Sustained Short Circuit Current from Synchronous Generator

[George556]

I work for a power utility. Due to work on a distribution circuit, we will temporarily be carrying a portion of a 16kV distribution circuit with a diesel generator since the main source will be disconnected.
The generator is 480V and there is a step up transformer (delta on 480V, Wye Grounded on 16kV). We have a recloser on the high side of the bank to protect for a fault on the circuit.

The vendor provided specs for the alternator which included Xd = 2.99pu, X'd = 0.17 pu, X"d = 0.12 pu. They also provided time constants of T'd = 0.135s and T"d = 0.01s. As a Protection Engineer, I thought I would have to trip very fast (under 0.135s + 0.01s) to be able to clear faults on the line because if I wait for it to go to steady-state, there won't be enough fault current for the recloser to trip when Xd = 2.99pu. The fault current ends up being about 33% of full load capability.

However, the vendor pointed out that the Spec Sheet also says the Alternator is separately excited by a Permanent Magnet Generator and there is also an AVR for Sustained short circuit for 10 seconds. The Spec Sheet shows a Short Circuit Decrement Curve of the sustained short circuit for a fault on the terminal of the alternator. This shows that sustained fault current is about 300% of Full-Load Current.

In literature I found that:
The steady-state fault current could either be around 0.5 x Full Load Current if there is no field overexcitation or if the generator is equipped with maximum field excitation, the "surge" voltage will cause the fault current to increase for 10 seconds to about 300% of the full load current.

We use a Short Circuit program for modelling so the vendor is recommending that I manipulate the value of Xd on my short circuit program to be able to get a value of the sustained short circuit current seen at the alternator based on the Short Circuit Decrement Curve on the Spec Sheet. Then, use that new Xd value to check end of line fault current (including the transformer and line impedance).
They also have an Application Guide that mentions "no effort should be made to determine the level of steady state fault current level by a calculation using the alternator’s advised value for the synchronous reactance (Xd). An alternator’s actual sustained short circuit level is displayed on the individual Decrement Curve for that alternator design."

The vendor recommends setting the Recloser setting high enough to avoid cold load pickup during energization. With their recommended settings, an end of line 3ph fault takes about 0.5 seconds which meets our protection criteria, but initially I thought the generator wouldn't have fault current after the Transient and Sub-Transient period.

I am leaning on going with the vendor's recommendation since they say with their equipment they are able to sustain a short circuit for 10 seconds. Have you ran into this before or have any thoughts?

 

[waross]

Does the generator have a main breaker?
If so, will the main breaker trip on fault current?
How far can you push the generator excitation?
The old school solution, before PMGs became common was a set of CTs with rectifiers that would provide a boost voltage to the generator field.


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

 

[SolarPrestige]

I am familiar with the fault current ratings you are talking about, and the difference that having a PMG excited generator will cause. With the PMG installed, you want to be using the decrement curves that have been supplied.

 

[dpc]

As mentioned, most small generators have some sort of excitation boost to sustain the fault current output at something like 300% of FLA. The Xd synchronous reactance can be used only assuming constant excitation, which probably won't be the case.

If you want to trip the generator off for system faults, an undervoltage relay will be more reliable.

 

[FreddyNurk]

Not quite so recent employment with a utility; they ended up with them using Voltage Controlled Overcurrent for feeder protection when fed by smaller generators.

Undervoltage is effective, but generally too slow (i.e. set for 5 seconds, but the generator falls over trying to feed the real impedance of the transformer, lines and fault, and you lose the set rather than clear the fault).

VCO was meant to allow the current pickup to drop based on reduced system voltage, the catch is you need VTs somewhere to use it. I haven't been in that space for some 5 years, but as far as I am aware it was far more effective than blacking out the station rather than tripping the faulted feeder. It was implemented because even with allowing for the PMG to kick in was still either not enough fault current, or the set collapsed rather than feeder tripping. Most of the feeder faults were not close in faults, hence dropping the engine rather than unloading it.



EDMS Australia

 

[dpc]

I don't see a reason for a UV relay intended for system fault detection to be that slow. In my experience, they typically operated within a few cycles to trip the generator. They were fast enough to trip the generator off prior to fast reclosing. These are not the same as the undervoltage elements used for generator protection. The voltage-controlled (or restrained) overcurrent relays generally provide backup overcurrent protection. Since they depend on voltage drop to operate quickly, I don't see that much is gained in terms of speed. A properly set undervoltage element should be at least as fast.

 

[FreddyNurk]

Fair enough, the commentary above was related to feeder protection in islanded systems, and as such they didn't have a separate UV element for feeders, and you're correct dpc, the UV was generator protection, not feeder. The UV was also that slow (say, -5 to -10% of nominal for 5 seconds) in order to not cause spurious tripping due to load changes. The other reason I suspect it wasn't implemented in the systems I'm familiar with is UV elements rather than VCO on each feeder will result in dropping all the feeders whereas they were aiming to at least keep the non-faulted feeders on.

Different if there's only a single feed from the generator.

Having said all that, generators have nowhere near the voltage regulation ability of a much larger grid. Something much faster (say -20% of nominal within 0.1 seconds) would be useful in this context.
I don't have coverage on what larger networks would do for such things though, only small diesel fed systems.

EDMS Australia

 

[dpc]

Right, the UV approach for system fault detection works best for small generators connected to a larger grid. The voltage collapse is the best indicator of system fault.