that is a very interesting question - from the power grid perspective subtransient reactance and resistance provide damping to power system oscillations. I’ve only known that you have to watch out for it being too small and overdutying the connected interrupting device, but very curious how...
I understand my utility does exactly as you describe - neutral is tied to the transformer tank and to the vault ground, as well as the customer neutral (and by extension the customer’s ground)
My utility locates arrestors on substation equipment (transformers) and on underground terminations. I don’t believe we use them anywhere else - granted, we get very little lightning.
In my region, the western us, the regional planning entity (Western Electric Coordinating Council) has a guideline for frequency droop from 3-5%. We’ve set our larger hydros at 3% to improve the frequency response in our balancing area. Gas turbine droop typically is 4% and it’s trickier to...
Droop is your friend.
Use frequency droop. 3-5% is typical.
If the units connect to the same bus without transformers, assuming the units are in voltage control, use voltage droop to prevent the AVRs from fighting each other. You might use an external voltage setpoint once the units are online...
Good point, that would provide much better response for longer duration sags.
The high level study I mentioned earlier was using modeling tools (Aspen Oneliner).
We have not done it in my company, largely because I work in the generation side of a utility where we have 30MW to 200MW generators...
Well, I stand corrected - I should more accurately have stated it’s never come up in my utility that I know of.
Load imbalance, now that comes up all the time.
I wonder if it might be economical to increase the bus voltage during voltage sags rather than modify motor starters and risk stalling (I’m not sure how many motors you are talking about).
Synchronous motors/generators, synchronous condensers and STATCOMs can inject reactive power during low...
I would assume manufacturers would consider the worst case or most conservative case when designing switchgear - that the main bus can handle all the attached load. This would be common on a main tie main system - two 1200A mains with a 1200A tie supplying <1200A of load. Your situation is a bit...
I’m not clear what you are trying to do, but by your terms I am assuming you’re connecting to a distribution circuit. The utility assumes their lines are perfectly transposed, which they are not, but the voltage imbalanced caused by balanced load on a poorly transposed distribution circuit is...
Tripping an upstream breaker faster will reduce the process impact on the rest of the plant and reduce potential equipment damage by removing the fault quicker. I would tend toward fast arc detection relays unless I don’t have access to the upstream device or it’s a fuse.
100% flooded lead acid at my utility (medium sized US utility, about 1.2 million customers) for substation and generation control and relay systems. Require maintenance, but highly reliable, we had bad experiences with VRLA in the past (battery failure caused a coastdown without lube oil on a...
Parallel. The relay is measuring the voltage drop across the resistor to detect 3Vo to determine a ground fault or to polarize directional elements.
This set up with the resistor in the delta (in USA called a Broken Delta) of a PT secondary is ubiquitous on utility sized generating stations.
For utility scale generators we have examples of both at the company I work at, and operationally I don’t notice a difference. It seems more common to put the PTs in the switchgear with the breaker - often the gen and line PTs used for synchronizing are in the same cabinet.
In the generators I work at, which are mostly gas and smaller steam turbines, plus some medium sized hydro, vacuum dominates up to a 5000A ampacity, above that it goes to SF6.
We had some magnablast air breakers, and some of the older hydros had air breakers, and even a couple of oil breakers...
