Part 4: Electrical Engineering Queries Asked by Our Valuable Students

Q1. Breakers that can decompose the unbalanced set of phasors to their respective sequence components are electronic breakers. Is there hardware inside the breaker that can do this and thus, correctly diagnose what kind of fault is on the system?

Circuit breakers do not have the ability to decompose a set of unbalanced phasors to their respective sequence components and neither do they diagnose the type of fault. Circuit breakers only sense the current magnitude and then trip.
Electronic breakers, however, have a wide range of adjustable long time, short time and instantaneous (LSI) settings to provide better coordination and protection.

Q2. Why when performing KVL on the negative and zero sequence networks, the initial voltage is zero? Is it because we are considering each network separately? I fail to see how math works if we consider the full faulted sequence network as one continuous loop/circuit since, by the logic, there would be two node voltages that are both zero despite not being physically connected?

The negative and zero sequence circuits do not have a voltage source, or you can say that their pre-fault voltage is zero. This is because synchronous generator sources are designed to generate balanced voltages only i.e., positive sequence voltages.

Now, if we consider each network separately or consider a continuous loop. The initial voltage for negative and zero sequence parts will remain zero and will be represented by a short circuit

Q3. Why are we not considering the transformer impedance when referring to HV side while calculating the sequence voltages?

According to KVL, if transformer impedance is included that would give us the voltage after the transformer that is, the LV Side. But since we are calculating sequence voltages, immediately before the transformer that is why transformer impedance is excluded. Similarly refer to the Reactance diagram above, if fault occurs on point 2 that is the LV side of transformer, and its sequence voltage is reflected on HV side then 0.08j will not be included. As to your second point, the fault current value has been reflected on HV side both in terms of Magnitude and Phase angle (See part 4c). So, fault current value already accounts for transformer impedance.

Q4. How much distance to be checked from fault distance (receiving from substation) if any fault occurred in EHV transmission lines?

From what we have gathered from your question, it is about fault distance tracing from the fault point to the substation.

For faults that occur on transmission lines, we use “Distance Relay” that not only isolate the fault, but also give the estimate of fault location to restore the fault.

The relay issues tripping signal when fault is internal to its zone and restrains from the issuance of tripping signal when fault is external to its zone.

Figuratively,

• Z Relay <= Z measured, Relay restrains from tripping
• Z Relay > Z measured, Relay issues tripping signal

Consider the figure above, where fault occurs after the substation on EHV transmission line.

Since the fault is internal to the zone, the distance relay will issue tripping signal based on the condition mentioned above. As impedance is directly proportional to length of EHV Tx Line, so when the fault occurs at point A, voltage at the fault point decreases. Similarly, current increases exponentially and measured impedance becomes lower than relay set point impedance. This ensures that relay sees the transmission line shortened as before.

Q5. How to do primary injection test to verify the CT polarity of the other circuits with a reference circuit in the substation (refer to page 351 to 354 of the book Practical Power System and Protective Relays Commissioning by Omar Salah Elsayed Atwa).

There are several ways to test CT polarity and primary injection testing is certainly one of them, however not common. In my mind, primary injection testing would involve running current through the apparatus in which the CT is connected to. For example, if we a donut style CT measuring current through a cable, then we need to primary inject current into the cable. If we have a CT connected to the bushings of the transformer, then we need to inject current through the transformer. This can become expensive and very quick.

By far, the most common and practical method for CT Polarity testing is through a dedicated testing unit like the Megger MRCT or something equivalent. These units have special ways and algorithm to inject current on the CT secondary side (as opposed to primary injection) to determine the polarity and many other things. I would highly recommend down

The easiest way to determine CT polarity is through a Microprocessor-based protective relay and using a metering command. The equipment and apparatus are connected such that power flows from the source (utility) to the load (customers). And it is very typical to have CTs (Current Transformer) designed such that they see a positive current value on the relay during normal operating conditions. So, if have a CT polarity is swapped unintentionally, there is a very high chance that the metering command will show a negative value for normal power flow.

I know this is a lot of information without referencing the textbook but hopefully, it gives you context around CT polarity and testing methods to get more ahead with your work..

Megger MRCT: https://megger.com/current-transformer-excitation,-ratio-and-polarity-test-set-cter-91

Q6. Explain How non-SCADA coverage areas in power system operations could be supervised and controlled?

Non-SCADA coverage areas can be supervised and controlled locally onsite with microprocessor protective relays and advanced controllers or personnel who can respond quickly.

You will get more value with SCADA connectivity (remote monitoring & control) but if coverage is not available, then local supervision and control can still be performed by relays and advanced controllers like mentioned. Systems were monitored and controlled locally with a dedicated staff on property before the days of SCADA availability

Q7. What is the secondary connection of the connected CT to the Star / delta power transformer?

Diagram below shows the connections of the CT’s connected to transformer Star-Delta configuration (ignore the relay protection scheme). It is a normal practice to connect CTs in Star/Wye when the transformer is delta connected and CTs are Delta connected on the side where transformer is Y connected. Flipping the whole circuitry (including CT’s connection) horizontally will make it Star-Delta configuration.

Q8. How to wire a ct in delta for a tx secondary star winding for a differential relay?

We would like you to have a look at the following snapshot taken from the Book “Practical Power System Protection” by Hawitson, pp. 218. It will give you a good idea of how to connect CTs in delta for a transformer’s star winding incorporated in differential protection scheme: .