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AVR Functioning and MVAR control
AVR Functioning and MVAR control for Gas and Steam turbines

Dear All,

I was gone through many threads in control.com. However finally i got confused and didn't get the answer. everywhere lengthy replies which is making more confusion and troublesome.

Our Plant is configured into 3 blocks. Each block constitutes 2 Gas turbines with 2 HRSG's and one Common Steam turbine. Each Turbine has its own Generator with its own corresponding Generator Step up transformer. So Total 9 Generators. (6 Gas turbine + 3 Steam turbine).

Gas turbine having 52G as synchronizing breaker which lies b/w generator terminals and corresponding step up transformer. (52L all the time in close condition corresponding to Gas turbine), where as steam turbine having 52L (line breaker) as synchronizing breaker.

Generally Grid operators used to call us to increase or decrease Grid KV by 1 or 2 kv like that...So according to that we give var setpoint to each and every generator equally (sharing) almost.

To control the grid voltage we are adjusting the vars flow of all turbine generators producing power at that time.

1) the generator var capability shall always depends on its cold gas temperature with respect to MW. lets suppose when the var limits are high for the given MW allow you to go high var (say 100 mvar). At this moment if still grid is asking to increase more kv means...How can we increase the var window (by increasing the tap or decreasing the tap of a Step up transformer)??..if so we increase or decrease how the var generating capability of the generator increases???

2) why voltage control not provided in GE D11 steam turbine and why all the time both var and pf controls are in enabled condition. where as GE 9fa gas turbine only one control will be in service any time(either var or pf or voltage)?? kindly differentiate why it is like this

3) can i say (volt and pf and var controls) are sub controls of AVR.??

1 out of 1 members thought this post was helpful...

Thank you for taking the time to search through the archived threads looking for an answer to your question(s).

1) Do the transformers at your site have load tap changers, capable of changing taps while the transformer is energized and current is flowing through the transformer? Or would the transformers have to be taken off-line to change the taps?

A lot of sites use transformer with load tap changers to help expand the range of voltage excursions the generator can respond to--but this requires tap changers that can be switched while current is flowing through the transformer (LOTS of current). Transformers with non-load tap changers can also be used, but they have a limited ability if voltage excursions are very large and frequent.

Best to work with your utility/grid regulator after you understand the capability of the transformers at your site. This is something that is usually considered during the design phase of the plant and documented in the plant manuals provided by the plant designer. Conditions do change over time, requiring different operating considerations--but usually when something like this occurs a power system study is performed to be able to understand the capability of the existing equipment and what can be expected of the existing equipment given the current or expected changes to system parameters. Any upgrades would be recommended at that time.

2) I've heard this complaint about D-11s before, and I find it very difficult to understand how VAR and PF control can BOTH be enabled and active at the same time. If one sets a VAr setpoint and enables VAr control, then as load changes the PF will change. And, conversely if one sets a PF setpoint and enables PF control then as load changes the VAr reading will change. They are not mutually exclusive, and in fact are very related. If one enters a VAR setpoint when VAr Control is enabled and active and the load does not change and the grid voltage does not change, then the PF will remain constant. It's even possible to adjust the VAr setpoint to achieve a desired PF--but as soon as the load changes or the grid voltage changes the PF is going to change even if the VArs don't change.

And, if 'voltage control' was not enabled, how could the voltages be matched during synchronization? Also, what would happen if the VAr input(s) failed? What mode would the exciter go into? Without VAr feedback neither VAr nor PF control would be possible.

It's possible, but not likely, that there is some kind of "cascading" generator control that is automatically enabled when the generator breaker closes--but that just doesn't seem very realistic. Rather, it's more likely that the indications on the HMI are not configured correctly leading the viewer to believe that BOTH VAr and PF control are enabled simultaneously, which, as was said above is pretty hard to understand how they could both operate simultaneously.

3) Historically, GE has, in the past, done VAr and PF control in the Speedtronic turbine control panel, simply issuing exciter RAISE and LOWER signals to the exciter regulator as necessary. So, the VAr transducer input(s) are connected to the Speedtronic turbine control panel, as well as the load transducer (MW) inputs. The power factor is calculated in the Speedtronic from the Watt and VAr transducer inputs. So, load control, VAr control and PF control can all be accomplished in the Speedtronic turbine control.

It's always been a question about why VAr and PF control were done in the Speedtronic turbine control panel, and with newer exciter regulator regulators capable of receiving inputs from CTs (Current Transformers) making them able to calculate Watts and VArs and PF it's certainly possible that VAr and PF control could be "moved" from the Speedtronic turbine control panel to the exciter regulator.

If VAr and PF control were done in the exciter regulator, then, yes--they could be considered subsets of the exciter regulator (the "AVR").

As usual expected Mr.CSA is the one who strikes the reply earlier. Thank you very much sir...

You are my Guru (means MASTER in Indian national Language). I learned many things from your posts.

thanks a lot for sharing your knowledge with whole world. You have great fans all over the world..

> 1) Do the transformers at your site have load tap changers, capable of changing taps while
> the transformer is energized and current is flowing through the transformer? Or would the
> transformers have to be taken off-line to change the taps?

Yes, we are doing tap changing when machine is on load and transformer is energized and current is flowing through the T/F.

suppose if grid ask us to increase 2kv we will increase mvar setpoint from 50 to 70 (lets say example) and if they ask us to increase one more KV then we will increase mvar setpoint from 70 to 90..and it goes on. at this time we keep eye on generator terminal voltage and generator capability curve. over excitation limit should not reach and gen terminal voltage must be with in limits.

As i am working in field some times our controller ask us to do increase tap change or decrease tap change (we are in field so we don't aware that time whether we have lagging var flow or leading var flow) doing blindly what control room engineer telling, we take the tap control to manual we increase or decrease according to his requirement. unluckily our engineers not interested to share the knowledge. but i never stop learning as long as Masters like you exist.

So just tell me whether my imagination is right or wrong

when generator MVARS are high already due to grid demand, i think we should decrease it from 13 to 12 (example). In this condition the system voltage and generator voltage (primary side or low voltage side) of StepUp T/F reduced slightly both sides. so that our var capability window will become more. then we can supply more var as required by the system.

Even when the var limits are high for the given MW allow you to go high var (say 100 mvar) but "excessive Volts/hertz limit" doesn't allow you to give more excitation in order to protect stator winding from over temperature (to my idea)

generally when u increase var, your terminal voltage of generator and results in further increase in voltage on SUT secondary.

But if you see the V/Hz limit is not active here.

so, by reducing the tap position of SUT on secondary, the system voltage will drop slightly reducing generator terminal voltage

so, then volts/hertz limit will not act even if you increase the var until the limit again reaches.

Then we can increase VAR supply in the lagging direction or we can say we are in lagging power factor.

we will do vice versa when we need to consume reactive power or when on leading power factor(which is indigestible after certain limit to any generators as they are mainly supposed to supply lagging var). we will increase the tap position so there will be slight increase in voltage on primary and secondary side of stepup T/f so the excitation requirement from the avr will be less to support terminal voltage setpoint.

2) another big doubt for me recently i had some fight with my controller. he is telling AVR is only online during startup and up to synchronising but later on this is in standby condition and no use. But i argued with him. Yes the main function of AVR is during startup and synch but it never be offline. till before it was connected to the grid AVR tries to maintain gen voltage and after connected to the grid it is looking after VAR flows into and out of the generator. so as VAR flow is related to VAR control and as it is subset of AVR. and also told him in case of grid fluctuations for sure there will be considerable deviations in the system voltage, so at that time AVR is taking care of gen terminal voltage by not deviating much from its limit. So, i told him in this way AVR is still online when connected to the grid, but he is not accepting.

3) i never see V/HZ and OEL and UEL are active in EX2100 screen. Do they are not active when the machine is in online with grid?
Do they active only when that particular condition was arises like over excitation etc.

Thanks and Regards

Transformer tap changers are available in different configurations, and without understanding how yours is configured--I'm very reluctant to make more comments.

There are two basic types of AC machines: Synchronous and Induction. Most engine-driven generators (and turbines are engines, too) are synchronous machines. If the rotors are not energized when current is flowing in the stator then the rotors will quickly overheat and be damaged. That's why there is 'Loss of Field' protection (also called UEL) to protect against damage--either from the effect of heat or when excitation decreases and the generator slips a pole. The "AVR" or exciter must be energized whether the synchronous machine is being used as a motor (during starting) or as a generator because current is flowing in the stator windings.

As for V/Hz, OEL and UEL protection--I believe they are "optional" in the EX2100, but are almost always used. They won't be 'visible' until they are actually limiting something so it's ikely that you haven't reached one of the configurable limits.

Hope this helps!