of rotation because of magnetic attraction--again, as long as the torque/magnetic attraction isn't overwhelmed.

As the energy flow-rate into the prime mover increases the amount of torque being produced increases. However, because the rotor magnetic fields arelocked into synchronism with the stator magnetic fields the rotor (and the prime mover) can't spin any faster--and the generator converts the torque into amperes to power loads (motors; lights; computers and computer monitors).

Here's where some contention has occurred at control.com. As we all know, as the amount of current flowing through windings increases the strength of the magnetic field of the winding increases. As the stator (armature) current increases as the torque applied by the prime mover increases the stator magnetic field strength increases. If the rotor magnetic field strength remains unchanged what will happen is that the stator magnetic field strength will start to "shrink" the rotor magnetic field strength, and this will cause the generator terminal voltage to decrease and this will affect the generator power factor and reactive current flow. So, to keep the generator terminal voltage constant as stator current increases it's necessary to increase rotor field strength--and to do that it's necessary to increase excitation.

Hope this helps!
 
Shubhal,

We are talking about Synchronous generators (and not about asynchronous generator) here. Stator and Rotor magnetic fields are virtually "locked" with each other and rotates at generator frequency. When this two fields are not in "locked" position, a condition called "Pole slipping" occurs and it is not good for the machine. To keep this two fields in "locked" condition, we do increase the field current with increase in generator load and vice-versa. Actually this process of excitation control is done by AVR (Automatic Voltage Regulator)and the operator doesn't have to worry much.

More help on this may be provided by Phil Corso, CSA and other MVPs.(There is also a concept called "load angle" which we've not discussed)

Hope this helps!
 
many thanks.

It was a wonderful explanation to a very difficult concept in the simplest possible way.
 
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