Generator, PF, and reactive power 2

[Roger00]

hi All,

I want to have your opinions about PF, and reactive power:

1) why does generator with PF 0.85 lag to 0.9 lead have better flexibility in the Grid than PF 0.9 lag to 0.9 lead? is it because they can work in lower grid voltage?

2) our grid regulating body requires power plant to have 0.85 lag to 0.9 lead, does this mean they want to ensure that power plant can supply more VAR to support grid voltage drop? if yes, is it always voltage drops the power factor also drops (to lagging).

3) Who control grid power factor? is it regulating body or Is it grid frequency, power factor, voltage are related to the generating load vs consumers load?

4) If i have generator (H2 gas cooling) with rating of PF 0.85 lag, but in actual condition always works at 0.9 lag, from gen. capability curve does this mean the generator will require less H2 pressure at the same MW with 0.85 lag, while if at the same H2 pressure the generator can supply more MW?

5) why regulating body does not pay VAR but only MW? if grid voltage drops and regulating body requires a power plant to supply more VAR at the same load? so does this mean the generator excitation current will increase its current and affects steam turbine control valve to open wider? is this how to quantify the cost of VAR by more steam/fuel demand?

6) For 660 MW, which one is the best generator with PF 0.85 lag to 0.9 lead or 0.9 lag to 0.9 lead, what are the impacts to generator? is it 0.85 lag will require bigger size and why? what are other difference of 0.85 lag and 0.9 lag?

thanks for your answers

 

[rcw retired EE]

For generators, lagging power factor means the generator is supplying Vars into the system, leading power factor means it is pulling vars. Most generators are rated 0.85 pf lag to 0.9 pf lead. There are problems with sucking too many vars - operating wih a low leading power factor.

Think of vars as the electrical transmission fluid needed to get watts from a generator to the load. The steam turbine is spinning the generator rotor but how does that power get across the rotor air gap into the stator windings? It’s the magnetic field from the rotor that gets the power across the air gap. It is the same thing on a motor or a transformer where there are two windings with no connections. The magnetic fields transfer the energy from winding to winding and from motor stator winding to rotor. If the magnetic field is not there in the generator, the transmission line, transformer or motor, no power can flow. (This analogy is not 100% perfect but it helps understand volts, vars and watts). Thnik of the vars as building those magnetic fields so watts can flow.

Vars always go from high voltage to low voltage. (Watts go where they are needed). To push more vars out of the generator, raise the voltage higher than the utility voltage and more vars go out and the power factor goes further towards lagging.

Changing the voltage barely affects the MW output. The steam valve controls the MW output and the voltage regulator controls the MVAR output. There is almost no cross over between the two controls. Spinning the voltage dial hardly moves the watt meter.

The generator produces the vars and the air gap magnetic field with the DC excitation to the rotor winding. To get leading power factor (sucking MVARs from the system to pull down a high voltage) decrease the excitation which reduces voltage and the generator sucks vars and power factor goes more leading.

If you keep reducing the excitation, the magnetic field in the air gap weakens as voltage drops. Eventually, the magnetic field is too weak to hold the rotor in synch and the generator starts slipping poles. You've drained too much "transmission fluid" out of the air gap. About the second time the pole slips past, you trip the turbine and call either a junk dealer and mortician to collect the scraps, or if you're lucky, a generator rewind outfit.

That is one reason why a generator can push more vars than it can suck. Very seldom do power plants get requested to pull the voltage down. Most utilities and system operators require plants to be capable of operating at full MW with 0.85 generator power factor. Each generator is asked to provide their share of the vars needed to maintain system voltage.

As you mentioned, they usually don’t get paid for supplying VARs, but if they don’t, they don’t get to sell megawatts.

 

[rcw retired EE]

Check your generator capability curve (MW vs MVAR curve).

(Search capability curves on this forum to find some good explanations).

A 100 MVA generator rated 0.85 lag to .90 lead has a rotor capable of 100MVA in that range. At its rating point it can put out 85 MW + 52.7 MVAR = 100 MVA @ 0.85 pf.

Its capability curve is a constant 100 MVA radius line from 0.85 lag to 0.9 lead. Beyond 0.85 lagging, rotor heating is the limiting factor due to higher excitation current needed to produce more vars. Beyond 0.9 pf leading, stability limits are the issue as I discussed above.

Say you have a 100 MW turbine. If you could get by with a 0.9 pf generator it only needs to be rated 100MW/0.9= 11 MVA. At 0.85,it has to be rated 117 MVA. Stator windings, cooling and excitation all have to be bigger for the lower power factor unit.

That power has to go out through a step up transformer before you can sell to the utility. The transformer impedance is mostly reactance so it requires vars. If the utility requires power at 0.9 pf, the generator will probably have to run at 0.85 to supply the var losses in the transformer and still deliver 0.9 pf MW.

You mentioned hydrogen pressure. Hydrogen is the cooling medium. The capability curve is based on thermal considerations. Changing H2 pressure doesn't make more MW, it allows better cooling and moves the constant MVA line out a bit
.

 

[crshears]

The term 'grid power factor' is meaningless; power factor can only be measured in one set of conductors...

The simplest AC system constructable has one generator supplying one load. Since current phase displacement from voltage is constant from end to end, the power factor measured at the load will be the power factor of the generator.

However, as soon as multiple loads or multiple generators are combined into one system, it gets complicated; resistive loads will have a PF of 1.0, almost purely inductive loads like the reactors used to suppress voltage rise on 500 kV circuits will have a PF near 0.0 lagging, induction motors will, depending on loading, have a power factor somewhere on the lagging side of unity, and almost purely capacitive devices like the capacitor banks used to supply 'lagging' reactive power near major load centres will have a PF near 0.0 leading. Power grids may be predominantly inductive or predominantly capacitive [most are the former], but grids or systems as such do not have power factors; only the devices connected to them do. [For the sake of this discussion, a single load customer or a generating unit can be considered one device.]

Throughout my operating career I have encountered generating units equipped with voltmeters, ammeters, wattmeters, VARmeters, and synchroscopes; never have I seen a power factor meter installed [one achieves 'unity power factor' on a generating unit at zero vars]...but hey, maybe other utilities or entities have them.

CR