Reactive power sharing in Island mide


Two equally sized diesel generators are used to supply critical parts of a plant, when national grid is out.

I suppose one of the units should be in isochronous voltage control, to regulate the bus voltage.
What should be the control mode of the other unit, so that they will share the reactive load?
Can the other unit be given the same excitation reference as the isochronous unit?


While I have encountered exciter regulators with Droop (which is really just straight proportional control), I don't recall every encountering an exciter regulator with Isochronous control.

My experience with reactive power-sharing during island operation of two or more generator-sets is that in order for the system voltage to be at rated the generator(s) must supply the reactive power required by the load. And that's usually handled--in my experience--by the operators (which means it's usually not handled very well). When an external control system is used for "power management" for frequency and reactive load control some really interesting--and not so good--things happen.

My scope during island operation testing is frequency control--unless there is an external power management system, and then my scope is to try to explain why the PMS isn't programmed properly (which is like pushing a wet string and expecting it to be straight while it's moving).

I think you're on the right track, thinking of reactive power-sharing during islanded operation like one would think of real power-sharing to effect frequency control. Voltage can be thought of like frequency. (I'm NOT saying it is--just that there an analogies there which can be useful in developing an understanding (without all the maths--which can be understood easier once the fundamentals are internalized).)

But, that's all I got for ya. Which is why I didn't chime in before. If you can explain what (if any) issues you are experiencing, and provide a little more information about the generator-sets and the exciters and loads involve we might be able to offer more.

I dont´t have any issues at the moment. I am looking at replacing old AVR´s.
It is two 1MVA diesel driven backup synchronous genarators.
The machines are generating at 6.6 kV and both unit have their own 6.6/10 kV step up transformer.
Step up transformers are feeding a common bus which have some loads and a connection (via transformer) to the national grid.

When one gen is in service in island mode, I thought that the AVR needs to be in voltage regulation mode, to keep bus voltage at 10 kV.
But if I have two units in island operation in voltage regulation mode, I think there is a risk that they will compete with each other and that the bus voltage will not be stable.
Would it be possible to have one AVR in voltage regulation mode and the other machine is fed with the same excitation reference? In that case the reactive power sharing would be equal between the two units.

Once the connection to national grid is closed, my plan is to have both machines in VAr- or PF-control, to avoid leading PF and risking out of step.

These are just my thoughts and I´m not planning to invent the wheel again.
Therefore my question, what is the best practice in this situation?


These are really good questions for the potential suppliers of the new AVR equipment. They know their equipment better than anyone else. In my experience, I have only seen exciters "fight" for control of bus voltage once--and that was when someone had misconnected the CT (Current Transformer) circuit of one of the generators and hadn't verified the connections before saying it was okay to start the machines. 25 MVAr in and 25 MVAr out on 2 25 MW machines--and TRIP!

If proper synchronizing practices are performed (matching speed and voltage), I see no reason why anything special need be done for most AVRs. There are probably some AVRs that have special options for particular circumstances, but I don't have experience with those.

So, when these machines are synchronized together now (with their current exciter regulators (AVRs)), how do they behave? Do they fight for control of bus voltage/VArs? I presume they are tested occasionally, and probably even get put into service occasionally when separated from the grid, so how do they perform now?

Best of luck with your possible anticipated issue(s).

There was a reason why I didn't get involved in this thread when it was first posted. I should have continued to follow my instincts.

Another life lesson learned, and tucked away for future reference.
I'm sure that AVR suppliers can answer these questions.
But I hoped that someone here could explain how this is usually done.
I cant see how two AVR's trying to regulate a common process value (bus voltage), will not create potential problems (if they are set up as pure voltage PID loops).
I guess they are not set up as pure voltage regulators.
With two control systems in strictly proportional control ("droop") neither control is really trying to control a particular voltage setpoint. The operator changes excitation to make the voltage equal to what is required/needed/nominal, and if the voltage drifts (because the reactive load changes) the operator has to make another change--because in proportional-only control (NOT PID--just straight P!) there's nothing to cause the control action to drive the process value back to the setpoint. (That's kind of what "droop" means--the actual (process) value is allowed to differ from (be more or less than) the setpoint, and there's no control action to cause the control to return the process value to the setpoint.)

Two generator sets with their governors set ti Isochronous speed control WOULD fight for control of frequency (load)--because BOTH are always trying to keep the actual frequency equal to the setpoint. THAT'S why on an islanded system, one governor is (should be) operated in Isochronous Speed Control mode, and any other generator set which is synchronized to the island is to be operated in Droop Speed Control mode--letting the Isochronous machine control the frequency. The Droop machines don't control the frequency--the Isoch machine does. And the Droop machine(s) are just along for the ride, happily contributing without trying to control the frequency at the same time as the Isoch machine. NOW--this is for the prime mover GOVERNORS, NOT the exciter regulators. But, again, there are similarities in the analogy. I have seen references to AVR Droop control, but never to AVR Isochonronous control. Doesn't mean there isn't some manufacturer using that terminology--it just means I haven't seen it. And, I haven't seen every AVR, nor will I. But I have seen a fair few of them.
Exactly, two units in droop will not regulate bus voltage to a setpoint.
And there is no operator to adjust excitation, to keep bus voltage at desired level. This is a standby system that kicks in if grid connection is lost.

As I see it, to regulate bus voltage to a setpoint, one unit needs to be in pure voltage regulation mode.
But you said you have never seen that, so what am I missing?
Could it be that generator(s) in island operation with AVR in droop control, "regulates" bus voltage good enough and that there is no need for a straight line voltage control?

Have you never seen the two diesel gen-sets you are referring to run in island mode supplying watts and VArs?

Presuming the real load(s) are stable and the island is at rated frequency with two units synchronized together if one wants the island system voltage to be at rated, one needs to adjust the AVR of both machines until the reactive load is being carried by one or both of the gen-sets. Let's say, the reactive load is 2.3 MVArs, leading. No matter what one does with the AVR settings of the two generators the reactive load is going to be 2.3 MVArs, leading (the load is the load!). Let's say one generator is carrying 2.0 MVARs, leading, and the other is carrying 0.3 MVArs, leading. In this case the island voltage would be very close to rated. Now, if someone or something started changing the AVR setpoint of either machine, the island voltage will start to drift from rated. If someone or something gets carried away and doesn't pay attention to what they are doing the reactive loads on the two generators will change as one starts to produce or consume more MVArs, and, in my experience when this happens the island voltage--as a whole--changes (high or low).

Again, I don't know what you're talking about when you say "pure voltage regulation mode." If the AVR is not in VAr control or Power Factor control, and the exciter is in Automatic mode--then the setpoint is voltage, and the feedback is voltage. That's the way most every exciter regulator (AVR) I have ever dealt with works. There's Automatic Mode (which is voltage regulation--a voltage setpoint and voltage feedback, and excitation is adjusted to make the generator terminal voltage equal to the setpoint by the regulator). There's Manual Mode--which is where the setpoint is excitation current or voltage, and the feedback is excitation current or voltage. The operator will most likely be looking at generator voltage when making adjustment in Manual Mode to make the generator voltage equal to some desired value, but what's changing in this mode is excitation current/voltage setpoint and what's being regulated (controlled) is excitation current/voltage.

When the AVR is in VAr Control or Power Factor control (and it is in Automatic Mode), the generator voltage is regulated to control a VAr or Power Factor setpoint. (Not a good way to operate an islanded system, especially if the reactive load changes a lot or or frequently.)

But, if you've never seen the two generators you are citing run in island mode and checked how they are operated, it's probably a good time to set up some kind of witness/test for you. (I'll bet that will be difficult, because most plants/operators don't like to run islanded--it's only an emergency mode--because when they try to do it it almost always results in tripping/blackouts.... And, that's most likely NOT because of equipment configuration or set-up problems, it's because the operators don't know what they're doing and try to make adjustments based on what they think they should do--which is not always what they should do when operating in island mode, with multiple gen-sets synchronized together.) Someone will probably say, "That's why we want you to get new AVRs--because [we think] the AVRs are the reason the island is unstable and unreliable when we try to run it for a test!" And, to be honest, they really haven't thought anything through, they just "took action" without understanding the physics involved and their actions seemed logical, based on what they would do when the units are synchronized to a larger grid--and that was wrong. But, they never really thought about anything--before or after. And, therefore the wrong thing(s) get blamed. (Of course; it's never the operators' fault(s)--it's always some control system's fault, because they have too many wires and too many flashing LEDs, and they're very complicated.)

Best of luck.
I have not seen them in operation.

With "pure voltage regulation" I mean a voltage regulation, without droop.
As you said, droop control means that someone has to adjust the AVR to make bys voltage at desired level, so why don't do it automatically?

A simple PI(D) regulator would regulate the voltage to the setpoint, independent of load and no interaktion from operator.
No operational experience.

You should try studying some of the manuals and white papers written by some of the AVR manufacturers you are considering to gain a better understanding of the equipment and how it is applied. Basler is a well-known manufacturer of excitation systems and AVRs, and their manuals are among the better ones in the industry. You have to give your name, affiliation, and email address and wait to be added to their registry in order to gain access to their manuals and white papers (documents describing operation and programming and physical principles employed in their equipment).

Best of luck. You have your way of looking at things, and that's good--you have given it some thought and consideration. And that's all good, but you need some experience--at least with the equipment you are working with--and then maybe you will come to a different, perhaps better, understanding of how things work.
I have lots if experience with synchronous machines and now how they work.

I just wonder why the voltage regulator cant be based on a simple PI(D) regulator instead of a droop controller that might need interaction from an operator in order to keep bus voltage at setpoint.
In my world an AVR should be just that, Automatic voltage regulator, not semi-automatic.
This is for backup generator(s) connected to an islanded bus and no operators looking after the equipnent.

Thanks for all input.
I found a manual for a Basler DECS125-15 (I used this unit for excitation control of a motor many years ago, in VAR/PF mode).

This unit has 3 different modes of operation.
"Droop mode", "Voltage mode no droop" and "VAR/PF".

Voltage mode without droop is what I would call isochronous voltage mode, am I wrong?
You said you have never seen a AVR in isochronous mode, so I´m starting to think that we are talking about different things here.
I found a manual for a Basler DECS125-15 (I used this unit for excitation control of a motor many years ago, in VAR/PF mode).

This unit has 3 different modes of operation.
"Droop mode", "Voltage mode no droop" and "VAR/PF".

Voltage mode without droop is what I would call isochronous voltage mode, am I wrong?
You said you have never seen a AVR in isochronous mode, so I´m starting to think that we are talking about different things here.
Unsure if you have found your answers here, voltage with no droop is isochronous, however without any method of kvar sharing, the machines will fight and trip from over/under excitation.

Have you considered utilising cross current compensation (CCC)? When appropriate logic is put in place for the droop CT shorting relay and another relay to open circuit the main CCC circuit (when the generator(s) are in parallel with the grid), this would provide a way for the generators to maintain a set voltage when islanded (both in parallel with each other and not) and in parallel with mains.

This would be achieved if:
- The regulators are of the same make and are set to operate in droop*
- The generator ratings are the same*
- Droop CTs are the same*

* It is possible to have different regulators, rated generators, or CTs, however compensation resistors between one of the AVR CT terminals and the CT before the unit/parallel relay would need to be used.

If interested, then the attached is a useful read