For low voltage equipment I generally see the pass/fail at 1 megohm, with I think comes from a NETA (inter-National electrical testing association) testing guideline. I don’t remember the section, if you’re interested I can go back and find it and get you the reference.
Casey
In larger machines originally WECC, and now NERC, require validation of those generator parameters to ensure accurate grid stability models. System protection also uses them to provide accurate fault currents in system fault programs such as ASPEN Oneliner.
However, NERC registration starts at...
There are various reasons why a designer chooses different VT grounding methods:
- the grounding of the power system neutrals can be different.
- the protection methods are different
- different sets of VTs are used for different things.
- design standards from different engineering groups favor...
Biggest impact of LTCs I think of on IBRs is the loss of VAR capability at high voltage. If the taps aren’t set right the VAR capability can be severely limited. Right now for that reason I plan to set the LTC in our new wind farm to manual - I just don’t see much value in the LTC anymore with...
I’m working on relay settings for a type 3 wind farm. According to the manufacturers literature, the rotor inverter controls the fault current of the generator unless the voltage across the electronics get too high, then a crowbar operates to short the rotor circuit and protect the rotor...
Here’s how I think I would go about calculating losses and seeing if I could get some savings in energy:
Let’s think about the generator only (put a reactor off your switchgear) for simplicity.
This is how I would go about it:
Losses are I^R.
If you get the R off the generator datasheet...
Generally you want fast acting governors and AVRs to maintain consistent voltage and frequency to the load. I wouldn’t advise block loading or PF mode.
(The US western grid tried something similar in the 1990s and dumped California in the dark. It was shortly after that PF and VAR modes were...
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.
