# Generator droop control

#### JohanK

Hello,

In reactive droop compensation mode, how is reactive power actually affecting the voltage control loop?

I suppose that voltage control regulation without droop, is a PID loop, with a voltage setpoint and the actual generator voltage as process value.
How does the reactive power signal actually affect the PID loop?
Does it offset the setpoint or process value and is it still a PID loop, or a proportional only loop?

Does speed/power droop control function the same way?

/Johan

#### JohanK

OK, but how would that help me with my question?

/Johan

#### CSA

JohanK,

You both seem to believe in similar philosophies of generator excitation control and regulation. Perhaps you can help each other come to some kind of mutual understanding. And, actually, there are four (4) questions in your original post to this thread.

Droop speed control is, as was explained, proportional control--no "reset" action (no I or D). A machine governor being operated in Droop speed control with 4% droop regulation will be at approximately 50% of rated load when the speed reference is at 102% and the actual speed is at rated. If the actual speed decreased by 0.5%, then the actual load being carried by the prime mover (watts; kW; MW) would increase by 12.5% of rated, to 62.5% of rated. This topic has been covered SO MANY times on Control.com, and can be found using the 'Search' feature at the top of every Control.com webpage.

Isochronous speed control on the other hand is proportional plus integral control (PI control). Any change in load on the system to which an governor being operated in Isochronous speed control mode will result in a very fast response by the governor in Isochronous mode in order to return/keep the frequency (which is a direct function of generator rotor speed) at rated (as long as the change doesn't cause the machine to go below 0 watts/kW/MW or above rated load). If the operator or some external system tries to change the load on a machine governor operating in Isoch mode the result will be to change the frequency of the generator and of the system. (Any time load(s) change on an electrical transmission and distribution system the immediate result will be for the system frequency to change (which also affects the speeds of EVERY generator synchronized to that system; synchronism and synchronization is a VERY POWERFUL phenomenon and term.)

That is why there should only be one--and ONLY one--generator set operating in Isochronous speed control mode connected to (synchronized to) any grid. Because multiple Isoch machines will DEFINITELY fight to control frequency (speed) and the usual outcome of that is not very pretty (think blackout). There is something called "Isoch load sharing" but it is really just detuned Isoch governor functions which REQUIRE external communications and control schemes to even attempt to operate properly and testing/tuning such systems can be fraught with issues and require huge amounts of time and even more effort.

As jtkarlsson will tell you, on a small grid with, say, two similarly-sized generator sets (generators and their prime movers) if the system is running stably at rated frequency and voltage and there is a change in reactive load (let's say it increases by 5% in the lagging direction on a system running at 3.0 MW with two generator sets each rated at 4.0 MW and each running at 1.5 MW while each sharing 50% of the reactive load on the system, the total reactive load on the system changes and usually the system voltage also changes--unless there is some over-riding control system/sensor which returns the system voltage to rated (and the reactive load will remain at 55% or so). In my experience without some kind of external power monitoring/management system to change real load or generator terminal voltage when the reactive load changes the immediate effect on the system is for the system voltage to change in order to "support" the reactive power change. And, that's the SAME thing that happens when the real load changes on a power system without some external load monitoring/management system: when the real load changes the immediate effect is for the system frequency (speed) to change and unless someone or something changes the energy input to one or more generator prime movers the system frequency is going to increase or decrease from rated.

Just look at a graph of ANY power transmission and distribution system at any time during the day--but if you do it in the morning (when people are waking up and starting work, or when they are quitting work and going home) the grid frequency (and grid voltage) will be more unstable than at other times during the day or night. And it takes PEOPLE--or some very sophisticated control systems capable of sending commands to one or more generator sets--to return the system or to keep it at rated. It's not the individual governors or excitation control systems (AVRs) that do that--it's some over-riding regulatory scheme that has to do it. That's why in some parts of the world the grid frequency and voltage are fairly stable, and in others, it's a moving target--literally.

MY experience with generator excitation systems (AVRs) is that they have some form of Droop (and it's even referred to as Droop regulation). In MY experience, whether in parallel with other units on a large(r) ("infinite") grid, or some small island power system that it requires operator intervention to maintain a generator terminal voltage (system voltage) as reactive power--and even real power--varies. Want proof? Leave the exciter regulator (AVR) in Auto mode after synchronization and load the unit. As real power increases the actual (process value) generator terminal voltage will decrease--the degree depends on many factors, but invariable it decreases. Do the same when unloading a generator set from rated power in Auto mode; the actual generator terminal voltage (process value) will almost always increase as the unit is unloaded requiring manual intervention to maintain generator terminal voltage. (In both cases, I am referring to NOT using EITHER VAr control or Power Factor control--which many grids are now restricting the use of (because it can cause and exacerbate grid disturbances in many cases.)

Anyway, reach out to jtkarlsson (I'm sure it's not very far... ;-) ) and see if you two can't answer each other's questions and doubts and concerns.

Again, blessed day!

#### JohanK

Oh my god , that's a long answer. Thank you!
But I still don't know if a voltage droop control is using a P or a PI control loop,do you?

#### CSA

What does your Basler DECS manual say?

#### JohanK

I don't know what's wrong with you, but I'm sure there is help to find somewhere.
You can't face the fact that there is onre question that you don't know the answer to, can you?

#### CSA

JohanK,

I don't have all the answers, and I have as much as said so for this and the other post I cited. I have answered to the best of my experience and knowledge; I am most familiar with GE-design heavy duty gas turbines, generators and auxiliaries and the GE Mark* line of turbine control products. Most of my experience with GE excitation control systems was with an older GE analog static excitation control system, and I do have some experience with Isoch testing and operation (during commissioning of new heavy duty gas turbines).

I even wasted some of my life looking at a couple of DECS manuals (including the one you cited) for more information, and I didn't find anything that might be of help to either of us.

HOWEVER, Basler has an area of their website which is populated with "white papers"--which are descriptions of operation and applications and concepts and philosophies. They are available for download (after registering, and if start to receive marketing emails after registering you can unsubscribe and they will quickly stop) and review.

I don't tend to recommend textbooks or reference books on the matter of droop and/or isochronous control--of speed or voltage. Most are written by ivory-tower, egg-head professor types with very little hands-on operating experience and the concepts they present ARE NOT properly explained because they fail to state the full conditions necessary for what they are trying to explain to actually happen. (For example, the only way actual speed (frequency) decreases when load is "added" to a generator set (generator and its prime mover) is when the genset is isolated from other machines and is operating in Droop Speed Control without a conscious human being paying attention--but that's just about the typical explanation given in most texts and references is that when a genset is loaded the actual speed (frequency) decreases regardless of its operating condition.)

I don't know where to tell you go continue looking for the answer you so desperately need to satisfy your understanding of generator voltage control on an islanded system of two similar-sized units synchronized together supplying load(s) which have a reactive characteristic of some sort that seems to vary over operation/time. I've explained what I have witnessed and observed--did I dig into the exciter regulator to see precisely how the controls work, if they use PID controllers; no. I presume from the behaviour I have seen during islanded operation that some kind of proportional control is used in the exciter regulator from the way it responds to changes. I don't have any books I can recommend--only the white papers written by Basler available on their website. I have found them to be very informative and helpful at times.

Thank you for your concern for my well-being; it is most appreciated. My problems with being unable to satisfy posters to Control.com are coming to an end very soon. I have paid my debt to Mr. Collins and Mr. Barnett and am looking forward to stepping back from the professional life I was so fortunate to have found and experienced. It enriched me in so many ways I could never have imagined (in addition to my pocketbook!).

Blessed day, sir.