Part 1 — Electrical Engineering Queries Asked by Our Valuable Students

Q1. How to choose the right circuit breaker based on the trip time-current curves?

In order to balance the right amount of overcurrent protection against optimal machine operation, we need different trip curves. Selecting a circuit breaker with a trip curve that trips too soon can result in nuisance tripping. Choosing a circuit breaker that trips too late can result in catastrophic damage to machine and cables.

The X axis represents a multiple of the operating current of the circuit breaker and The Y axis represents the tripping time.

The three major components of the Trip Curve are:

1. Thermal Trip Curve: This is the trip curve for the bi-metallic strip, which is designed for slower overcurrent to allow for in rush/startup, as described above.
2. Magnetic Trip Curve: This is the trip curve for the coil or solenoid. It is designed to react quickly to large overcurrent, such as a short circuit condition.
3. The Ideal Trip Curve: This curve shows what the desired trip curve for the bi-metallic strip is. Because of the organic nature of the bi-metallic strip, and changing ambient conditions, it is difficult to precisely predict the exact tripping point.

Trip curves represent the predicted behavior of a circuit breaker in ambient room temperature. This means when the bimetallic strip is within the specified ambient operating temperature for the breaker. If the breaker has experienced a recent thermal trip, and has not cooled down to the ambient temperature, it may trip sooner.

Trip Curves predict the behavior of circuit protection devices in both slower, smaller overcurrent conditions, and larger, faster over current conditions. Choosing the correct trip curve for your application provides reliable circuit protection, while limiting nuisance or false trips.

Q2. How to calculate the neutral current in an unbalanced system?

If the 3 phase currents are equal to one another, then the neutral current will be equal to zero. However, if one of the phase current is different than the others, the neutral current is then equal to the difference between them. The real and imaginary both parts of the current will be added.

A detailed calculation of neutral and phase currents and voltages in an unbalanced 4 or 3 wire system can be done by applying Kirchhoff’s voltage law on all 3 phase loops.

Q3. What are surge arrester types and their tier applications?

Type 1,2, 3 and 4 can alternatively be called Type A,B,C and D surge protection devices:

• Type 1 (Type A) SPD: The Type 1 SPD is recommended in the specific case of service-sector and industrial buildings, protected by a lightning protection system or a meshed cage. They are also intended for installation between the secondary of the service transformer and the line side of the service equipment overcurrent device, as well as the load side, including watt-hour meter socket enclosures, and are intended to be installed without an external overcurrent protective device.
  It protects electrical installations against direct lightning strokes. It can discharge the back-current from lightning spreading from the earth conductor to the network conductors.
• Type 2 (Type B) SPD: The Type 2 SPD is the main protection system for all low voltage electrical installations. Installed in each electrical switchboard, it prevents the spread of over voltages in the electrical installations and protects the loads. connected Type 2 SPDs are intended for installation on the load side of the service equipment overcurrent device, including SPDs located at the branch panel.
• Type 3 (Type C) SPD: They are installed as a supplement to Type 2 SPD and in the vicinity of sensitive loads. Type 3 Point-of-Use Surge Protection Point-of-use surge protectors such as surge receptacles are installed within 30 ft of conductor length from the service panel and are designed to offer premium surge protection for specific electronics while providing innovative features to enhance user convenience.
• Type 4 (Type D) SPD: Type 4 SPDs may be intended as Type 1 SPDs, Type 2 SPDs, or Type 3 SPDs and must be considered based on their intended application.

For Type 1, Type 2, and Type 4 SPDs, the manufacturer shall specify (declare) the value of Nominal Discharge Current to which the sample will be tested. The Nominal Discharge Current value selected by the manufacturer shall be as follows:

• 10 kA for Type 1 SPDs or Type 4 SPDs used for Type 1 SPD Applications
• 3 kA, 5 kA, or 10 kA for Type 2 SPDs or Type 4 SPDs used for Type 2 SPD Applications and, optionally, for Type 3 SPDs

An additional Nominal Discharge Current value of 20 kA for Type 1, Type 2, and Type 4 SPDs is provided in other standards ANSI/UL 1449–2006 [B2]; however, due to the scope of this standard and harmonization with IEEE Std C62.41.2–2002, the values in this standard are limited to 10 kA maximum.

Type 4 SPDs generally have conditions of acceptability dictated by the national regulatory body that would require Type 4 SPDs to undergo this testing when installed in its final form in its intended application. However, it may be acceptable to submit Type 4 SPDs to these tests.

Q4. What is the role of maintenance in Power system planning? What type of maintenance required and how to calculate cost and other factors related to it?

There are many objectives of equipment maintenance plans in power systems. It is done for cost optimization, increasing system reliability, increasing life span and durability of equipment & safety of personnel and equipment. There are two major types of maintenance:

1. Corrective: After failure occurs
2. Preventive: Regular maintenance to prevent future failure

For the next part of your question. In order to plan your budget for equipment maintenance following factors should be considered so that the equipment maintenance can be done in the timely and cost efficient manner:

• Availability of skillful maintenance worker
• Tools and equipment for maintainability
• Spare stocks for backup operations
• Maintenance policy
• Environmental factor (weather, size, working conditions)
• Systematic maintenance data collection, analysis and continued reliability study
• GMS (generator maintenance schedule) and TMS (transportation maintenance schedule) using different algorithm

When considering your overall maintenance plan and frequency of test intervals, the following ten factors should be included in that decision-making process:

1. Equipment criticality and device significance
2. Current condition
3. Lubrication life
4. Maintenance history
5. Operational history
6. Industry experience
7. Maintenance philosophy
8. Operating environment
9. Time allowed for maintenance
10. Manufacturer’s recommendations

Having an understanding of these ten factors, and using them as critical decision points, can greatly enhance your ability to accurately judge the frequency at which you maintain your equipment.

Q5. What is the meaning of zero sequence in a power system?

Zero sequence current provides a unique and various prospective for the power system. One prospective is that it tells how how much unbalance we have in the system. Another prospective is that it measure the fault current magnitude for a one-line-to-ground fault. We highly recommend watching “Fault Analysis in Power Systems — Part 1” which will walk you through the various faults and how symmetrical components are used to interpret and analyze the faults.

Q6. How does 1/J0.4 becomes equal to -J2.5?

The ‘j’ operator used in engineering denotes the complex number operation when attached with any number. It can be simply considered as a basic imaginary number ‘i’ iota which is equal to the sqrt (-1). In electrical circuits +j shows that a phase advance of 90 degrees and -j shows the phase retard of 90 degrees.

We can simply convert 1/j0.4 to -j2.5 by using the basic imaginary number laws and operation:

We know that:

j x j =j² = sqrt (-1) x sqrt (-1) = -1

Therefore, if we rationalize the denominator, then:

1/j0.4 = 1/j0.4 x j/j = j/ 0.4j²

We know that j² = -1, hence:

j/ 0.4j² = j/-0.4 = -j2.5

Q7. What happens to the sequence currents when there is a SLG (Single Line to Ground) fault in the delta configuration?

By the rules of Delta, there is no ground which means there is no support of 0 sequence currents. But when there is an SLG or an LLG fault, ground is induced in the delta-connected system and this would mean that the delta side will follow the same method.

Q8. What if the CTs (Current Transformer) employed in delta configuration don’t have the same ratio? What ratio should we use? Should we use the average?

All the CT’s that will be used in making of Delta connection needs to have the same CT (Current Transformer) Ratio and Burden. It is an obligation. Our blog will help you in this regard: https://allumiax.com/blog/current-transformer

Q9. Explain the meaning of zero sequence in a system?

Zero sequence current supplies a unique and various prospective for the power system. One prospective is that it tells how much unbalance we have in the system.
Another prospective is that it measures the fault current magnitude for a one-line-to-ground fault.

Q10. Why are we neglecting voltage loss due to the resistance of the transmission lines?

We have assumed the voltage drop due to resistance of the transmission line as negligible. The goal is to keep the per unit calculations simple and easy to understand. When we analyze complex transmission models at a professional level, we do consider voltage drop due to resistance.