Here's my simple question...

In one of the LinkedIn groups I belong to, somebody asked "How do I set this 50/51 relay?". A very simple question, no? The following is the list of questions that I feel need to be answered, or data that needs to be provided before somebody should attempt to answer that question.

What Grid Code or Mandatory Reliability Standards do you need to adhere to?

Grid Codes and Mandatory Reliability Standards set the extremes of the envelope for what the protection engineer is allowed to do. The same system built in North America, Europe or China will have to adhere to different Grid Codes, and may therefore require different protection settings. Certain reliability standards, like TPL-001, may result in protection requirements (max clearing time, mostly) in order for the system to be operated beyond certain power flow levels.

What are your corporate protection philosophies?

Within the limits of Grid Codes and Mandatory Reliability Standards, each company then sets their own philosophies of how they wish to build and set protections. Some of this is for the sake of consistency, some is to account for unique characteristics of the system in question, and some is a reaction to various past disasters. Internal protection philosophies and standards answer these questions and many more.

• Do you use 1 A or 5 A CTs?
• What are your standard coordinating margins?
• How much resistive coverage do you require for line protection ground faults?
• At what MVA rating do you start using dual differential relays on transformers?
• At what voltage do you stop using phase overcurrent elements on line protection?
• Identical or different A and B protection packages?
• Does breaker failure protection trip adjacent breakers or trip into adjacent zones (if adjacent breakers, does a breaker failure trip initiate breaker failure protection on these breakers? If adjacent zones, does it trip into A and B protections or just one)?

Provide a full protection one line of the substation in question.

This will allow the protection engineer to determine all the protection zones (and ensure that they are all protected), and will also provide CT and PT ratios. Equipment ratings also need to be here, so that you can ensure that your protection settings can carry the system load.

Provide a system one line showing the substation in its context. Include extra detail on connected substations if necessary.

In the question that was asked, the person asked about how to set the 50 element on a line backup protection. If the line was short, you could find that once you add enough margin to not trip on an out of zone fault, that there would be insufficient current to trip on an in zone fault. In a case like this, under certain circumstances (if your grid code and protection philosophy allowed it), you could consider applying an overreaching 50 element. For example, if you had a short line that terminated in a transformer, with no other tapped stations, you could consider allowing the line 50 relay to trip for faults partway into the transformer, as long as the transformer protection would also trip instantaneously for the same fault. This buys you fast protection on the line at the expense of taking out an extra element in the event of a rare transformer fault, but there is no additional loss of load, generation or system integrity, so your protection philosophy may allow that. However, if the line terminates in two parallel transformers, you may not be able to set a 50 element, because then a transformer fault will result in effective loss of both transformers.

System fault model and existing protection settings at least two buses away from the station in question.

You need to do a system coordination study in order to determine the new relay settings (and possibly changes to existing relays as well). If a full system model is unavailable due to confidentiality issues, then you need a model that goes out at least two buses from the one where you are doing work.

Are there any unique operational requirements for the new system, or are there any special protection schemes required?

Operational requirements, or results of analytical studies can sometimes produce interesting protection and control requirements. Weak generation sources attached to long lines can result in zero or positive sequence resonances, which can then require the generating plant to be tripped offline before the remote (system) terminal of the line is tripped. System stability criteria may require line clearing speeds under a certain number of cycles (which could result in a 51 relay being utterly inappropriate).

The last set of relay calculations for this station.

This one is a bonus, and for many engineers working for consulting companies, is something they may never see. However, if the previous set of calculations is well written, they can be a gold mine of understanding. A well written calculations file will not only document what was done, and why, but should also shed light on what was not done, especially when non-standard or less than obvious paths were taken.

OK, now I'm ready to answer your simple question...