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.

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.

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.

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.

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.

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 =j^2 = sqrt (-1) x sqrt (-1) = -1

Therefore, if we rationalize the denominator, then:

1/j0.4 = 1/j0.4 x j/j = j/ 0.4j^2

We know that j^2 = -1, hence:

j/ 0.4j^2 = j/-0.4 = -j2.5

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.

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

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. 

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.

Just remove all the circuits after the point at which you want to calculate the short circuit current and just attach Zload to it. Then solve it using a per-unit system and apply Ohms Law in the end.

LV Side:
When a line to ground fault occurs on one line on the LV side then all current will flow from the faulty line. Other two lines will have no current passing through them. Similarly, the line which is faulted will have zero volts on it while having rated voltage on other two lines.

HV Side:
Transformer will feed its maximum fault current which will eventually saturate the transformer with a slight decrease in the rated HV voltage.

In literal terms, the conductor passing through the window type CT does not have any 'turns'. However, the term 'turns' is extensively used in electrical engineering literature to refer to the number of times the current must travel through a similarly shaped part of the circuit. See the image in the link below which shows a solenoid, where there are 6 'turns' --or say 'identical portions' of the circuit, so in a circuit where there are no turns, there will only be one 'identical portion' for the current to pass through.

https://circuitdigest.com/sites/default/files/field/image/What-is-Solenoid.png

The term 'turns' has been adopted for use in several equations, one of the most famous being the transformation ratio of a transformer. To keep consistency with the existing literature, a single straight conductor is called having 'one turn'.

A single 3-phase transformer can be connected in Wye configuration to get a 4-wire system, 3 of the wires will be for each of the 3 phases, while the 4th wire will be used for a neutral connection.

A Burden is an estimation of load connected on the secondary side of CT (measured in VA). Ideally, a CT should reflect the current on secondary side as accurately as possible from the current flowing in the primary side.
However, this does not happen so because of the presence of magnetization current and other factors that generates an error in the reflection of current on secondary side (Discussed in part 2 and 3). Nonetheless, an effort is made to make this error minimal. CT measurement is close to maximum accuracy when the actual CT burden is equal to the rated CT burden.
The CT burden influences the accuracy of the CT measured value on the secondary side. Higher burden selection against the required burden results in CT measurement inaccuracy. For instance, if a CT designed for 15 VA burden is operated for 5 VA, there will be a higher error in its measurement even when the CT is operating at its rated current.
As to answer your question, the primary current of the CT is independent of the CT burden on the secondary side. Since the primary current depends on the load current flowing through the line.

It depends on which two HV Lines are lost. You will have to trace through the transformer connections to see if there are any HV windings that are energized. If there is any HV energized winding, then you can expect power to flow into the LV (Low Voltage) winding.

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.

perspective, it receives abnormal voltages and currents from two phases but little (or even zero) from the phase that was lost on the HV side.

We can define Zs as the maximum impedance due to a single line to ground Earth Fault (also called Earth Fault Loop Impedance). For the maximum fault current, I(fault) and nominal system voltage V, Zs can be calculated by the formula Zs = V/Ifault. Zs is calculated and used in Fault Analysis in power systems. Also, it can be calculated from the time-current curve of the protective device during protection coordination.

Typically for any an earth fault that would occur on the LV (Wye) side of the transformer, the impedance reduces and the current on the secondary side will increase causing the current in the primary side (Delta) of the transformer to be increased due to the cascaded effect and the current feeding through the upstream devices will also increase. The overcurrent protection devices will come into play to mitigate the effect of the fault.

In case you require a more specific response you can choose to specify the size in KVA and %Z of the transformer as well.

SIMOCODE is the flexible, modular motor management system for low-voltage motors. It can easily and directly be connected to automation systems via PROFBUS or PROFINET. It combines in just one compact system all required protection, monitoring, safety, and control functions. The motor management system thus increases plant availability and allows significant savings to be made for installation, commissioning, operation, and maintenance of a system.

Well, the answer to this question has many implications. To understand, the open phase condition in transformer is also called "single phasing". When it occurs the currents and the voltages on the primary and the secondary side of the transformer highly depends on the following:
- Transformer Winding (Delta, Wye , Delta-Grounded etc.)
- Transformer Core construction
- Transformer Loading

Usually, the detection of the open-phase or single-phase condition is difficult to detect. In fact, the ground overcurrent or negative-sequence over current protection may not even detect the open phase condition due to the symmetry and balance of voltages and currents. To do that a detailed analysis of the open phase condition is done, and certain methodologies are implemented to identify and understand the effect of single phasing in a transformer. 

To provide safety to the people in the work environment Arc Flash studies are done. Appropriate procedures and personal protective equipment are then employed to minimize potential injuries.
Calculating the Arc Flash currents, and Incident Energy Levels have a step-by-step procedure. The following link will give you an in-depth look into the manual Arc Flash calculation according to the IEEE (Institute of Electrical and Electronics Engineers) Std. 1584 2002:
https://myelectrical.com/notes/entryid/130/arc-flash-calculations-arc-flash-safety

A Maintenance Switch is a toggle switch that is connected to the upstream protective device (relay or trip units) having the "Maintenance Mode" option. The maintenance mode makes use of a different trip setting that reduces the interruption time as compared to the standard instantaneous protection. When the switch is manually operated, the maintenance switch turns the upstream breaker function to "Maintenance Mode". Under this setting, the protective device can improve the operating safety conditions by reducing the fault clearing time thus lowering the incident energy levels.

In summary, the maintenance mode or switch changes the settings, so it is sensitive to the change in current. Typically, the protective device (relay or breaker) operates on the lowest set instantaneous setting. If a fault were to occur, the protective device would operate fast without worrying about coordination. The speed of device operation reduces the incident energy levels significantly...  and it enhanced safety... When personnel is working on a gear, the maintenance mode/switch would be "turned on" until the work is finished.

To answer the first part of your question there are several factors and parameters considered when we can call Arc flash Hazard. For example, arc flash and incident energy levels produced by it differ according to the equipment, voltage at the bus it is type and equipment type. Similarly, when we talk about the power sources, we are referring to the voltage levels and current which are first use in calculating the Short-Circuit-Current and this value of the current is used to calculate the Arc Flash Hazards. For more details you can refer to the article on 

IEEE Xplore: "IEEE Guide for the Specification of Scope and Deliverable Requirements for an Arc-Flash Hazard Calculation Study in Accordance with IEEE Std 1584(TM)"

and the link: https://allumiax.com/blog/ieee-1584-2018-in-depth-arc-flash-calculations-using-mathcad-express-etap-19-0-extensive-results-comparison?highlight=WyJoYW5kIl0=

 Secondly, although our understanding of the Arc Flash has expanded in the recent years but most of the work is done on AC arc flash. Moreover, 2002 IEEE 1584 standard includes only AC arc flash hazards and no standards for the calculation of DC Arc flash. However, NFPA (National Fire Protection Association) 70E Arc Flash standards 2012 and 2015 extracted significant information from the paper: "Arc Flash Calculations for Exposures to DC Systems" and "DC-Arc Models and Incident-Energy Calculations". It conclusively mentioned that the maximum possible power in a DC arc flash occurs when the arcing voltage is 50 percent of the system voltage. Also, since we must know the Arc Flash Energy levels which matters most, whether they occur into the AC or DC power system, but their method of calculation is surely different.

Radial distribution and other distribution schemes are not usually considered in calculating the relay settings. Once the system distribution scheme is set up and relays are placed, relay settings are then configured according to the voltages, fault currents, loads, sources, and equipment protection. These settings have certain features which ensures desired selectivity, sensitivity, speed, and safety of the system.

Relays, in general, are switches which can make or break the circuit to serve the crucial purpose of protecting power systems. They can be electronically or electromechanically operated. Advancement in relays have enable them to perform several tasks which include:

• sending trip signals to circuit breakers when required (e.g., in case of fault current)
• acting as the brains of overcurrent, differential, earth fault, distance various other protection schemes
• acts as an interface between high power loads and control circuitry
• control and operate switches and other electromechanical devices remotely at large distances
• programmable/ numerical relays incorporate microcontrollers which can be programmed to achieve the desired objective and level of protection

Single Line Diagram is per phase representation of a three-phase system. It is a simplified notation of a three-phase system, that is why it is also known as One-Line Diagram.

Pre-fault voltage is the voltage of the system (particularly at the location of fault) when normal load current is flowing through it. The system voltage will be at the pre-fault level until any fault current starts to flow through it. The term 'pre-fault voltage' has no meaning in the context of distance relays. The general concept applies everywhere in the power systems.

Yes, we can lump the generators and transformers for circuit representation, but it also depends on the type of circuit or say its application.

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.

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.

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.

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.

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

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