Instantaneous Settings of Feeders

What I see from utilities is a substation with 2 or 3 breakers feeding a distribution feeder at 11kv, 12.46kv or 13kv. If you have an inst setting on a breaker, you will see an operation if a branch touches the feeder or squirrel get into the phase conductor or anything like this. You can make the choice to use a time delay setting on the breaker to reduce the inst outages.

Let me add more information. The question refers to cable and overhead line feeders as well. The feeder generally has many 11/0.4kV substations downstream with 11kV side breaker or Hv fuses. But with instantanoeus setting at the feeder head, the whole coordination with downstream stations is upset and even for a fault in one of the 11/0.4kV transformers, whole feeders trip.

So why to set instnatneous at feeder head?

With an Instantaneous Settings, anytime you have any kind of a fault you will trip the breaker and have power interruptions. The inst setting is for temporary faults on taps off the main feeder. The thinking is that the reason for the fault will clear and the breaker will re-set. You may want to consider removing the inst setting one the breaker if the interruptions are causing customer complaints.

"They justify this saying it operated because the fault current was very high!!! I am surprised so what?"

That is not why you have the inst setting. The fault is what it is. How high is high. If you remove the inst from the breaker you will delay opening the breaker by what ever the timing is. You probably would operate the primary fuse to the transformers. You can check to see if the breaker and fuse coordinate.

Well you have discovered that different utilities have different approaches to feeder protection. I will give a few comments and suggest that you find out how your protection scheme is designed to work.

Low set instantaneous relay (LSIR) setting: This relay does not coordinate with any downstream devices and is typically set at a low current rating. This is commonly called the fuse saving scheme. The LSIR will operate the feeder breaker for faults above it's setting. The breaker will then reclose instantaneously. Everybody is happy if it was a transient fault. Everyone is happy if their equipment can ride through a momentary interruption that is. If it was a permanent fault then the appropriate protective device would now operate. Due to customer complaints since the introduction of electronic consumer devices, many utilities have turned off the LSIR allowing downstream fuses to operate creating a permanent fault for a section of the feeder.

High set instantaneous relay HSIR setting: This relay also does not coordinate with all downstream devices. Depending on the fault current the downstream fuse may operate before the HSIR. The HSIR pick-up is typically set at at very high current level. This protects equipment from high fault current by getting the fault off the system very quickly. The feeder breaker may or may not reclose on this case since you do not want to subject your system to repeated doses of high fault current.

Cable Feeders: Typically a feeder composed of all underground cable does not reclose for faults.

Fault current: I recommend you study up on what fault current can do to electrical equipment so you will understand why it is important to remove fault current from the system quickly.

The line protection scheme employed by any utility must meet the needs of the customers and the utility. Comprises must frequently be made.

The use of 51 only protection will provide the needed coordination for distribution transformer primary side faults, and will result in only the faulted circuit being disconnected from the system, which is very good design. The operating time of the 51 relay will determine the duration of the voltage dip experienced by customers on other healthy circuits. If the Utility has a restriction on the fault clearing time, then the Time Dial of the inverse curve can be set accordingly. For low-level faults the pickup setting of the 51 relay must be set to detect these levels as well. If you clear in 300-400 msec, you should ensure that the 51 curve lies to the left of the 11kV feeder cable damage curve(if UG cables are used), when coordination curves are plotted for the 51 relay and the cable.

I was offline for some time, but I see the discussion during this time was very good.

Some of the participants even suggested me to understand what highfault current can do. What I see is that these are already cosnsidered during the busbar/breaker/transformer rating/short circuit capacity design. There are various standards for those. If some thing is wrongly in done those, it is very difficult to take care of such issues by relay settings. The discussion here is where the shortcircuit currents are within the capacity and those are SF6 breakers.

In this circuits there are no reclosures. And if we go on interrupting the other curstomers, that is not a good scheme.

What Ripple suggested is what I did in earlier utility, used only 51, coordinated considering the maximum fault current, ensuring that those do not exceed the equipment rating. It was working well rather fantastic.

Any further comments.

You can also consider the use of Instantaneous with delay (Definite Time) in place of the 51 or in addition to the 51. The ABB MSOC relay offers both functions (51 and 50 with Delay to be used together). In this way you can set the delay to override transformer inrush time on the feeder and at the same time allow all downstream fuses first opprotunity to clear faults on their respective transformer primary side. The 51 pickup can be set above the pickup current of the largest down stream fuse, the 50 pickup set below minimum fault current at primary terminals of most remote(distant) transformer, and the delay can be set at 0.3 sec. This will allow dowstream fuses to clear transformer primary side faults, while upstream feeder breaker waits for 0.3 sec before it trips. In this way, anytime the upstream feeder trips on the 50 function, the voltage dip is limited to 300 msec.

Certainly the tefinite time element is also a consideration, when the fault level variation acorss the feeder length is not much.

Let me put some light on the way I set instantaneous element. Instantaneous element is set at breaker (A) only when the fault level at next downstream breaker or fuse (B) is half of this or less. IfB is less than half of IfA. The instantaneous setting at A is then 1.3 times IfB. If the above criteria is not satisafied, I do not set the instantaneous relay. And in most city systems, the above criteria does not satisafy and hence relays are set with only inverse curve (51).

Further, the tranformer HV side instantaneous setting is 1.3 times the through fault current of the tranformer (i.e. 1/Xt mutilplied by 1.3).

If I set the instantneous with criteria such as 16 times CT rated current etc and then justify uncoordinated tripping saying the fault current is high, the coordination is uspet especially when the tranformers are parallely operated and fault currents are high but within the rating of bus/breaker. I am very mcuh able to avoid this situation by my approach.

However, there is one point, which some participant told in this thread, that the transformer gets stressed during fault. Per IEC60076, the transformer shall withstand the bolted fault current for 2 seconds. And typically such faults should get isolated in 0.3 seconds by 51 curve. However, what is the cumulative effect of many such faults is a subject which is not specifically addressed in most protection setting philoposhies.

The real measure is how does your protection design perform? How many breaker failures, transformer failures, other equipment failures occur using your protective scheme versus the national or international failure rates?

What is your customer favorability rating versus the norm?

What are your feeder reliability indices versus the average feeder?

I am not suggesting that you share your data here but use it to evaluate your protection philosophy.

Could somebody tell what is the typical maximum time delay one has assigned during protection coordination at 11kV feeder head breaker and also at 11kV breakers at 11/0.4kV distribution substations, either by means of inverse curve or by definite time????

Hi,

I place here snapshot coordination of over current relay (IDMT curve + definite instantaneous curve) for 8 relays. In order to get at least 0.3s discrimination, tripping time for instantaneous relay need to be adjust. If not, problem mention in first post in this thread where upstream relay tripped when fault occur at downstream.

I have one question, how far I can adjust the instantaneous time. Now I put inst. setting for relay OCR1 at 0.5s. Can I adjust to 2.5s since the breaker can withstand 20kA fault current for 3s so that I can set another relay (OCR11, 17, 23) to have discrimination 0.3s. Maybe someone can share.

Info: Relay OCR1 & 2 are 11kv

another relays are 0.415kv. Stepdown tx 11kv/433 connected between OCR2 and OCR5.

-madie