Generator short circuit current 1

[Mbrooke]

How do you find the short circuit current of gensets paralleled through GSUs? Something like 10 250 MVA units. No external sources.


My understanding is that a fault further away will slow down the generators, but a fault close by will speed them up until cleared.

 

[waross]

The Available Short Circuit Current at the generator terminals will be determined by the Subtransient Reactance, the Transient Reactance and then by the reactance.
Add to that the DC offset due to X:R ration and point on wave switching.
The current will be highly reactive and the load will be in KVA.
The action of the engine depends on the real load which in turn depends on the resistance in the fault circuit.
The real load on the set depends on the real load in kW.
For a fault on the terminals there will be very little resistance and thus little kW load.
As the fault becomes further away the resistance of the conductors adds to the I²R and the load increases.

but a fault close by will speed them up until cleared.

Yes but limited by droop action. Limited by the droop setting of the governor.
The limits may be 3% for an islanded set and 5% for a grid paralleled set.
Voltage collapse and the age of the set.
Self excited sets, generally very old sets, are subject to voltage collapse.
This will drop the fault current.
In a case of severe voltage collapse, the fault current may not be enough to trip the generator main breaker.
Some self excited sets were fitted with field boost circuits.
CTs on the generator output would be used to supply a boost to the field and so avoid voltage collapse.
Newer sets with Permanent Magnet Generator supply to the AVR are not as prone to voltage collapse.

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

 

[Mbrooke]

Thanks

Steam turbine, synchronous generator.

 

[Mbrooke]

Anyone know the typical Xd?

I want to know the short circuit of 12 high side GSU paralleled 250 MVA steam generators.

 

[Bill West]

I'm not a system planner, but I think the available short circuit current would principally depend on:
-the generator impedance
-the transformer impedance
-the HV system voltage

For a network these would all be chosen by the customer vis-a-vis his needed stability with the rest of the network and between the units within the station. He also balances low impedance's higher gen/tfr/line cost with its higher CB cost.
For an isolated station the question is just stability between the units and the costs.

For a curiosity study you can work backwards. A quick Google for ABB 500kv circuit breakers brought up brochures showing 40 to 80ka interrupting capacities. That can be back figured to an impedance for each generator/transformer set.

Bill

 

[waross]

Does this help?

X”dv: Subtransient reactance in percent on generators MVA base. Most synchronous generators have subtransient reactances in the 9-20% range1. The subtransient reactance is used for ½ cycle, 5 cycle and 30 cycle short circuit calculations in accordance with ANSI Standards.

X’dv: Transient reactance in percent on generators MVA base. This value typically ranges from 15-30%. The transient reactance is not used in ANSI standard calculations except for hydro and salient pole generators without amortisseur windings (Xpu = 0.75X’).

X0v: Zero sequence reactance in percent on generators MVA base. This value may range from 3-15% for typical generators. Zero sequence values are used in all ground fault calculations.

Xlr: Locked rotor impedance for induction machines. When actual data is not available, use 16.7%.

Easy Power link]

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

 

[Mbrooke]

Big help, much appreciated



@Bill West: Spot on. Typically the short circuit current typically is 20-60ka (some 80-90ka in New Jersey) in a grid connected system but I'm trying to wrap my brain around an islanded system. Fault current would be less in theory, but also the frequency would change in theory changing everything in the process.