Choosing the correct fault type is a vital skill to learn if you want to test a relay without changing settings, and find problems that traditional test plans can’t. Watch these videos to learn the basic characteristics for the most common fault types.
Three-Phase Faults
This video shows you what a three-phase fault looks like and how to simulate correctly.
Phase-Ground Faults
This video shows you what a phase-to-ground fault looks like and how to simulate correctly.
Phase-Phase Faults
This video shows you what a phase-to-phase fault looks like and how to simulate correctly. We also briefly discuss sequence components.
You can download the files mentioned in this video below:
How to Calculate Fault Magnitudes and Angles – PDF Version
Calculate P-P Fault Spreadsheet
Click “Mark Complete” below after watching the video so you can keep track of your progress.
Hi Chris
By simulating these fault current and voltages into the relay, multiple enabled protection elements(51, 46, 27…) will pickup and/or operate. Correct?
The goal is to test the elements without changing settings, and the best way to achieve that is to simulate the kind of fault that would occur in the real world. It is possible that another element may operate when you are trying to test another, but this is usually an indication that the relay is incorrectly programmed. Something that you wouldn’t discover using traditional test techniques when a spare output is programmed.
Sometimes an overlap in protection isn’t technically an incorrectly programmed relay, but an unintentional problem with the way relay settings are created. For example, you may find that you can’t test a 51G element because a 21G element operates first. This can happen because the design engineer used a coordination study to program the 51G and a system study to program the 21G. They probably have no idea that an overlap exists and may want to adjust the settings accordingly when you point it out. If the 51G will, in fact, never operate in those cases, what would be the point of testing it?
Thanks for the responses Chris.
Chris,
At 6:01 minutes of the Phase-Ground Faults video you show the residual current calculation equaling 4.666 @ 180 degrees, by my TI-89 vector addition, I came up with 4.666 @ -86.199 degrees. What did I do wrong when calculating the residual current?
You didn’t do anything wrong! You caught me being lazy. The voltage angle is always -180 degrees as shown in the following drawings:
I must have forgotten that I was dealing with current and had to actually do the math. I could have used the Manta as shown below, but the screen was already getting cluttered. You should be aware that as soon as you questioned it, I didn’t go to the calculator to figure out, I did a napkin drawing similar to one below and immediately knew that I was wrong. Nowadays, I’ll use the Manta Remote Console to do the math for me instead of a finding a calculator with phasor math. You can do the same with Omicron’s Sequence Component display and Doble’s Sequence Component Calculator.
For those wondering what we’re talking about. Hopefully I seamlessly fixed it in the video by the time you watched it so that this comment doesn’t make sense.
Thanks for keeping me honest Shaun!
Hi Chris,
Can you please explain the following:
1. Why magnitude of voltage is become smaller for faults occur close to PT location and bigger for faults occur far from PT location?
2. Demonstrate on omicron -Phase -phase fault, phase-ground fault and phase to phase fault?
Thanks
Joshua
1. The impedance to the fault is lower when the distance decreases, which means all of the connected generator excitation systems have to work harder to maintain the voltage and they have limits. Also, less impedance equals more current, which means more voltage drop. We cover in this in much more detail in the upcoming Overcurrent Relay Testing Seminar.
2. That will be covered later in the seminar.
Thanks for the question,
Chris
Hi Chris, I’d be happy if u can add elements such as line differential, transformer differential, distance & field failure/loss of excitation to the training program too.
Thanks.
dnccc
Thanks for the suggestion. All of those topics will be included in or are planned new courses. The dirty little secret of relay testing is that testing these elements are just variations on what has already been covered here, there’s just some extra math to turn it into the over/under current/voltage tests described here.
I’m looking forward to these new courses
thanks.
dnccc
I’m looking forward to getting them out of my brain 🙂
Dear Chris, what is the convention on direction when referred to earth fault? When it is said that an earth fault is in forward direction, do we refer the fault in forward direction on the line CT or the neutral CT? I notice that sometime neutral CTs are wire in reverse to the relay input but the setting is forward. Logically, the earth fault seen by neutral CT is the same reagardless of the fault location in forward or reserve in relation to the line CT right?
The convention in North America typically places the CT polarity mark away from the protected device so that a forward fault is current flowing toward the protective device. Therefore, The current during a fault on the protected device should into the polarity mark of the CT. The actual forward direction for a relay is a current flowing within +-90 degrees degrees of the phase voltage.
The image below shows the wiring for a transformer differential relay that is protecting the transformer. If a ground fault occurs on the power system, the Phase CTs and relaying would show a reverse fault. If the ground fault was in the transformer and a power source was connected to that winding, the phase CTs and relaying would show a forward fault.
The next image shows that the ground current always flows into the neutral terminal, regardless of location. So the ground current would flow into the polarity mark of the ground CT in the 745 relay above, which flows into the non-polarity mark on the relay. Therefore, all ground faults might be considered “reverse” faults because fault current flows into the non-polarity mark of the relay.
Notice that IG doesn’t change in the next two images. IG (Ground CT current) is always in the reverse direction. But IO (residual current) is forward when the fault is inside the transformer (protected device) but reverse when on the power system.
So the answer is “It depends on which ground fault current you are referring to, What CTs you are looking at, how the CTs are connected in the power system, and how the CT secondaries are connected to the relay.