Isochronous governor "fighting"

I heard that when there are more than two isochronous governors operates in parallel, there will occur the "fighting".
Many people said that it caused by different speed settings.
But, I wonder how about the different valves, engine time constant of different PI gain effect to the "fighting" except different speed settings?

Is there anyone who can kindly reply to my question?
And how can I find some documents that deal with these issues?
 
JunHyeok,

So, you are going to design a system where multiple units can be operated in parallel with each other (synchronized together) in Isochronous Speed Control? Let me know how that works out for you, okay?

You might try looking for information using the search term "Isochronous Load Sharing" or "Isochronous Standby." But, you need to be REALLY careful when reading information about Droop and Isochronous speed control because most of it was written by academics and professors with little or no real operational, hands-on experience and they fail (hugely) to properly state operating conditions when attempting (feebly) to describe them. Want a typical example? Without any qualifying statements or information about the status of the system/grid MOST every description of what happens when a Droop machine is loaded says: "The speed of the Droop machine decreases in proportion to the amount of Droop of the prime mover as load is applied to the generator." Well, that just ISN'T what happens on a well-regulated grid of any size (small or large). If it were, the frequency of the voltage coming out of the wall at your home or place of business or where you shop or exercise would be all over the place (and it is in some parts of the world--but that's another story for another time).

Who are these people you are listening to? What is their experience? You can have two generator sets (prime movers and generators) that were built (assembled) one right after the other, and both installed and commissioned by the same persons, both with exactly the same rating burning the same fuel (or steam from the same source) and both with the same percentage of Droop and PI control parameters for Isoch with the same prime mover governor synchronized on the same bus with each other--and if they are both in Isoch control they are going to fight each other. The speed settings of both machines should be 100%--because that's what the frequency should be. But, they will fight each other. MANY people have tried to de-tune the Isoch control parameters to allow two such units to be operated in parallel with each other but haven't had much luck. And, when the prime movers are different and the governors are different--that's even more difficult.

What happens when two alpha people are both put in charge of a project without some division of responsiblity agreed to be everyone involved? Two Isoch machines synchronized together is pretty much just like that--they both want to be "in control." Without some kind of over-riding method of deciding who will respond to frequency changes and when and for how long, the two Isoch units are simply going to fight each other to try to maintain frequency--and the results are going to be very ugly, quite often resulting in a black-out.

Sure, you can detune the PI regulators of Isoch machines to make them not so "aggressive" for certain operating conditions, but when you need one or both to respond in a grid disturbance they probably are going to disappoint you--and everyone connected to that grid.

Again, be very wary of what you read with regard to Droop and Isoch speed control. Be even more wary of explanations from people who have little or no operational, hands-on experience with units actually providing power to a grid (large or small). Listen to what people say, and read what people write, but think long and hard and very critically about what you are hearing and reading, consider the source(s), and if you still want to pursue this endeavour--good luck. Yes; people are going to tell you, "It's been done successfully before!" Ask them where and when and for contact information. And, then dig a little deeper and see how that site and those units respond under different conditions--frequency disturbances of different magnitudes and durations. I think you'll be very surprised, indeed.
 
CSA,

Thank you for your fast and kind reply.
I'm also worried about what you mentioned in the above paragraphs.

Now, I have tried to design the isochronous governor controls working in parallel.
Obviously, I'm in academics and don't have any hands-on experience. I designed the frequency compensation process for removing the "fight" circumstance and finished the hardware in the simulation. Of course, it cannot be sure 100% in the real grids but I have to do it for the project.

Anyway, I thought that in the steady-state condition only the different speed setting occurs the "fighting", many different factors such as valve, engine time constants, and generator parameters "of course" effect on the different transient response of the power responded to frequency but not the steady-state.
Hence, I tried to find the materials which handle this issue, but they which I previously searched did not mention the details about it. They just mentioned that different speed setting can occur the "fighting".
 
JunHyeok,

We're talking about AC (Alternating Current) power generation, right?

When a unit (or two, in your theoretical case) is generating power, what is the speed setting? Because in all the machines I have worked on the speed setting is 100%. Sometimes, there is a small deadband or hysteresis of, say, +/-0.17%, so the allowable speed range is 99.83% to 100.17%. If the load on the Isoch unit causes the actual speed to decrease below 99.83% or above 100.17%, then the control system will increase the energy flow-rate into the prime mover to increase the speed or decrease the energy flow-rate into the prime mover to decrease the speed, as appropriate.

You need to be more specific about "speed settings" if this isn't what you're talking about. I have been at power plants with identical units (prime movers and generators) with identical control systems with identical "speed settings" (control parameters) and when some unexperienced manager or director insists that two units be synchronized together, both in Isochronous Speed Control Mode, and watched the two units, sometimes with only a couple of megawatts of load each, start swinging the load back and forth between each other, becoming very violent swings with both units going into reverse power at opposite times, until one or both units trip--usually either on under- or over-frequency or reverse power. And, the manager or director deems the test to have failed.

Academics and mathematics are great things for predicting what usually happens. But, what happens in the real world at power plants when two units are operated in Isochronous Speed Control mode--even with the same "speed settings"--is a very unstable frequency and load, and usually a loss of AC power and black-out. It just doesn't work that way in the real world. Maybe if you have an extremely stable load, and a lot of luck--but it would like not be reproducible.

That's just the way it works.
 
When more than one isochronous speed systems is operated in parallel, they generally have load sharing lines connected from governor of one engine to the governor of the other engine to share load equally.
 
And, sir, would you consider such an application to be "Isochronous Speed Control"? (I wouldn't as it involves a load signals being shared between engines along with other required logic and sequencing. True Droop Speed Control and Isochronous Speed Control relies on speed (frequency) for operation with no other signals or shared controls.

That's one of (the many) beauties of AC power generation speed control: No extra signals or wires required. Everything is done using speed--and since every generator runs at its synchronous speed which directly proportional to frequency, it doesn't get much simpler! Seriously--think about it: For more than a century now prime mover governors from strictly mechanical assemblies (fly-ball governors), to links-and-levers, to analog hydraulic to digital hydraulic to digital servo systems have all been able to be synchronized to the same grid with over various and sundry types of prime mover governors--all without the use of protocol converters and extra signals and wiring. It was all done with speed, which is directly proportional to frequency.

Pretty damn amazing, and about as simple as it gets. Eh?
 
Thank you for your reply.

Yes, AC right. my "speed setting" means the frequency reference setting.

I thought that any other parameters such as generator parameters, valve actuator and engine time constant will affect the dynamic responses of the frequency and power change, but they won't cause the fighting in the steady-state.

In my opinion, the only things that affect the "fighting" are frequency measurement error and the frequency reference setting.

Summarize, I know multiple isochronous governors operation in parallel is really unstable in real power system. It may cause the "fighting".
but, my question is what parameters are really effected on the "fighting". My opinion is different PI gains, valve actuator and engine time constant will not be effected if the frequency reference and measurement setting is perfectly accurate (even if it cannot be in real power system).

p.s) how can I find the materials related to standards of the frequency allowable deadband in isochronous governors?


I really appreciate your reply.
Thank You.
 
JunHyeok,

Opinions are like ... Well, let's not go there, eh?

All of the things you are referring to will likely have some effect on frequency deviation--the extent to which the frequency will vary during a disturbance, or when loaded.

I see you are simply concentrating on steady-state conditions--and I would imagine that if the load were stable it would be possible to have two units synchronized together both operating in Isoch Speed Control mode and not have too much fighting. But, what happens when one starts a motor, or turns on a light or turns off a motor or a light--which is what happens on a real dynamic AC power system--of any size?

I'm not trying to argue with you, or belittle your efforts. I'm just trying to point out that it's virtually impossible to operate two (or more) synchronous generators in parallel with their prime mover governors both in Isochronous Speed Control--without some kind of auxiliary signals being shared between the prime mover governors or some kind of external load/frequency control. Which would mean that Isochronous Speed Control had been de-tuned to allow external load control of some sort.

I would suggest that if you are doing some kind of academic project you have only just begun your research for factors affecting governor operation--which includes valve timing, valve actuator slew rate, gains, etc.
 
CSA,

Maybe there are some misunderstandings about my opinions.
My research is about the auxiliary controls for the parallel operation of isochronous governor.

My exact question is :

When the load changes (such as starts a motor, turns on a light), the multiple governors are trying to main the frequency to 100%. Of course, different valve timing, actuate slew rate, gains, and ... etc will affect the different dynamic responses of each governors. However, (in my thought) the frequency and the active power of the generators can be reached to steady-state without "fighting" if the frequency measurements and references are exactly well-tuned - by proposed method.

Is it wrong?
I'm really welcome of your feedback and discussion.
Thank You
 
CSA,

Maybe there are some misunderstandings about my opinions.
My research is about the auxiliary controls for the parallel operation of isochronous governor.

My exact question is :

When the load changes (such as starts a motor, turns on a light), the multiple governors are trying to main the frequency to 100%. Of course, different valve timing, actuate slew rate, gains, and ... etc will affect the different dynamic responses of each governors. However, (in my thought) the frequency and the active power of the generators can be reached to steady-state without "fighting" if the frequency measurements and references are exactly well-tuned - by proposed method.

Is it wrong?
I'm really welcome of your feedback and discussion.
Thank You

Good day to all,

JunHyeok,

After i have read this thread, I would like to add some comments regarding isochronous governor "fighting" as its the subject of your post.

I think also as CSA told you and expalined :
" fighting" governor in isochronous mode is a subject that can be more practical than theoretical.

Without getting offensing your works and practice on the subject, With my own experience i think that isochronous mode should be aborded and studied in case by case , as utilities and factories like cemnetey, or other aluminium smelters....
have their own power system design and capabilities like island mode...

One shoudl also be aware that in case of governor fighting in isochronous mode , there also will be power/ferquency swinging, MW or MVAR ACCORDING again to the facility, and so you will have operations /selectivity of numericals protection both form bus utility or bus generator(s) according to the case that controls systems are facing .

Since generator can also go to underexcitation limits/trips settings or under/overfrequency sometimes .
Reverse power is not excluded for sure !

About the idea of having 2 generators in isochronous mode ,For sure that can be modelized and studied as you trying to do , and you can use sort of Matlab or labview to simulate some cases but but my thinking is that one should clearly try to establish the differents scenarios and states/cases or extra cases that may be unpredictables for the named utility.


As CSA said the reality can not always be predicted in power generation by simualtes some cases in such softwares.

When you working in the field , you can be facing more cases and sometimes abnormal cases than you think..


Because sometimes people who were designing the plant didnt take in account some "extra cases" from utilities as i mentionned above and then conducting to misunderstanding and more by customer and so the engineers like us have to manage to get the plant and the utilities getting working smoother and with customer satisfaction for what he ordered and paid for !

There is a nice example of isochronous mode in the forum called "reverse power isochronous " i guess you can read that one and sure you will get of what is an extra cases/unpredictible case like aux lube oil pump tripping that can be a mess after according to the author but still now We did not get his last statement, I have responded to the author but till now no response.....


Also i find your idea good and need more investigations ,
Hope this can be an help ,
James
 
CSA,

Maybe there are some misunderstandings about my opinions.
My research is about the auxiliary controls for the parallel operation of isochronous governor.

My exact question is :

When the load changes (such as starts a motor, turns on a light), the multiple governors are trying to main the frequency to 100%. Of course, different valve timing, actuate slew rate, gains, and ... etc will affect the different dynamic responses of each governors. However, (in my thought) the frequency and the active power of the generators can be reached to steady-state without "fighting" if the frequency measurements and references are exactly well-tuned - by proposed method.

Is it wrong?
I'm really welcome of your feedback and discussion.
Thank You


Well it can be reached without "fighting"...but there has to be some way of letting the governors of the prime mover's to know of what is to be done..in other words there has to be full communication between governors.
I will share a bit of my experience with isochronous controllers. Wartsila has been doing this from a very long time....with governor controllers which are now obsolete like the woodward 721 plus controller..where the input is just speed.,..and there is a load sharing line which is connected to other governor controllers.It is basically a bias signal...if there is any mismatch in speed from the rated speed, a DC voltage originates on the load sharing lines and a small direct current starts to flow until the gensets are balanced...The PI gain controller of the governor controller is a variable gain controller which is proportional to the bias signal. Now this sort of thing was done way back maybe some 15-18 years ago. In many old wartsila power plants this is still present as it gave a very stable isochronous control.
After that came some advanced governor controller like the woodward 2301A series which also measured the active load of gensets along with the speed and developed similar bias signals. When gensets are to be controlled in isochronous mode, the load of each gensets are measured and fed back to governor controller for a much more precise control. It also employs similar bias signals which were to be terminated to other governor controllers. The load shared is always proportional to the individual genset's rated power. For ex. if there are two gensets one of 4MW(Gen 1) and other of 6MW (Gen 2) and sudden load of 5MW comes, then Gen1 will take 2 MW and Gen 2 will take 3 MW.
Now in newer power plants and for marine applications, wartsila developed a new patented system with motorola called the UNIC automation as woodward stopped supporting for legacy governor controllers. For the load sharing part, it employs can bus over which load sharing commands are deployed. Here the greatest power gen becomes the master and all other smaller gensets follow its frequency, just old stories being said and done in new ways.
In other words if more than one generator is to be run in isochronous mode( although not isochronous in the truest of sense), but still looks isochronous (LOL), there has to be some way of doing the load sharing and letting individual governors know of what is to be done otherwise motoring of gensets and blackouts will occur...
For references you can study the user manual of the governor controllers as mentioned in the post..maybe you will find something which tickles your mind.
 
JunHyeok,

I'm not sure what ControlsGuy25 is trying to say, and I like what udshred said: "In other words if more than one generator set is to be run in isochronous mode( although not isochronous in the truest of sense), but still looks isochronous (LOL), there has to be some way of doing the load sharing and letting individual governors know of what is to be done otherwise motoring of gensets and blackouts will occur... " This is the essence of what it takes to operate multiple gensets in Isochronous Speed Control mode at the same time.
I also believe that if you have a read of the Woodward and Wartsila governor controller manuals you will find more information--though I'm not a huge fan of the way Woodward describes Droop and Isochronous--lots of unspoken conditions and academic thinking mixed in. Their controllers can be made to work with multiple governors in Isoch at the same time, but, as was said: it's not Isoch in the truest sense. It's really load sharing and Isoch standby--sort of.
I believe (sort of) that we are getting to the crux of the problem here: "...My research is about the auxiliary controls for the parallel operation of isochronous governor. ..." We don't know, because you (JunHyeok) haven't told, what exactly your proposal/paper is about. What exactly does "... auxiliary controls for the parallel operation of isochronous governor. ..." mean? Are you talking about an external controller which sends signals to the two Isochronous governors to share load in a stable manner? Because is that really Isochronous control? I say not; apparently you say otherwise.
In my personal opinion, operating multiple genset governors in Isochronous Speed Control mode when synchronized together supplying a load (loads) using an external controller is not Isochronous Speed Control. In fact, I would submit that if the external controller were to suffer a problem and be unable to send signals to the gensets it is monitoring and controlling that the frequency of the grid would begin to drift away from nominal, and the loads of the gensets would begin to start oscillating between the gensets until such time as the "fighting" starts (also a subjective--NOT objective--term!), eventually leading to tripping on reverse power and/or over- or under-frequency--also called a blackout.
Also in my personal opinion, this concept of operating multiple gensets in Isochronous Speed Control mode at the same time while synchronized together supplying a load exists because plant operators are not properly trained in how to operate a small, islanded system with one genset in Isochronous speed control mode--and/or the islanded system is, 1) not configured properly for such operation, 2) has been modified since the original commissioning resulting in operational problems and blackouts, 3) the load(s) are not stable and large load swings cannot be predicted or anticipated or responded to quickly enough by the operators (regardless of their training and experience).
So, manufacturers of power generation equipment and suppliers of power generation equipment controllers have chosen a very terrible term (Isochronous Speed Control mode) to describe the method of load/frequency control of multiple gensets at the same time when synchronized together and supplying a load (loads).
I have been to a couple of sites where the Customer was complaining very loudly that the Isochronous governor modes of the machines at the plants weren't working properly. And, at both sites it was possible to instruct the operators on shift at the time to reliably operate the plant with one unit in Isoch mode and the others in Droop mode. They didn't much like being told what to do and when to do it, but it was demonstrated (and recorded using data archival and retrieval methods) that it was possible and could be done. When we left the site for the night, we didn't even make the 45 minute drive back to the hotel before we were summoned back to site--because the next shift had arrived and taken over the plant and it went to hell and blacked out. FORTUNATELY, we left the trending program running and were able to point to precisely when and how the instability started (that lasted for only about 10 seconds) and resulted in the black-out. That particular site chose to implement Isochronous Load Sharing (the term the OEM had for operating multiple gensets in parallel with each other in a pseudo-Isochronous Speed Control mode, which was a de-tuned Isoch mode. The modification required LOTS of additional programming (perhaps what you are referring to as "auxiliary controls" as well as new wiring to share signals between multiple generator prime movers.
When it came time to commission that system at that site, it took more than month-and-a-half and the plant tripped multiple times--hence why it took so long to commission (the site would NOT allow testing/operation except at low power outputs and process outages). The "tuning" (setting of Droop regulation setpoints, essentially) was time-consuming, also. And, as it turned out--usually, once a proper regulation setpoint was found for a particular load, if the load was increased or decreased there was new instability and other issues. Eventually, it was made to work--but it was never fully automatic and required constant operator monitoring and attention.
I have been to other sites where the Customer used a third-party system for load/frequency control of multiple generator sets--usually in Droop Speed Control--that had similar issues and took a long time to commission and never worked fully in automatic and without constant operator monitoring and attention.
That's the Holy Grail, though--fully automatic power system operation without human operator attention or supervision. I do believe it's close, what with machine learning (AI--Artificial Intelligence), but even then, it's going to take a fair amount of iteration to make it truly automatic and human-less. That's what power plant owners want--autonomously operated power plants. That's what even one OEM is touting with their software--autonomous plant operation. Owners want to reduce manning costs, and software and controls automation is the way to do it. (Interestingly enough, a new field of controls is emerging which monitors sensors and data to alert to bad sensors or faulty data. This, of course, requires modeling and redundant sensors. All of which is greatly increasing the complexity of the control systems and the number of sensors, all of which require calibration verification, but which most power plant owners are only doing when a sensor is determined to be not working correctly but which may have been drifting out of calibration for some period of time and negatively affecting unit efficiency, operation and reliability.
I can't offer any more to this thread. Perhaps if there had been a better explanation of "auxiliary controls for parallel operation of isochronous governors" we could have made more progress. As it is, we're all speculating and opining--and that's not research or being constructive. I had similar conversations with OEM engineers in offices halfway around the world from the sites where Isochronous Load Sharing was being implemented--which was really nothing more than load-sharing of machines with low droop regulation setpoints (less than 4%, sometimes much less than 4%) and lots of auxiliary sequencing and signal sharing--most load (not speed).
Prime mover governor speed control is very fast--and typically uses speed sensors with wheels with multiple teeth (60 or 100 or more, depending on the prime mover) and high-speed input cards which monitor and sense subtle changes in speed. Why? Because speed and frequency are directly related. And, during synchronization, speed control needs to be accurate.
Again, without spending a lot of time reading a paper which hasn't been offered about the control scheme which is being designed for some academic purpose I can't offer any more to this thread. And, I don't have any time to devote to this in the future. If this has serious merit, some OEM or controller manufacturer will pick it up and we will all hear about it--because it will be big news in the power generation industry because fossil-fueled power generation is going to be necessary until such time as large energy storage methods and schemes can be put in place (even including pumped storage!) to stabilize renewable power sources on large grids, or even smaller, distributed grids (which is becoming increasingly popular in theory but not yet in practice).
Best of luck!
 
Sorry for late response.

I'm really appreciate to you guys reply.

Once, I will study more about what you mentioned.
Before it, the discussion is meaningless.

I will read and read repeatedly that you guys are aforementioned.

God bless you.
 
Sorry for late response.

I'm really appreciate to you guys reply.

Once, I will study more about what you mentioned.
Before it, the discussion is meaningless.

I will read and read repeatedly that you guys are aforementioned.

God bless you.
Dear JunHyeok ,

Thank you for your last message , I really appreciate it.


It would be fine to tell us how things are going on this thread subject??
As we spent time trying to support/help, you and then we can ask for miminum feedback to close the thread.

Thank you for your understanding,

God bless you,
Controlsguy25
 
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