Negative MVAR

[Lenz81]

Hello Gentlemen

Can you please explain me why we usually have Positive MVAR for Gas turbines and Negative ones for Steam turbine? Is it because of different excitation system?

Thanks in Advance.

 

[davidbeach]

I'm not aware of any such relationship.

 

[racobb]

I would expect that it depends on the particular billing constraints that need to be satisfied rather than being machine dependent.

Alan

Democracy is two wolves and a sheep deciding what to have for dinner. Liberty is a well armed sheep!
Ben Franklin

 

[dpc]

The generator doesn't care what is turning it, so I'm with David Beach, I don't think what you are describing has anything to do with the generator or excitation system.

It may have to do with how the gas turbines are being used (peaking versus base load). Most utility generators in my experience operate with a lagging power factor (exporting vars).

"Theory is when you know all and nothing works. Practice is when all works and nobody knows why. In this case we have put together theory and practice: nothing works... and nobody knows why! (Albert Einstein)

 

[Lenz81]

Thanks guys .i believe you are right ,it was interesting for me to see that our operators usually keep the MVAR balance of our plant with Positive MVAR from GTs and Negative from ST.

 

[Rodmcm]

I think I would have a training course for the operators on the possibe effects of negative (I assume you mean leading) VArs......

 

[Lenz81]

yes , i mean Leading VArs by Negative, i know Negative MVAr can cause under excitation and low voltage which can lead system to Over current , Am i right Rodmcm?

 

[waross]

Depending on the topography of the system, distributed generators may be run over-excited (exporting VARs) for voltage control.
Another reason may be fuel costs. If two machines use different fuel with different costs, The machine using the cheapest fuel may be run at close to unity power factor and the VARs supplied by the machine using the more expensive fuel.
I am aware of a system with a mix of remote hydro generation and local diesel generation. They pump as much real power through the transmission line as they can and use the diesel generators (close to the load) to compensate for transmission line voltage drop by boosting the voltage with VARs. This approach keeps the expensive diesel fuel consumption down.

Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[ElectricalPhil]

I'm not a thermal guy, but from what I understand, it could be detrimental to run steam generators (what I'm used to calling a turbo-generator), in an under-excited mode. To be clear, the convention I'm talking about is importing lagging VArs, or operating a generator with a leading power factor.

When operating at high levels of excitation, the core is fairly close to saturation, and the flux paths are parallel to the laminations, preventing significant eddy currents from flowing in the core. When you allow the machine to go under-excited, the flux paths can start to flare out at the core ends. This allows the flux to go perpendicular to the laminations, and substantial eddy currents arise, which may result in substantial heating at the core ends. I've heard anecdotes about cores melting down due to excessively under-excited operation.

Normally, there is an under-excitation limiter that prevents operation too low into the under-excited region.

Lenz81, do you have capability curves for your steam units? Are you aware of whether there is an under-excitation limiter set up and active in your exciter?

 

[Marmite]

Gas turbines are sometimes operated as synchronous condensers and can be used to generate or absorb VARs depending on what is required. Google synchronous condenser.
Regards
Marmite

 

[ScottyUK]

True, but the GT is able to de-couple from the machine once it synchronises otherwise it either requires fuel or power to meet the compressor load.

There are good reasons to keep away from the under-excited region if possible because the machine is operating closer to the stability limit. Any decent AVR which is correctly configured should prevent the machine operating too close to the limit but there is little reason to deliberately operate in the leading area simply to offset excessive lagging VA_Rs from other units. The losses in the generator, GSU transformer and cable or bus duct will be higher with the loading profile you describe than they would if all units were operating slightly lagging to meet the overall dispatch.


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If we learn from our mistakes I'm getting a great education!

 

[Denan]

When you talk about stability, I remembered once I read in a thread here, DavidBeach said something like "pole slip will mess up your entire day".

I find this funny, that's why I remembered it.

Can anyone explain this please? What can happen so day is "messed up"?

 

[ScottyUK]

Pole slipping typically occurs under severe fault conditions which cause a transient torque on the generator which exceeds the ability of the field to hold the generator rotor synchronised to the stator. A generator is most susceptible to this problem when it has a low excitation, as this produces a weak magnetic field. For this reason, capability diagrams show the stability limit for the machine when in an under-excited state. Outside of this line, pole slipping becomes a real possibility in the event of a system fault.

The 'slip' occurs when the rotor experiences a sudden physical and electrical shift in position relative to the stator, after which the field recovers strength and the machine tries to lock the rotor back in synch with the stator. As this occurs the machine experiences violent acceleration and deceleration causing enormous stress on the generator and prime mover, and may result in anything from winding movement to shaft fracture or worse. It is a very serious fault.

A correctly set AVR will act to prevent operation at or outside of the stability limit, but certain abrupt changes in the system caused by faults or badly-planned switching operations may exceed the ability of the AVR to respond if the machine is already near the stability limit.


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If we learn from our mistakes I'm getting a great education!

 

[Denan]

Thanks for the explanation, Scotty!

 

[rcw retired EE]

There should be no reason the steam unit operates under excited. I have seen this a few times on our plants when operators were not properly trained.

Each gas turbine (GTG) and steam turbine (STG) has their own step up transformer, sometimes with identical tap ratios. In 2-on-1 or 3-0n-1 plants (two GTG's supplying steam for an STG) the STG is a larger MVA rating and a higher voltage rating. Typical values are 18 kV for the GTG and 23 kV for the STG. There may be tap ratio differences that make the effective STG voltage less than the GTG so the STG absorbs the MVAR's produced by the GTG's.

When the plant starts up, the GTG's come on line, match the utility voltage and then start supplying MVAR’s. The GTG’s produce heat that makes steam and then the STG comes up and on line. But the GTG's have essentially raised the system voltage seen by the STG so if it has the same effective tap ratio it will come on line with a lower effective out put voltage and start absorbing MVAR's.

Solution is to change taps on the STG step up transformer to raise it s output voltage or tell the operators to raise the STG excitation.

 

[racobb]

Could be several reasons to operate a unit at unity pf or at some level of var export, can't think of a reason to operate under-excited and importing vars.

Alan

Democracy is two wolves and a sheep deciding what to have for dinner. Liberty is a well armed sheep!
Ben Franklin

 

[rovineye]

Linked is a capability curve as mentioned by Scotty.

We do run this machine under excited (0.5 leading or so) when we switch on harmonic filters and before we start up our synchronous propulsion motor. At that time we have very little load however, keeping us out of the unstable region.

I really don't understand all of this diagram. 1 pu field current = 120 amps. I don't know how that is defined. As field current at unity no load? Anyone?

 

[Lenz81]

rcwilson what you say makes a great sense ,therefore after a while The STG effective output Voltage will get to system voltage and it should stop absorbing MVArs ,can we calculate how long it takes to get to system Voltage? Or better to say how long it takes to establish the Balance?

Thanks In Advance.

 

[rcw retired EE]

By effective genertor voltage I was refering to the generator voltage as seen on the utiltiy side of the step up transformer. It is the generator voltage times the transformer ratio minus the transformer voltage drop.

You can change the effective voltage by chagning the transfmer tap or by changing excitation on the generator.

If your operators do nothing, the voltage will stay the same, unless you have some balancing controls to balance reactive power loading. If you do have something like that, the resposne time is in seconds.

I would increase the excitation on the generator (raise generator volts) until it was opearting slightly lagging power factor, delivering a few MVARs to the system.

 

[Lenz81]

rcwilson,what you mentioned is exactly the reason of my question ,I have seen in couple of power plants that operators leave The Stg with Negative VArs But The Gtg with Positive VArs , that is why I brought up this thread. Thanks for replies