03 PROT405 IndustrialPowerSystemProt r2

Industrial Power System Protection Fundamentals

Technical literature supporting this section:

P.M. Anderson, Power System Protection. New York: IEEE Press/McGraw-Hill, 1999.

J.L. Blackburn, Protective Relaying: Principles and Applications, 2nd ed. New York-Basel: Marcel Dekker, Inc., 1998.

S.H. Horowitz and A.G. Phadke, Power System Relaying, 2nd ed. Taunton, Somerset, England: Research Studies Press Ltd., 1995.

H.J. Altuve Ferrer and E.O. Schweitzer, III (Editors), Modern Solutions for Protection, Control, and Monitoring of Electric Power Systems. Pullman, WA: Schweitzer Engineering Laboratories, Inc., 2010.

IEEE Standard Definitions for Power Switchgear, ANSI/IEEE C37.100, 1992.

IEEE Standard Electrical Power System Device Function Numbers, Acronyms, and Contact Designations, ANSI/IEEE C37.2, 2008.

IEEE Standard for Relays and Relay Systems Associated with Electric Power Apparatus, ANSI/IEEE C37.90, 2005.

IEEE Recommended Practice for Grounding of Industrial and Commercial Power Systems, IEEE 142, 2007.

IEEE Recommended Practice for Industrial and Commercial Power Systems Analysis (Brown Book), IEEE 399, 1997.

Standard for Electrical Safety in the Workplace, NFPA Std. 70E, 2014.

IEEE Guide for Performing Arc Flash Hazard Calculations, IEEE 1584, 2002.

J. Buff and K. Zimmerman, “Application of Existing Technologies to Reduce Arc-Flash Hazards.” Available at www.selinc.com.

J.B. Roberts and T. Lee, “Measuring and Improving DC Control Circuits,” in 25th Annual Western Protective Relay Conference, Spokane, WA, October 13–15, 1998. Available at www.selinc.com.

E.O. Schweitzer and D. Hou, “Filtering for Protective Relays,” in 19th Annual Western Protective Relay Conference, Spokane, WA, October 1992. Available at www.selinc.com.

1PROT405_IndustrialPowerSystemProt_r2






Generally, short circuits cause very high magnitude system current (larger than the normal load currents).

Electrical system components (overhead lines, cables, transformers, etc.) have metallic conductors (wires) that experience this high current.



Any current (large or not) passing through a wire in free space causes a temperature rise in the wire. The energy comes from the current, for which the change over time (power) can be expressed with the following equation:

In the former equation, I represents the rms value of the current.

Part of this energy heats up the conductor; convection transmits another part of this energy to ambient. During normal load conditions, if we assume the current has constant rms (steady state), the wire temperature reaches an equilibrium. This means that the wire temperature T remains constant, and all the energy the current provides is transmitted to the surrounding medium.

For this simple system, the wire temperature as a function of time can be expressed as follows:

et

ei TeTTtT /)()(

2dWI R

dt



For a given material and a given set of constant environmental parameters, the temperature change of the wire depends almost exclusively on the wire size and the current magnitude (the rms value).

Expressed as an equation, the relationship is as follows:

The values Te, Ti, and strongly depend on the rms value of the current I.

et

ei TeTTtT /)()(



The expression for T(t) determines the evolution of this conductor’s temperature for an applied current of 100 A. The following copper data are used:

• Specific heat: C = 385 J / (kg • °K)

• Density: D = 8,940 kg/m3

• Temperature Coefficient: αa = 0.00394 1/ °K

• Resistivity: ρa = 1.72 • 10-8 ohm-m

Also, the equivalent convection factor, h, is considered to be 15 W / (m2 • °K)

The thermal time constant is given by:

Time constant: = 425.63 seconds 7 minutes

Continued on next slide . . .


2 4

2 3 2

• • •:

4 • • • 16 • • •a a

C D d

h d I


The equilibrium temperature is given by:

Equilibrium temperature: Te = 359.3°C

T(t) = (Ti – Te)e–t/ + Te

Note: The density is used to determine the mass as follows:

m = D V = m A L

V = volume in m3

A = cross-sectional area in m2

L = length in m

Notice in this curve that one hour after the current is applied, the conductor has already reached its theoretical equilibrium temperature.

PROT405_IndustrialPowerSystemProt_r2 8

2 3

2

1:

• •

4 • •

e a

aa

T Th d

I


For an insulated conductor, the insulation will experience the temperature increase.

Plastic insulation—such as that used in common cables—is instantaneously damaged if the temperature exceeds a limit value called the damage temperature (Td). This temperature is 150°C for common thermoplastic insulation.

If the current is large enough, the wire temperature could exceed the limit. The time td needed for the temperature to reach the limit is called damage time.



To explain the importance of speed in protection equipment, the diagram represents a brief overview of thermal damage.

The graph shows how an insulated conductor is damaged if a large enough current is applied. The damage time is the time required for a cable with a given current to reach a temperature at which damage occurs.

We can show (experimentally and analytically) that:

• The damage time is shorter as the applied current is larger.

• There is a current (Imd) that causes the equilibrium to equal the insulation damage temperature. Equivalently, the damage time for this current is infinite.

The curve obtained by plotting the damage time vs. the applied current is called the damage curve.



Time vs. current plots are widely used in protection.

The damage curve is also known as the thermal capacity curve, or the short-time thermal damage curve.

Notice (for example) that the cable rating or rated current is not the same as the minimum current Imd. The nominal current In (rating) is the current that causes the wire to reach the rated temperature of the cable in the steady state (equilibrium). This temperature, in steady state, is the value at which the manufacturer guarantees the useful life of the cable.

If a current with an rms value between Imd and In is applied to a given component, this current will reach an equilibrium larger than the rated temperature but smaller than the damage temperature. In this case, we say that the damage will occur over time. This means that the equipment will lose years of life (accelerated aging).



If the conductor studied in Example 1 were a stranded conductor with an annealing temperature of Td = 220°C, then the damage curve could be drawn after building a table and plotting the results t vs. I, as shown. The diameter and material are the same as in the previous examples.

It is important to note that this is a static curve. Each damage time is determined for a constant current value. Any variation of the current during the test or calculation will result in a different damage time.



The figure shows the difference between a damage curve obtained using an initial current of 0 amperes and a damage curve obtained using an initial current of 55 amperes.

For this conductor, with the same characteristics described previously, a current of 55 amperes causes an equilibrium temperature of 75°C. The ambient temperature is 20°C.



The Insulated Cable Engineers Association (ICEA) recommends the use of the formula shown above for insulated cables with copper conductors. In this formula, I is in amperes, T1 is the initial temperature, and T2 is the damage temperature, both in °C. Parameter A is the cross-sectional area in circular mils. See the IEEE Buff Book for a more complete description of the ICEA formulas.

Notice from the result on the previous pages that Kd is proportional to the square of the wire’s cross-sectional area. With this, the equation is as follows:

I2t = Kd = K′ • A2

(I/A)2 • t = K′

Notes

• The unit “mil” is sometimes used to describe a diameter of 1/1000 inches for a circle

• 1 circular mil (1 CM) is equivalent to the area of a circle with diameter of 1/1000 inches (a mil)

• 1 CM = [ / 4] • (0.001 in)2 = 7.854 • 10-7 sq. in. = 5.066 • 10-4 mm2 = 5.066 • 10-10 m2



The damage curves shown were calculated using the ICEA equation described previously.

Exercise: A 4/0 cable with the characteristics shown in the graph above is subject to a short-circuit current of 9,000 A.

What would the cable’s damage time be?

Answer: 1.50 seconds, approximately



For conductors without insulation, such as those in overhead distribution lines, the damage temperature is determined by the annealing temperature.

The figure shows the damage curves for stranded aluminum conductors with an annealing temperature of 200°C.



The figure shows a typical thermal damage curve of a distribution transformer with 4 percent impedance for through faults.

Standards and manufacturers provide curves plotting the damage time vs. the current in per unit of the transformer rated current. The damage curves for different transformer categories will be described later in this course.

Exercise: What is the minimum damage time for a close-in external fault at the low-voltage side of a single-phase distribution transformer?

Assume the following characteristics: 100 kVA, 7,200/120 V, Z = 4%

Answer: 2 seconds



The thermal damage curve shown represents a specific generator with balanced three-phase loading. Notice that the currents are between 100 and 225 percent of the rated current for the machine.

This curve is useful in determining the machine damage for overloads. The damage time during short circuits requires a more involved analysis, to be presented later in the course. This example was taken from ANSI/IEEE C37.102.

Exercise: What is the current in amperes required to damage the generator in 1 minute?

Assume: 13.8 kV, 20 MVA turbo generator with a damage curve similar to the one shown.

Answer: 1,088 A



Unbalance currents in the windings of a generator stator can produce negative-sequence fields in the machine air gap. These fields induce currents in the rotor, which overheat the forging and other components not normally designed to carry current. This overheating can produce significant damage during large negative-sequence current unbalances.

Generator manufacturers determine a time vs. current curve that indicates the time required for the rotor to be damaged for a given negative-sequence current in the stator circuit, I2. These curves correspond to the equation:

(I2)2 • t = K2

Constant K2 depends on the type of generator and the cooling system used. As a general rule, I2 is expressed in per unit of the generator rating and t in seconds.

The example shown above corresponds to a 68.9 MVA, 13.8 kV turbo generator.



The operation of an induction motor is limited by its thermal capacity and winding temperature. The manufacturer specifies motor thermal capabilities using thermal limit curves, also known as damage curves. A thermal limit curve is a plot of the maximum safe time versus line current in the windings of the machine for conditions other than normal operation. The curve represents the motor thermal limit for the following three operating conditions:

• Locked rotor

• Starting and accelerating

• Running overload

These curves can be obtained by means of destructive tests on prototype motors or can be estimated using mathematical models.

The figure shows an example of an induction motor thermal limit curve.



In this simple experiment, we sacrifice an inexpensive wire to save an expensive cable. In other words, for a given current, the inexpensive wire reaches the melting temperature before the expensive wire reaches the damage temperature. The inexpensive wire blows out and the cable is protected.

What do we call this inexpensive wire?



A fuse has an inverse melting curve, similar to the one we found for the damage time of an insulated cable. The difference is that the limit is the melting temperature, instead of the damage temperature.

In a similar way as was shown for the damage time, it is possible to show the following:

• The melting time decreases as applied current increases.

• There is a current (Imm) that causes the equilibrium to equal the fuse melting temperature. Equivalently, the melting time for this current is infinite. It is difficult to experimentally determine an accurate value for this current.

The curve obtained by plotting the damage time vs. the applied current is called the minimum melting time curve.

Notice that the fuse rating (nominal current) is not the same as the minimum melting current Imm.



The fuse melting time refers to the time before the fuse reaches melting temperature.

Once the melting temperature is reached, the current does not become zero immediately. The fuse goes through a series of different stages that terminate with the development of an arc. The current disappears when this arc is completely extinguished. At that moment, we say that the fault has been cleared.

The time between the fault occurrence and the fault clearing is called the total clearing time.



Similar to the melting time, a curve can be used to represent the total clearing time as a function of the current.

The following are the main characteristics of a fuse:

• The minimum melting time curve

• The total clearing time curve

• The fuse minimum melting current

• The fuse rating, which should not be confused with the minimum melting current

For better overcurrent protection, we could say that the total clearing time for the fuse should be less than the damage time for the protected equipment.

We will describe practical details of fuse application later in this course.



Besides thermal damage, rigid busbars can also suffer mechanical damage during short circuits. Large short-circuit currents produce large mechanical forces. Large mechanical forces can cause permanent deformation in the shape of rigid conductors and/or the destruction of supports. The effect can be very destructive in transformers, motors, and generators. Damage occurs instantaneously (in a very short time).

Most electrical equipment has an unacceptable voltage variance region (UVVR). The region indicates the equipment tolerance to voltage variations. The clearing time and the recovery voltage in the system must remain out of the UVVR. Examples of UVVR curves are included at the end of this section.



This slide shows an example of the mechanical forces caused by short-circuit currents.





As mentioned earlier, most electrical equipment has an unacceptable voltage variance region. The region indicates the equipment tolerance to voltage variations.

The clearing time and the recovery voltage in the system must remain out of the UVVR.


CBEMA Curve (Revised 1996)

0

100

200

300

400

500

0.01

0.1

110

Duration in Cycles (c) and Seconds (s)

Pe

rce

nt

of

No

min

al

Vo

lta

ge

(R

MS

or

Pe

ak

Eq

uiv

ale

nt)

20 ms3 ms1 ms 0.5 s 10 s0.01 c

1 s

120

140

110

908070

40

SteadyState

Unacceptable Voltage Variance Region (UVVR)

UVVR

Applicable to Single-Phase 120-Volt Equipment


These are typical UVV curves for electronic drivers, computers, and motor contactors. The specific UVV curve for each piece of equipment must be provided by the manufacturer.



With the introduction of distributed generation practices, electromechanical stability problems become an important issue in modern distribution systems.

For synchronization of generators and utility systems after a fault, the clearing time must be very short.

The upper permissible limit for this clearing time is traditionally known as the critical clearing time.

The critical clearing time is based on machine dynamics and other system conditions.

For the simple case shown, the clearing time (tclear) of Circuit Breakers 1 and 2 must be less than machine characteristics and the critical clearing time (tcrit) the system imposes.







Power systems require continuous control actions to maintain voltage and frequency in the operation range. Steady-state power system operation is really a dynamic state in which load changes frequently. Therefore, it is necessary to continuously control the active and reactive power outputs of generation units and the outputs of other reactive power sources in the system using both central and distributed control devices. There are two main steady-state control systems: active power-frequency and reactive power-voltage. In addition, there are automatic actions to minimize the cost of power system operation.



We need to balance reliability and cost when we are designing a power system. It is impossible to avoid faults and other abnormal operation conditions that generate power system disturbances. Therefore, protection and control systems should take preventive or corrective actions during power system disturbances.

The first line of defense is the protection of power system elements. This type of protection detects faults and abnormal conditions and disconnects the faulted element to prevent further damage in the element or to avoid a system disturbance.

Modern power systems operate near the security limits. Therefore, the power system also requires protection functions at the system level (wide-area protection systems); these functions include underfrequency and undervoltage load shedding, power system out-of-step protection, and other functions.

Preventing and/or mitigating disturbances also requires control actions (emergency control). These actions include preventive actions, such as deployment of active and reactive power sources, and restorative actions, such as automatic reclosing of transmission lines, automatic transfer to alternate power supplies, and automatic synchronization.



The figure shows a systemic view of the power system that includes three blocks:

• The power system

• The control system

• The protection system

The outputs, or outcomes, of the whole process are the active and reactive powers served to customers at satisfactory levels of voltage, frequency, and harmonic distortion that ensure the quality of service.

The inputs are of two types. The orders and settings from the operators are inputs controlled by people. The disturbances are inputs out of human control.

Disturbances can be classified as light or severe.

The control system responds to human actions and light disturbances. Severe disturbances (like faults) cannot be fixed properly by the control system. More drastic actions must be taken to minimize the system damage during severe disturbances. These actions are performed by the protection system.



We can classify power system faults as shunt faults or series faults. Short circuits are the most destructive type of shunt fault; system protection must include a tripping action to protect against short circuits.

A fallen conductor in an isolated-neutral or in a high-impedance-grounded system is a shunt fault that shifts the system neutral without large fault currents. The system may continue to operate for a short time in this condition. The protection system should issue only an alarm signal. Ground fault detection in these systems requires very sensitive relays.

Open phases are series faults. Broken conductors and blown fuses are the most common causes of open-phase conditions. Series faults do not produce high currents. They do, however, create system unbalance. Negative-sequence currents may overheat and damage the rotors of generators and motors in the system. Although tripping a line as a result of an open phase is not necessary, providing protection against unbalanced operation in rotating machines is required.



Power systems can suffer other abnormal conditions besides faults. A generator or a transformer may be in danger of thermal damage during overloads or external faults. Unbalanced operation (open phases, external unbalanced short circuits) can damage the rotors of generators and motors.

The power system can suffer abnormal frequency conditions when the generation-load relationship becomes unbalanced. Generation deficit causes underfrequency, and generation surplus produces overfrequency in the power system. Disruption of the reactive power balance causes abnormal voltage conditions. Reactive power deficits produce undervoltages, and excess reactive power can cause overvoltages. Other causes of overvoltages include line switching and lightning strikes.

Power system stability problems present a challenge to power system protection. Many protection schemes are prone to misoperation during stable or unstable power swings. Operation of these schemes should be blocked. On the other hand, when the system loses synchronism, it is necessary to divide the system into electrical islands, in which generation and load are closely matched. We need special out-of-step relaying systems for this condition.

Energizing a power transformer or a substation can produce abnormal values of current and could cause protective relay misoperations. Transformer magnetizing currents can reach very high transient values during transformer energizing. Transformer differential relays require a special design to avoid misoperation for transformer inrush conditions.

The current of a distribution substation can reach high transient values when we energize the substation after a long out-of-service period. The current can be several times greater than the normal current for several seconds. This condition results from the loss of natural diversity between loads. For example, during hot weather, all refrigeration and air-conditioning systems will be ready to start at the same time after a long service interruption. The starting currents of all motors contribute to the transient cold-load restoration current.



In a broad sense, the main function of power system protection is to detect faults and abnormal conditions and to disconnect the faulted element (or elements) or take other corrective actions in order to prevent further equipment damage or to avoid a system disturbance.

Another important function of protection systems is to facilitate restoration by providing an indication of the fault. This is a target indication. In the past, substation operation personnel would read relay targets after a relay operation and send the information to the relaying department. Modern digital relays can send the information over a communications channel. Power system operators can then use this information in real time to make better restoration decisions.

We should not confuse this targeting function with fault location, which is an accurate estimation of the distance to the fault on the transmission, subtransmission, or distribution line. Fault location information provided by digital relays helps line repair crews reduce repair time.



Fuses are protective devices with a fusible element. For an overcurrent condition, this element melts and an electric arc appears. During a current zero-crossing, the fuse extinguishes the arc and interrupts the fault current. We typically apply fuses in low- and medium-voltage distribution systems.

Automatic reclosers combine the fault detection, fault current interruption, and line reclosing functions in one piece of equipment. These reclosers are typically pole-mounted on overhead distribution lines. Automatic reclosers provide as many as five trips and four reclosures, to give temporary faults the opportunity to disappear. Automatic reclosers are used in overhead distribution circuits.

Sectionalizers are pole-mounted devices that count automatic recloser operations and open the faulted circuit during a given recloser-open period. Sectionalizers are not intended to interrupt fault current. They sectionalize a faulted lateral, for example, taking advantage of the operation cycle of the recloser installed in the feeder. The recloser resets after an incomplete operation cycle when the sectionalizer disconnects the faulted lateral.

Low-voltage breakers (typically used in industrial, commercial, and residential circuits) also combine fault detection and fault interruption functions.

Protective relays detect the fault and issue a tripping signal to a breaker. We use relays in medium-and high-voltage systems.



A relay protection system, or relaying system, used in medium- and high-voltage systems includes: 1. protective relays, 2. voltage and current transformers, 3. circuit breakers, 4. a dc supply system, 5. a communications channel (eventually), and 6. control cables. Protective relays detect faults and abnormal conditions in the protected element and close an output contact to initiate circuit breaker tripping. VTs and CTs isolate the relays from the primary system and reduce the primary voltage and current values. Breakers receive the tripping signal from the relays and open the primary circuit to interrupt the fault current. The dc supply system provides the breaker tripping current when protective relay output contacts close. In transmission lines, a communications channel could be necessary for the relays at both line ends to exchange information.

Relay protection system reliability depends on all system elements. In the past, electromechanical relays were responsible for a high percentage of protection system operation failures or misoperations. Digital relays are highly reliable devices. These relays, besides providing protection, can also monitor the status of protection system elements, further enhancing protection reliability.

Fault-tree analysis is a method for examining all aspects of the protection system and determining the major contributors to reliability.



The figure depicts a simplified dc tripping circuit. In the dc schematic circuits, the contacts are shown in their de-energized position. The normally open 52a breaker contact is closed when the breaker is closed. Relay operation for a fault implies the closing of the relay contact. This operation completes the circuit and establishes current through the breaker trip coil 52TC, which functions to open the breaker main contacts and disconnect the protected element.

When the breaker trips, the 52a contact opens to interrupt the tripping current, protecting the relay contact. Relay contacts can often make, but not break, the tripping current, creating the need for a more robust contact to interrupt the highly inductive dc current. Interruption of the dc current in this circuit is the function of the 52a contact.

A trip contact seal-in technique is sometimes provided in older relay designs. A seal-in contact (SI) closes when the tripping current begins to flow, bypassing the relay contact. The action of the seal-in contact prevents the relay contact from interrupting the tripping current under any circumstance, thus protecting the trip contact from welding. This technique has been replaced with a built-in latching logic in modern digital relays, which has been widely accepted in the design of breaker tripping circuits. Using this logic, the relay output contact cannot open when the breaker is closed and/or when current is flowing through the breaker. SEL relays also have high interrupting capacity output contacts available as an option.

The red light shown in the figure has two functions. This light indicates if the breaker is open (52a is open, light is off) or closed (52a is closed, light is on). In addition, if the breaker trip coil circuit is opened accidentally, the red light will remain off even when the breaker is closed, thus indicating an open-coil condition.



Given the importance of power system protection and considering that a protection system may fail to operate, you should have two protection systems: primary and backup protection. This is particularly important for short-circuit protection because the short circuit is the most frequent type of system failure; therefore, the probability that the primary short-circuit protection will fail is higher than that of the protection against other abnormal operating conditions.

Primary protection is the first line of defense. Primary short-circuit protection operation should be as fast as possible, preferably instantaneous, for stability and power quality reasons and to prevent equipment damage.

The figure shows the one-line diagram of a power system section that illustrates the basic concepts of primary short-circuit protection. Adjacent system elements are connected through breakers, which allow the protection system to completely isolate a faulted element. Occasionally, breakers are omitted between adjacent power system elements. Then, it is necessary to disconnect both elements to isolate the fault. For example, in generator-transformer units, generators have dedicated step-up transformers, and the breaker between them is frequently omitted.

The zones indicated with dotted lines in the figure are the primary protection zones. The significance of these zones is that a fault inside a zone implies the tripping of all the breakers within that zone, and only those breakers. Protective relays define the primary protection zones. Relays use system currents and voltages as input signals. Later in this course, we will show that current information is instrumental for the relays in determining fault location. Therefore, CT location defines the limits of the primary protection zones in many cases.

Adjacent protection zones overlap to provide full primary protection coverage in the power system. A fault in the overlapping areas produces the tripping of more breakers than the breakers needed to isolate the fault. Therefore, the overlapping areas need to be as small as possible.

When the relays of a protection zone receive information from CTs located at all interconnections with adjacent zones and make tripping decisions based on this information, we have a closed protection zone, also called a unit protection zone. When the protection zone is partially limited by only CT location points, the zone limits are not well defined in the direction of the interconnections without CTs. These limits vary with the fault current. In this case, we have an open, or nonunit, protection zone.



A backup protection system increases power system protection reliability. Backup protection operates when the primary protection system fails or is removed from service for inspection or testing. Failure of any one of the primary protection system elements (protective relays, VTs and CTs, breakers, dc supply system, communications channel, and control cables) could be the cause of a primary protection failure to operate. Redundant primary protection (redundant relays, instrument transformer windings, and dc supply systems, for example) provides high reliability. In addition, backup protection should be designed so that anything that might cause a primary protection failure would not also cause a backup protection failure. In other words, primary and backup protection should not have common mode failures to operate. Self-testing, included in modern microprocessor relays, greatly improves reliability by detecting and alarming for most relay failures.

The figure shows a one-line diagram of a power system and helps illustrate the concept of backup protection. The bus-tie breaker T is assumed to work normally closed. For a fault on Line CD, Breakers 5 and 6 should operate as the primary protection. If Protection 5 fails to operate, two possibilities remain for removing the fault current contribution from A, B, E, and F: open Breakers 1, 3, and 8 or open Breakers 2 and T. In any case, backup protection needs a time delay. The primary protection needs an opportunity to operate before the backup protection operates.



Breakers 1, 3, and 8 are located in remote substations. They provide remote backup protection. Any given protection often serves as remote backup for more than primary protection. For example, Protection 1 is the remote backup for Lines BC and CD and for Bus C. Therefore, the remote backup protection zone starts at the backup relay location and extends in one direction to cover all the adjacent system elements. For faults in the backup zone, remote backup must operate more slowly than the slowest primary protection.

An advantage of remote backup protection is the low cost: the remote backup protection comes from protection equipment that is needed for primary protection functions of adjacent system elements. Therefore, there is no need for additional investment. Remote backup is widely used in distribution and subtransmission systems. However, we will see later in the course that operational drawbacks of remote backup protection limit its application in transmission systems.



Breakers 2 and T provide local backup protection; they are located in the same substation as the primary protection. Local backup protection is more expensive than remote backup because additional equipment is needed to duplicate some protection system elements. Operational advantages of local backup over remote backup (described further in the course) explain the wide use of local backup in transmission systems. These advantages are greater sensitivity, greater selectivity, and faster operating speed.

When primary protection is out of service for maintenance or repair, backup protection systems provide a level of primary protection. This operation condition should be avoided because it results in slower fault clearing times, disconnection of a larger number of system elements, and the lack of backup protection.

The previous discussion refers only to short-circuit protection. Protecting the power system against other abnormal operation conditions requires a variety of primary protection schemes that respond to different input quantities and that have different operation principles. Therefore, although there is general protection coverage of power system elements, no universal protection zone overlapping exists. In the past, the practice was to apply backup protection only for short circuits for economic reasons. This approach was probably valid for electromechanical protection schemes. With modern multifunction digital relays, backup protection against other abnormal operating conditions can be provided at a low cost.



This slide presents the primary and backup protection concepts as applied in a radial industrial power system.

In case a fault occurs at point F1, Device 1 must clear this fault. If Device 1 fails to operate, the system is designed so that Device 2 acts as the backup of Device 1.

In industrial systems, this is accomplished by allowing Device 2 to detect the fault at F1, adjusting so that it does not operate after a certain time interval. Device 2 waits until it is sure that Device 1 has failed.

Devices 4 and 6 operate similarly if a fault takes place at F2. But they are different in that Device 6 is located at a remote station. This is considered a remote backup device.

Question: Would Device 5 operate for a fault at F2? Why?



Protection systems are intended to trip when there is a fault or an abnormal condition in the protected element and not to trip during normal operation conditions or external faults unless the primary protection of the adjacent faulted element fails to trip. It is important to continuously evaluate protection system performance in order to detect problems and take rapid corrective measures.

Correct protection system performance trips when required and does not trip when no fault or abnormal condition exists. Protection systems most often monitor a normally operating system. During most of its life, the protection system is in a correct, no-operation condition. Correct performance requires the satisfactory operation of all the protection system equipment. This performance includes the satisfactory presentation of relay system quantities to the relaying equipment, the correct operation of the relays in response to these input quantities, and the successful operation of the switching device or devices. In a broader sense, the protection system performs correctly when primary protection operates correctly to clear the fault, backup protection does not operate, and, as a result, the faulted element (or elements) is isolated in the expected time.

Incorrect protection performance may result in failure to disconnect faulted elements and/or the disconnection of healthy elements. Then, incorrect protection system performance includes two possible deviations from the correct state: failure to trip and false tripping or misoperation. A failure to trip is a lack of trip when required. A false trip or misoperation is a protection operation that occurs when the protected element is healthy. Such an operation can occur during normal operation conditions or, more frequently, during external faults or other system disturbances, such as power swings.

Possible causes of incorrect protection system performance are equipment failure or malfunction, relay application errors, relay settings errors, and other personnel errors. Incorrect protection performance is never planned. There are rare cases in which an incorrect protection operation incidentally results in an acceptable elimination of the fault or other abnormality. These cases should be carefully analyzed. Protection engineers should never rely on unexpected, or even incorrect, protection operations working in their favor to eliminate system failures.

There are cases in which a breaker trips as a result of a relay operation, or even without an indication of a relay operation, and there is not enough information to get to the root cause of the operation. Digital relay monitoring abilities (measurement, fault recording, and data recording on the status of primary equipment and protection system elements) provide information to evaluate protection performance, thus reducing the number of cases in which there is no conclusion.



Power system protection must meet very stringent requirements, especially when power systems lack redundancy and operate near their security limits. Protection systems should have several properties to meet these requirements. We can refer to these properties as protection objectives or functional characteristics. The most important properties are reliability, selectivity, speed of operation, and sensitivity. We should also include simplicity and economics as relevant properties.

Reliability of a relay or relay system is a measure of the degree of certainty that the relay, or the relay system, will perform correctly. A reliable system is one that trips when required (dependability) but does not trip when not required (security).

The dependability facet of reliability relates to the degree of certainty that a relay or relay system will operate correctly. We can obtain dependability through relays that try to trip the same breaker (parallel connection of the relay contacts or its equivalent logic function [OR logic]).

The security facet of reliability relates to the degree of certainty that a relay or relay system will not operate incorrectly. We can obtain security through series connection of the relay contacts or the equivalent logic function (AND logic).

There is a bias among protection engineers toward dependability in protection system design. This bias reflects the fact that power systems are redundant to a certain extent. In theory, we can lose a line because of a relay misoperation without having a system collapse. In modern power systems, however, this concept is changing.

Selectivity is the ability of a protection system to eliminate a fault in the shortest time possible with the least disconnection of system components.

We also use the term coordination for selectivity. Protection coordination implies that primary protection eliminates faults and that backup protection operates only when primary protection fails. We also call coordination the process a protection engineer uses in calculating relay settings.



If the protective devices do not operate when required, the consequences can be disastrous. The probability of failure of these devices should be as close to zero as possible.



Some normal transient conditions in the system can look like faults to certain types of protective devices. These mainly occur when switching operations are performed. For example, when a transformer is energized or a motor starts, the current in the circuit suddenly increases. An overcurrent protective device could detect this overcurrent and produce an undesired disconnection of the system.

In general, the protection system should be designed so that the overcurrent devices operate only for the conditions for which they are intended to operate. The system must be able to avoid overreaction when normal transients take place.



Suppose a fault occurs where indicated. The fault may be cleared by opening any of the disconnecting devices 1, 2, 3, 4, or 5, since any of them will interrupt the current flow to the fault.

If only Element 1 operates, the loss of service is minimal.



Speed of operation is the ability of the protection system to operate in a short time after fault inception. Fast operation is important in preserving system stability, reducing equipment damage, and improving power quality and human safety. Relaying system operation time includes relay and breaker operation time. We typically measure protection system operation time in cycles, or the periods of power system frequency. One cycle is equivalent to 16.67 ms at 60 Hz and 20 ms at 50 Hz.

An instantaneous relay is a relay with no intentional time delay. A high-speed relay is one that operates in less than 50 ms (3 cycles at 60 Hz). This term comes from electromechanical relay technology. In modern digital relays, instantaneous element operating times are about 1 cycle. Typical breaker operation times are from 2 to 8 cycles. For example, a 1-cycle relay and a 2-cycle breaker provide a fault clearing time of 3 cycles (about 50 ms at 60 Hz).

Sensitivity is the ability of the protection system to detect even the smallest faults within the protected zone. It is important to ensure the detection of high-impedance faults or the reduced contribution to faults from small, distributed generators.



Ground faults may cause potential differences between different points of the installation that can jeopardize the safety of personnel.

According to IEEE standards (referenced below), the grounding system must be designed to avoid fatal electric shocks to humans in the event of a ground fault. It can be shown that the magnitude of the fault current and the time required for the protection system to clear the fault are fundamental parameters that determine the effectiveness of the safe grounding design. This is an important reason to increase the operating speed of the protective devices.

References

IEEE Recommended Practice for Grounding of Industrial and Commercial Power Systems, IEEE 142, 2007.

IEEE Recommended Practice for Industrial and Commercial Power Systems Analysis (Brown Book), IEEE 399, 1997.



An electrical arc is essentially the result of electrical current conduction through a gas. The energy of an arc depends on the current and voltage and the duration of the arc. The temperature of an arc is extremely high, and the metallic conductors and other materials close to the arc will melt. A human being can undergo harmful and even fatal burnings if exposed to the arc flash. Moreover, hot particles of the burned material can also harm personnel.

When an arcing fault occurs, it is cleared by the protection system. The faster the clearing time, the less damaging the arc, because less energy is released.

There are regulations (see, for example, the NFPA reference below) that establish design criteria for systems to ensure personnel protection against arc flash. The general rules establish, among other stipulations, the minimum distances or protective boundary that a worker must have from given equipment to ensure that he or she will not suffer incurable burn. In all formulas, the arc duration (the fault clearing time) is directly related to the effectiveness of the protection measures.

References:

NFPA Std. 70E. Standard for Electrical Safety in the Workplace. 2014 Edition.

J. Buff and K. Zimmerman, “Application of Existing Technologies to Reduce Arc-Flash Hazards.” Available at www.selinc.com.



In general, overcurrent devices are typically set with the minimum operating current, such as threshold or pickup current, smaller than the minimum short-circuit current available in the protected zone.

For the system shown, it may be impossible for Device A to detect faults beyond Point x, where the fault current is 600 A. However, Device B can be set to detect faults lower than 400 A, covering the rest of the zone. As we will see later, this can sometimes conflict with other requirements of the protection system.





In high-voltage systems, the use of fuses is not economically feasible. Therefore, electrically commanded circuit breakers (CB) are used. The circuit breaker opens the faulted section of the system when it receives an order from a low-voltage device called a protective relay. The protective relay is a device provided with enough intelligence to detect a fault and make the decision to trip the circuit breaker.

Because the relay is a low-voltage device, it must be isolated from the high-voltage system. This is accomplished through the use of current and voltage transformers (CTs and VTs). The one-line diagram shown here depicts a relay that receives current only from the system.

Relay definition: “A relay whose function is to detect defective lines or apparatus or other power system conditions of an abnormal nature and to initiate appropriate control circuit action” (IEEE 100).

To achieve the main protection goal, when a fault occurs, the circuit breaker must completely clear the fault before the protected equipment is damaged. In other words, the operating time of the relay, plus the operation time of the circuit breaker, including the arc extinction time, must be shorter than the damage time of the protected equipment. Notice that all of this happens without the intervention of a human being. This is a fast, automatic action.



This slide shows a simplification of the fault clearing process by a relayed circuit breaker.

The process of clearing a fault has several steps. The first step, the detection function, is performed by the protective relay. The relay also makes the decision of tripping, or not tripping, the high-voltage circuit breaker.

Relays are normally designed to operate in a very short time. When no intentional delay is required, the operation time of a relay is between 1 to 3 cycles.

On this slide:

tr = relay time

ta = arcing time

tcb = circuit breaker time

tc = total clearing time

tm = mechanism time



In a classification according to design, we can break protective relays into analog and digital relays. Analog relays include electromechanical and static relays. In digital relays (also called numeric or microprocessor-based relays), the input voltages and currents are converted into digital quantities. Microprocessor platforms digitally process these quantities to execute protection functions. Modern digital relays also provide control and monitoring functions and have communications capabilities.

We also can classify protective relays according to function. For example, we have overcurrent, overvoltage and undervoltage, directional, distance, and differential relays, among others. Digital relays typically perform several protection functions.



A relay is an electric device designed to respond to input conditions in a prescribed manner and, after specified conditions are met, to cause contact operation or similar abrupt change in associated electric control circuits. Relays typically have electric input signals, but mechanical, thermal, or combined inputs are also possible.

Relays have been classified in several different ways, including function, type of design, input information, and others. A classification by function may include protective, regulating, reclosing and synchronism check, monitoring, and auxiliary relays. This classification should be updated because these functions merge totally or partially in modern digital relays.

A protective relay is a relay whose function is to detect defective lines or apparatus or other power system conditions of an abnormal or dangerous nature and to initiate appropriate control circuit action. Protective relays are connected to the power system through current transformers and/or voltage transformers and issue a tripping signal to a power circuit breaker. We use relays in medium-voltage and high-voltage systems.

Relay input signals are generally currents and/or voltages. Modern relays also receive logic input signals.

The outputs are dry contacts. Some modern relays have other kinds of outputs. The contacts are used to energize the circuit breaker trip coil.

Relays are flexible devices that can be set to operate for different situations. The settings include the threshold values, the time delay (when required), and others. Engineers need to calculate these settings for the specific application.



The figure shows the functional block diagram of a digital multifunction relay. The relay receives secondary voltages and currents from the instrument transformers. These are the relay analog input signals. The relay also receives discrete inputs, such as the contact status of other relays. A digital relay issues contact-closing tripping signals just as analog relays do. It also uses LEDs to signal operation.

As shown in the figure, a digital relay has an analog input subsystem, an analog-to-digital (A/D) converter, a discrete input subsystem, a microprocessor system, a discrete output subsystem, operation signaling elements, and communications ports. The digital relay also includes a human-machine interface (HMI) with front-panel buttons and display, not shown in this figure for simplicity.

The analog and discrete input subsystems prepare the signals before they are converted to digital signals for processing in the relay microprocessor system.

The discrete output subsystem includes fast electromechanical relays to provide the contact outputs.

The microprocessor system is the heart of the digital relay. It computes the digital signal processing algorithms and the protection, control, and monitoring programs, and performs all basic computer system tasks, including self-testing. The microprocessor system consists of the central processing unit (CPU), the memory, the buses, and the interface circuits. All these elements may reside in a single-chip microcontroller.



The relay microprocessor system uses different types of memory elements. The system needs random-access memory (RAM) as a data buffer for calculation results and digitized input samples. It also needs read-only memory (ROM) to store the digital signal processing and protection, control, and monitoring algorithms, and other operating system programs. The system requires electrically erasable programmable read-only memory (EEPROM) to store settings data and monitoring data, including, for example, oscillographic records. A RAM memory with a battery backup may also serve this function.

Modern digital relays have multiple communications ports, such as serial EIA-232 and EIA-485 ports, Ethernet ports, USB ports, and optical ports.

The main components of a microprocessor-based relay are as follows:

• The input interface, which includes:

The analog input subsystem, including the analog-to-digital converter

The discrete input subsystem: The objective of this hardware’s first stage is to convert the analog input signals into a sequence of digital values (ones and zeros) that can be used by the microprocessor. The resulting signal is sometimes called a sampled signal.

• The main microprocessor system contains the following elements:

Microprocessor(s)

Memory (RAM, ROM, PROM, EEPROM, etc.)

Human-machine interface with front-panel buttons and display

Communications ports

• The output subsystem includes the following subsystems:

The discrete output subsystem

Signaling devices (LEDs and others)

• The power supply and other auxiliary equipment



The analog inputs coming from the CTs and VTs pass through the analog input subsystem. This subsystem provides three functions also required by solid-state relays: signal conditioning, galvanic isolation, and surge suppression. Internal CTs and VTs reduce the input current and voltage signals to small voltage signals that can be handled by the relay’s electronic circuits. The analog input subsystem provides a galvanic isolation between the external ground and the relay’s electronics ground. This subsystem also protects the microprocessor system against surges superimposed on the input signals.

A fourth function of the analog input subsystem is low-pass filtering of the input signals to avoid aliasing in the sampling process required as part of the A/D conversion. We will discuss aliasing and anti-aliasing filters later in this section.



The analog input subsystem has the following functions:

• Signal conditioning (voltage or current reduction)

• Galvanic isolation

• Surge suppression

• Low-pass filtering

The analog low-pass filter eliminates the high-frequency components contained in the input. This filter avoids aliasing of the signal in the sampling process.

Some frequency components higher than the fundamental remain in the output signal of the analog filter. These components will be rejected by the digital filter to obtain the fundamental frequency components required by most relay functions. The cutoff frequency of the analog low-pass filter depends on the particular relay design.



Discrete input signals also require preprocessing. The discrete input subsystem achieves the first three functions that we described for the analog input subsystem: signal conditioning, galvanic isolation, and surge suppression. The input signals are discrete, so they do not require low-pass anti-aliasing filtering.



The discrete input subsystem typically includes optoisolators to provide galvanic isolation. An optoisolator consists of an electric-to-optic transducer (similar to a photodiode) and a optic-to-electric transducer (similar to a phototransistor). This device ensures complete electric isolation of the relay circuitry from the external system.

Some manufacturers call the logic inputs optoisolated inputs, because the logic signals are passed through an optoisolator before they are treated and converted to digital.



A/D converters sample the incoming analog signals and convert the sampled values to a digital format as required for further processing in the relay microprocessor system.

We will see later that in some relays, sample-and-hold (S/H) circuits perform signal sampling, and an A/D converter performs the conversion of the samples to a digital format. In other relays, the A/D converter performs both functions.

This figure illustrates the sampling process. A sampling clock determines the sampling instants. At each sampling instant, the sampler stores the instantaneous value (a sample) of the analog signal. The sampler output is a discrete signal, a sequence of samples whose values coincide with the analog signal values at the sampling instants.



The sampling frequency fs in Hz is the inverse of the sampling period t in seconds.

fs = 1 / t

The sampling rate can be specified as the number of samples per cycle. For example, an algorithm that works with a data window of one cycle and 16 samples per cycle in a 60 Hz system has the following sampling period and sampling rate:

t = 1 / (60 • 16) = 0.00104 s = 1.04 ms

fs = 1 / t = 960 Hz

The simplest sampling method uses a fixed sampling period (a fixed number of samples per second), which is equivalent to taking an integer number of samples per cycle of the nominal frequency. As we will see later, digital relays calculate phasors using the sampled data. When the relay uses this sampling method, the phasor calculation has errors when the power system operates at off-nominal frequencies. This error is not acceptable for some applications, such as distance protection and synchrophasor measurement.

A solution to this problem is to use a sampling method that takes an integer number of samples per cycle of the power system frequency, rather than the nominal frequency. The data acquisition system requires information about the power system frequency to adapt the sampling rate in real time.



The A/D converter converts each sampled value into a digital word. Hence, the A/D converter translates the analog sequence samples to the corresponding digital sequence. These data are stored in the memory of the microprocessor system for further processing in the relay.

Given that a digital word has a finite number of discrete values, the A/D converter rounds off the sample values before converting them into digital words. This discretization process introduces an error. Hence, the A/D system of a relay defines, to some degree, the accuracy of the input data.

For example, suppose that the A/D converter output has 8 bits. The A/D converter would be capable of providing 28 = 256 numbers (between 00000000 and 11111111). The accuracy is 100 / 28 = 0.39% of full scale. A 12-bit A/D converter will have an accuracy of 100 / 212 = 0.024% of full scale.



Several A/D conversions must take place at every sampling instant to process all relay analog input signals. A line protection relay, for example, has at least three current and three voltage inputs. A bus differential relay has even more inputs than a line protection relay. The figure depicts different alternatives to handle multiple inputs for the A/D conversion process in a digital relay.

The simplest and more economical scheme uses an analog multiplexer (MUX) to apply sequentially the different analog input signals to the A/D converter. Under the control of the computer clock, the A/D converter samples and digitizes every analog signal presented by the MUX. In this scheme, the samples are not taken simultaneously, so they do not have the same time reference. It is easy to correct this skew with software in the microprocessor system. Today, this is the preferred method.

In the past it was necessary to add hardware to prevent the sampling skew. Additional hardware included sample-and-hold (S/H) circuits or dedicated A/D converters in the analog input channels. However, this solution increased the cost of input circuitry.

In one of the schemes shown on the slide, S/H circuits take synchronous samples from all input signals under the control of the clock. In the S/H circuits, a charged capacitor holds the information on the instantaneous value of each input signal. An analog multiplexer (MUX) sequentially presents this information to the A/D converter. In this case, there is no concern about skew, because the samples are taken at the same time by the S/H circuits.

Another method devotes an A/D converter to each signal channel. There is no need for S/H circuits or multiplexers. All the A/D converters synchronously sample the signals under the control of the clock. This alternative has the highest cost, because the A/D converter is the most expensive component in the circuit, with the fastest potential sampling rate.



The digital relay algorithm is a set of mathematical operations implemented in a program. These operations are performed over the last N samples of the input signal. The relay makes the decision of tripping or not tripping the breaker based on the result of the algorithm.

The relay algorithm is programmed and stored in the ROM memory. The algorithm is divided in several routines, or functions. The figure presents a hypothetical example of a protection algorithm, which includes the following routines:

• Reading (read last sample): Reads the last sample of the input signals

• Digital filtering: Extracts the signal frequency components of interest by eliminating dc and other unwanted frequency components

• Phasor calculation: Calculates voltage and current phasors from the samples of the digital filter output signals

• Protection functions: Implements the relay protection function(s), such as overcurrent, directional, distance, differential, and other functions

• Relay logic: With the results of the protection function routine, the relay logic makes the final decisions for tripping and other functions. In some modern relays, the logic can be programmed by the user



Digital relay algorithms process only a given number of the most recent digitized samples. Every time a new sample becomes available for processing, the oldest sample is discarded and the same number of samples is processed. This process is referred to as a moving data window. This method is equivalent to multiplying these samples by one and multiplying all the previous samples by zero.

The figure shows the most recent N sample data window, composed of the last sample k acquired by the reading routine, together with the previous N–1 samples.

In digital relays, the typical data window length is one cycle, so N is generally the number of samples that fit in one cycle. As we will see later, one-cycle data windows provide a good balance between accuracy and speed in the digital filter. For even faster operation, some relays also use shorter data windows.



As mentioned earlier, the analog filter eliminates the high-frequency components contained in the input signals to avoid aliasing. However, the analog filter passes the dc offset component and some frequency components higher than the fundamental.

The digital filter rejects the dc offset component and other unwanted frequency components. This filter passes only the signal components of interest for the relay protection, control, and monitoring functions.

The digital filter output consists of samples of the filtered signals. Some relay algorithms use these samples as input information. Other algorithms require the phasor values corresponding to the filtered sampled values.



This routine determines the current and voltage phasors from the filtered signal samples. There are several phasor calculation methods.

In general, these algorithms determine the magnitudes of the sine and cosine components of the sinusoidal filtered signals (the phasor rectangular components). For a polar phasor representation, the algorithms calculate the phasor magnitude from the rectangular components. Finally, the phasor phase angle is determined with respect to a reference, which may be one of the inputs being processed.



Using the instantaneous or phasor filtered values, the relay executes the protection functions and other control and monitoring functions.



With the results of the protection function routines, the relay logic makes the final decision for tripping and other relay functions. In some modern relays, the user can program the logic.

The results of a logic function can be used to modify a protection function. For example, the output signal of a directional element can be used to enable an overcurrent element. This logic is the digital equivalent of torque control in electromechanical directional overcurrent elements.

Some digital relays include adaptive functions. These relays automatically adjust their operating characteristics and/or settings depending on the power system conditions. For example, the relay can monitor the position (open or closed) of several breakers in a substation. Depending on these positions and the result of programmed logic, the relay can automatically modify its settings to adapt to the substation topology. Using adaptive methods, the protection scheme can achieve significant improvements in sensitivity and speed without sacrificing selectivity and security.



The predefined logic provided by the relay manufacturer is sufficient for most relay applications. Engineers customize the relay by setting each element according to the specific application requirements.

For some applications, a level of customization beyond configuring the existing predefined logic is required. Modern digital relays provide programmable logic for these applications. Programmable logic is an extraordinary feature of digital relays. Users can define many different logic functions to meet to their needs.

Programmable logic allows you to create control equations that perform logic and mathematical operations on variables. These control equations may also include timers and counters. Control equations typically accept logic variables, which indicate the state of various logic schemes within the relay. These logic variables can be used as inputs to programmable logic and can also be outputs from programmable logic. Control equations in some advanced relays also accept digitized analog values, which can represent sampled signal waveforms, counter values, or external measurements such as temperature.



The discrete output subsystem includes fast electromechanical relays to provide the contact outputs. This subsystem also includes an analog-electronic interface between the microprocessor system and the electromechanical relays.

The outputs of some modern digital relays can also be programmed. Output programming allows users to define the output contacts to be controlled by given relay logical functions. For example, for a relay with four outputs, you can assign a particular relay decision to each output, such as:

• Y1 = [(32N) AND (51N)] OR [(67P) AND (67N)] to trip the breaker

• Y2 = Y1 to send a signal to the annunciation device (alarming)

• Y3 = 50P to indicate that the current in one of the phases surpassed a settable threshold

• Y4 = 59PT to indicate that the voltage in one of phases surpassed a settable threshold for a given period of time

All the relay logic variables (67P, 51P, 50P, 59T, etc.) are calculated by the microprocessor system every processing time. The position of the output contacts is updated with the same frequency. With programmable outputs, you can send the status of many relay logic variables out of the relay and use them for different purposes.



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