Effect or Implication of a Negative MVAR in a Turbine Generator

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Thread Starter

Avworhiare

Hello Sir,

pls can u explain to me the effect of a negative (-ve) Megawatt-volt-ampere-reactive (MVAR) means in a frame 9E gas turbine during generation? eg we are generating and is showing Gen.50/-0.7 (active-reactive).

I have seen different reading showing the active and reactive MW/MVAR at negate and positive. pls explain sir, when it is positive and negative, its implications and meanings as it relates to generation.

2. When the frequency during generation fluctuating BTW 48.5, 49.0, 50, 51hz could mean?

Thanks
 
When the voltage and current at the generator terminals are in phase, Power factor = 1 with 0.0 MVAR and all power generated is MW. When generator is under excited, the voltage at the generator terminals will reach maximum value after current reaches maximum value (lag). Power factor will be less than one and the negative MVAR reading you are seeing will occur. Your generator is designed to carry MVAR, positive and negative. You should have a generator capability curve to indicate exactly what your limits are based on the actual MW and generator hydrogen pressure. The MVARs will cause increased heating in the generator windings that must be accounted for with the cooling system.
 
Avworhiare,

This is quite a large topic, with no easy answer. Hmmm ..., where to start....

When there is no reactive current (VArs; kVArs; MVArs--MVArs stands for Mega-Volt-Amperes-reactive, or millions of Volt-Amperes-reactive) flowing in the stator windings of a synchronous generator the voltage- and current sine waves are indeed in phase with each other. The both reach maximum, minimum, and cross the zero axis at the same time. When this happens, the power factor is 1.0 ("unity"), which indicates zero reactive current flowing in the generator stator windings.

When MVArs are negative, per GE's convention, it means that leading reactive current is flowing in the generator stator windings. This can cause unwanted heat generation in parts of the generator which can lead to premature failure of generator insulation. Further, if the magnitude of leading reactive current gets too high it can mean that insufficient current is flowing in the generator rotor windings which can cause a phenomenon known as "slipping a pole" which can be very destructive to the generator, the load coupling between the turbine and generator, and the turbine. It's NOT a good thing, and there are generator protective relays to protect against this condition which will trip (open) the generator breaker and/or trip the turbine.

The magnitude you reported (-0.7 MVAr) is very negligible and would have not appreciable effect on turbine-generator operation.

As popdaddio suggested, every synchronous generator is provided with something called a 'reactive capability curve' or sometimes called a "D-curve" because of it's shape. This curve shows the limits of turbine-generator operation for various cold gas temperatures (generator cooling "gas", air or hydrogen, as appropriate). These lines, there are usually three distinct lines which make up the limits for each cold gas temperature, reflect the limits of operation which the generator can tolerate without being damaged because of the effects of heating. There is the real power (MWATT) limit (the ability
of the generator to safely remove heat from the stator windings); the over-excited power limit (the ability of the generator to safely remove the heat from the generator rotor); and the under-excited limit (the ability of the generator to safely remove hear from the end-turns of the stator windings, which is where the heat from leading (negative) MVArs is concentrated).

To produce positive MVArs, the generator rotor excitation current has to be higher than normal (presuming the grid voltage is within normal bounds), and this increase excitation current causes the rotor windings to heat up. So, the overexcitation limit (positive MVArs) is a function of the generator's ability to remove heat from the rotor.

To "absorb" negative MVArs, the generator rotor must be under-excited which causes unwanted heat to concentrate in the generator stator end-turns--as well as reducing the generator rotor's magnetic field strength which can lead to pole slipping (again--a very destructive condition).

Now, as for your second question.... Wow. It's very complicated. Frequency is "controlled" by the AC power system grid operators--or not, as the case may be. When a synchronous generator is synchronized to (connected to) an AC power system with other synchronous generators it can't spin any faster or slower than the speed that's directly proportional to grid frequency. So, when you see the grid frequency fluctuating you should also be seeing the turbine-generator speed fluctuating. And, there's VERY little you can do about it. Your turbine-generator isn't going to be able to have much effect on the grid--usually (unless the "grid" is very small, such as just a small plant or refinery or small geographic location). The turbine governor (the Mark V, or Mark VI or Mark VIe--GE turbine control systems) will be trying to respond appropriately to the grid frequency disturbances depending on the current governor mode (Part Load; Base Load; Pre-Selected Load Control; etc.). If the load is changing when the frequency is changing, that's to be expected. MANY people, including operations supervisors and Plant Managers--wrongly believe their turbine(s) should be stable when the grid frequency is unstable, and that's patently FALSE and can even lead to exaggerated grid frequency fluctuations and eventual black-outs.

This question is VERY involved and complicated, but you should know--and understand--that when the turbine-generator frequency is unstable that every other turbine-generator synchronized to the grid is also experiencing the same issues. And, that it's normal--even desirable--for turbine-generators to be unstable during grid frequency excursions, because, if the control systems (the governors) are working correctly they will be responding to the grid frequency excursions in a manner to try to help support grid frequency, which may seem like it's random and excessive, but, in fact, is normal and expected.

Your turbine-generator can't run at 48.9 Hz when every other turbine-generator is running at 50.7 Hz. Nor can one turbine-generator run at 49.3 Hz, another at 50.6 Hz, another at 49.5 Hz, and still another at 51.0 Hz--it's just not possible if they are all synchronized to the same grid. They all have to run at the same frequency--that's the whole idea of synchronism. Think of it like a group of bicycles all hitched together pulling a very large wagon filled with packages. All of the bicycles have fixed gear ratios, and the group is supposed to be pulling the wagon of packages at a steady speed on a flat road. No single bicycle can go faster or slower than any other bicycle--they are all hitched together, and their speed is a function of every other bike's speed. Now, one rider can stop pedaling, but when that happens one or more of the other riders has to pedal harder just to be able to maintain the same speed. Or, if one rider--a particularly strong rider--decides to pedal very hard then the speed of the entire group might start to increase, until one or more riders decreased their pedaling effort.

It's very much the same on an AC power system--there are many generators all "hitched" (synchronized) together to supply a load at a particular frequency. And, they are all operating at the same frequency, even when the frequency is unstable (that's because of very strong magnetic forces at work in the generators). On an AC power system when the grid frequency is unstable, it's because there's an imbalance between the amount of generation and the amount of load--usually, there's not enough generation for the load. And, when turbine-generators don't respond properly then that makes the problem worse.

Let's go back to our bicycle example, and let's say that two bicycles being pedaled by very strong riders suddenly had their chains break. Now, the entire group would start to slow down. If no other riders increased their pedaling effort then the group would continue to slow down. If all the other riders increased their pedaling effort then it's very likely that the group speed would increase above the desired rate, and unless there was some coordination and everyone suddednly decreased their pedaling effort then the group would start to decelerate again, and so on.

Left to their own devices, turbine governors will respond to grid frequency disturbances to try to help stabilize grid frequency. But, if some operators decide their turbine should not change load, and if enough of them decide their turbine should not change load, then the grid frequency can become quite unstable.

There are other conditions such as reactance and distance and type of load which can impact grid frequency--but at your site, you should know that you can't directly control grid frequency. And when grid frequency is unstable you can--and should--expect your turbine-generator frequency--and load--to be unstable. Until the power system operators can restore stability, at which time your turbine-generator will also return to stable speed and load.

Hope this helps!

Find your generator's reactive capability (D) curve, and learn how to interpret it. Don't worry too much if the MVArs are slightly negative, but they should NOT be less than the lower limits of the reactive capability curve. (System, grid, voltage can also impact MVArs, and, again, this is mostly our of your control. If grid voltage goes high, that can cause the MVArs to go slightly negative; if grid voltage goes load, that can cause MVArs to go more positive. And, grid voltage can also be unstable when grid frequency is unstable.)

Again, hope this helps! You've asked some great questions--unfortunately, they are not easily answered. But, we try, and if you need more clarification--we're here to help with that, too.
 
A very comprehensive explanation!

Some mfg also provide a "pull-out" curve, along with the reactive capability curves. Usually in relation to the minimum excitation curves, ie, pole slipping area-not to be entered under any circumstances.

High leading power factors are usually associated with weather as cooler temps will cause the load to be more resistive in nature (strip heaters, etc.) Many utilities have elected to install reactor banks to mitigate this and protect the generators from higher reactive current.
 
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