OVERCURRENT PROTECTION COORDINATION BASIC INFORMATION

WHY WE DO OVERCURRENT PROTECTION COORDINATION?

The objectives of overcurrent coordination are to determine the characteristics, ratings, and settings of overcurrent protective devices that minimize equipment damage and interrupt short circuits as rapidly as possible. These devices are generally applied so that upon a fault or overload condition, only a minimum portion of the power system is interrupted.

An overcurrent coordination study is the comparison and selection of operating times of the protective devices that achieve the objectives of the protection system under abnormal system conditions. This study should include all devices from the utilization equipment to the source.

A coordination study also provides data useful for the selection of
—Instrument transformer ratios
—Protective relay characteristics and settings
—Fuse characteristics and ratings
—Low-voltage circuit breaker ratings, characteristics, and settings

It also provides other information pertinent to the provision of optimum protection and selectivity in the coordination of these devices. In new installations, electrical equipment ratings often change prior to plant startup, but after protective devices have been ordered. These changes should be anticipated when selecting protective devices so that the device characteristics are sufficiently flexible to protect the individual load or branch circuit.

A preliminary coordination study should be made during the early stages of a new system design to verify that the protective device ratings can be selective and that the source utility’s protection practices have been considered. The protective device settings should be determined after the design has been completed and all load and fault currents have been calculated.

Protective devices are applied to a power system as primary and backup protection. Primary protection is the first line of defense against further damage caused by a fault or other abnormal operating condition. These devices are generally set to operate faster and remove less of the power system from service than backup protection.

Backup protection takes over when the primary protection fails to clear the abnormal condition. Backup protective devices and settings are selected to operate at some predetermined time interval after the primary device operates.

Thus, a backup device should be able to withstand the fault conditions for a greater time period than the primary protective device. For most applications, the operation of the backup device isolates circuits in addition to the faulted or overloaded circuit. Therefore, a greater portion of the power system is interrupted with backup protection.

In applying protective devices, it is occasionally necessary to compromise between protection and selectivity. While experience may suggest one alternative over another, the preferred approach is to favor protection over selectivity. Which choice is made, however, is dependent on the equipment damage and the affect on the process.

In existing facilities, system configurations and operating conditions often change. A new coordination study should be performed when the available short-circuit current to a plant changes or when significant changes in plant loading occur. This study determines the ratings or settings necessary to ensure that selectivity and protection are maintained after system changes occur.

A coordination study should definitely be performed when a fault on the periphery of an existing plant unexpectedly shuts down a major portion of the system. Such an event may indicate a need to change or reset devices.

PROTECTIVE RELAY TESTING OVERVIEW

Protective relaying is a very broad subject. Only a brief overview can be given here.

There are two major objectives in protective relaying. First, a protective relay serves to provide equipment protection (i.e., locate and isolate overloads, short circuits, undervoltages, and other types of electrical problems quickly in order to minimize damage).

Second, the protective device that is closest to the problem should operate first to clear the problem, and no other device should operate unless the closest one fails. This concept, known as selective tripping or selectivity, maintains service to as much of the electrical system as possible by isolating only the problem area.

In order to achieve these objectives, each relay must function as it was designed, and the relays must function in conjunction with the other protective devices in the system. Having all the protective devices function as one overall protective system is called coordination.

Each protective device has specific parameters within which it has been designed to operate. For example, a single element fuse has a value of current above which it opens. It takes a specific amount of time for a given current to melt the link away and open the fuse.

Manufacturers of fuses publish time-current curves that show how long it takes a fuse to operate for varying current values. Generally, the higher the current, the shorter the time.

This same inverse current-vs.-time concept is used for overcurrent relays and for low-voltage circuit breakers. Relays and low-voltage circuit breakers (with internal trip units) have a range of pickup operating current that causes them to operate. In many cases, this value of current is adjustable.

By properly selecting the type, characteristic, and/or setting of fuses, relays, or circuit breakers, the system can be coordinated so that the device that is closest to the problem opens before any device upstream of it. It is necessary to select compatible time-current characteristics of the devices for the entire system, in addition to selecting the proper settings for the devices.

Prior to performing protective relay testing, a coordination study should be completed to determine the proper settings for the relays to be calibrated. This is usually done by the design engineer when the system is first installed. If there have been revisions or additions to the system, a new study may be necessary.

Once the coordination study has been completed, the relays need to be calibrated to the proper settings. There are special test sets available for this purpose that inject currents and voltages, as necessary, and time the various operations of the relays.

This type of testing is usually performed by a technician who specializes in this area. Depending upon the relay to be calibrated, quite complex test equipment may be required and in-depth training in protective relaying may be needed to properly set the relay.

DIRECTIONAL COMPARISON BUS RELAYING

Occasionally, it is desirable to add bus protection to an older substation where additional current transformers and control cable are too costly to install. In this instance, the existing current transformer circuits used for line relaying can also be used to provide protection for bus faults.

A directional comparison bus protection system compares the direction of current flow in each circuit connected to the bus. If the currents in all the circuits flow into the bus, a bus fault exists.

If the current in one or more circuits is flowing away from the bus, an external fault exists. Fault detectors are used to initiate the system. This system can be used for either or both phase and ground bus fault protection.

The basic system requires directional relays, fault detectors, and a timer. Directional relays are used on each circuit connected to the bus. Fault detectors are used to indicate a fault within the vicinity of the bus.

Phase fault detectors are instantaneous overcurrent relays connected to a bus tie breaker or to one or more of the circuit connections. Ground fault detectors are instantaneous overcurrent relays connected in power transformer neutrals or to one or more of the circuit connections.

A timer is required to permit contact coordination of the directional relays. The contacts of the directional relays are connected in series with the timer contact to initiate a trip signal.

Current transformer saturation is usually not a problem when comparing direction of current rather than comparing magnitudes of current as is done in conventional bus relaying systems. The current transformers in each circuit do not require the same ratio and can be used for other forms of relaying and metering.

In some cases, the directional elements of relays used for normal circuit connection relaying can also be used for this bus protection system. The system is rather complex and requires rigorous maintenance due to the number of relay contacts.

The timer must be set for at least four cycles to assure contact coordination. Contact bounce must be avoided in the directional relays and in the overcurrent fault detector relays.

Contact bounce should be checked when high-magnitude fault currents are likely.

The relays and relay settings must be reviewed when system changes are made near the protected bus to make certain that selectivity between initiating and blocking relays exists. There is presently available a directional comparison system based on directional comparison of the current in all circuits connected to the bus in relation to the sum of all the currents.

This system employs solid-state relays. Intermediate current transformers are used, and main current transformer ratios and characteristics need not be the same on all circuits.

MTBF DEFINITION AND BASIC INFORMATION

WHAT IS MTBF?

MTBF is used in calculating reliability. It is an acronym for mean time between failures (MTBF).

Most manufacturers calculate the reliability of their systems in the same manner that is prescribed for military products. The process involves determining the basic reliability of each component that goes into the system.

The reliability estimate is based on field experience and accelerated life testing. The stress that is placed on the device in the application needs to be taken into consideration.

Once the reliability of each component is estimated and the total number of each is known, the total system reliability can be estimated. The overall reliability of a system is usually expressed as MTBF.

The MTBF is usually expressed in hours, and specifies the average number of hours that can be expected between failures in the system. The calculated MTBF is only an estimate and may not really define the actual reliability of the product.

The inaccuracies come about due to the many variables that are hard to determine. Such items as the stress (peak and average current and voltages, and junction temperatures) on the devices are often hard to determine accurately.

Other factors associated with the design are almost impossible to estimate accurately, such as noise susceptibility, effects of accumulated dust combined with humidity, and the thoroughness and correctness of the design.

Improper reactions of the system to faults or disturbances can cause the system to fail, but are not included in component reliability. Proper maintenance and installation are also often assumed in MTBF calculations.

In general, calculated MTBFs should be used as guides when actual field data are not available.

Many factors are involved in making a product as reliable as possible. These factors include design, component selection, workmanship, and conservative rating of the units.

It is very difficult to look at a product and determine its potential for reliable operation. Estimating the

relative performance of various products usually requires sorting through reliability information from manufacturers.

MTBF is an item that can be considered in determining the reliability of a power system installation.

TRANSFORMER PHASE TIME OVERCURRENT RELAY PROTECTION

Time overcurrent relays are inexpensive, simple, and reliable protective devices. Since sensitive settings and fast operation are usually not possible with overcurrent relays, they will provide limited protection for internal transformer faults.

Since the pickup value of phase overcurrent relays must be high enough to take advantage of the overload capabilities of the transformer and be capable of withstanding energizing inrush currents, insensitive settings result.

Fast operation is not possible, since the transformer relays should coordinate with load-side protection, including dealing with reclosing cycles and service restoration inrush. Where time overcurrent relays are used for primary transformer protection, extensive damage to the transformer from an internal fault may occur.

Settings of phase overcurrent relays on transformers involve a compromise between the requirements of operation and protection. The pickup setting should be high enough to permit overloading the transformer when necessary, but the higher the setting, the less the protection.

A setting of 125–150% of maximum kVA nameplate rating of a transformer is common, although higher values are sometimes used. On multiplerated transformers, a higher setting may be necessary so as to utilize the full capability of the transformer at the higher forced-cooling rating.

If overcurrent protection (relays or fuses) is applied only to the high-voltage (Δ) side of a Δ−Y grounded transformer, it can have a problem providing sensitive fault protection for the transformer and still coordinating with low-side protective devices. For low-voltage (Y side) phase-to-phase faults, the high-side line current will be 115% of the low-voltage per unit fault current.

For low-voltage (Y side) phase-to-ground faults, the high-side line current will be only 58% of the low voltage per unit fault current. When the Y is grounded through a resistor, the high-side fault current may be less than the maximum transformer load current.

Similar concerns are applicable when the Y is grounded through a reactor. The time setting should coordinate with relays on downstream equipment. Transformers are mechanically and thermally limited in their ability to withstand short-circuit current for finite periods of time.

For proper backup protection, the relays should operate before the transformer is damaged by an external fault. A for the transformer through-fault current duration limits and relay setting examples.) Solid-state or microprocessor-based relays with special features such as fast reset should be evaluated for coordination with downstream devices.

In setting transformer overcurrent relays, the short-time overload capability of the transformer in question should not be exceeded. Low values of 3.5 or less times normal base current may result from overloading rather than faults. For such cases see IEEE C57.91-1995, since allowable time duration may be different from those in the through-fault current duration curves. Pending establishment of additional transformer standards, it is recommended that the manufacturer be consulted for the capability of a specific transformer.

Distribution supply transformers are subject to many through-faults and autoreclosing into line faults. The use of extremely inverse tripping characteristics for distribution circuit reclosers permits fast clearing of the more severe faults.

Where the use of instantaneous relaying for either transformer or distribution feeder protection is limited, time overcurrent relays with very inverse time characteristics will provide fast clearing for the more severe faults.

GROUNDING TRANSFORMER DIFFERENTIAL RELAYING

Configuration
To establish a grounded system, a grounding transformer is frequently tapped on the low-side leads of the supply transformer and is thereby included in the transformer differential zone.


Problem
Zero sequence current supplied by the grounding transformer may cause differential relay operation during an external ground fault.

Solution
Since external ground faults cause zero sequence current to flow in the CT secondary circuits, a zero sequence filter is provided for the low-side differential Y-connected transformers. This filter is composed of three auxiliary CTs and can be formed in several ways.

The simplest form is to connect the primaries in Y and the secondaries in Δ. In Figure below, the ratio of the auxiliary CTs is not critical, but a 5:5 ratio is suggested.

Grounding transformer in differential zone (external fault condition shown)

The alternative filter connection in Figure 16 requires a 1:3 ratio for the auxiliary CTs. The primaries are connected in Y and the junction or sum of the primaries is wired to the secondaries connected in series.

Thus the secondaries carry three times the primary current. Both of these connections present relatively high magnetizing impedance to all but zero sequence current.

However, modern differential relays are of even lower burden than the usual auxiliary CTs. Thus, the common point of the relay connections should not be connected to the common point of the Y-connected transformers (a connection that is necessary without the zero sequence filter).

Only the filter neutral should be connected to the CT common point. The figure also shows the primary current and CT secondary current for an external ground fault.

The zero sequence filter prevents a relay imbalance. A 1:1 overall voltage ratio is assumed in the figure above with 1 PU fault current flowing.


An application example using an inverse relay has relay pickup at 30% of transformer rating and a time of 1.7 s at 300% of setting. The pickup depends on the effective contribution of the equivalent tertiary of the case.

The transformer manufacturer should be consulted.

TRANSMISSION LINE RELAYING SELECTION TUTORIALS

The selection of line protection requires the consideration of several factors, some of which are mutually exclusive. Knowledge of the most probable failures, recommendations of equipment suppliers, and good practical judgment can assist the protection engineer in determining which of the factors deserve the most emphasis.

One of the most important design considerations of relaying is reliability. Relaying reliability is separated into two aspects: dependability and security. Dependability is defined as “the degree of certainty that a relay or relay system will operate correctly.

” Security is defined as “the degree of certainty that a relay or relay system will not operate incorrectly.” In other words, dependability is a measure of the relay’s ability to operate when it is supposed to operate. Security is a measure of the relay’s ability to avoid operation for all other conditions for which tripping is not desired.

Dependability is relatively easy to obtain in relay design or in the application of a number of relays. Testing using operating conditions, fail-safe designs, and redundancy are methods to ensure dependability. Security is harder to attain; an almost infinite variety of tests would be needed to simulate all possible conditions to which a relay may be exposed.

Various engineering practices can enhance dependability. These include independence of design, different operating principles, redundancy within the relay systems, local backup methods, remote backup methods, and application of relays and relay systems that cause undesirable trips upon failure.

Security can be enhanced by using relays that fail into a “disarmed” mode, series connected protection, improved monitoring and self-checking, and emphasis on high-quality components. Another important design consideration is protection selectivity or coordination.

Selectivity is the ability of relays and relaying systems to cooperate with each other to minimize the outaged area resulting from a fault. Coordination refers to the process of applying relays to operate as fast as possible for conditions with their primary zone, but to have delayed, or coordinated operations for conditions within an extended backup zone.

Selectivity and coordination must be achieved to ensure maximum service continuity. Fault clearing time is an important consideration in the selection of line relaying. Requirements for relaying speed must be carefully determined. If the relaying is too slow, system instability, excessive equipment damage, and adverse effects on customer service may result.

However, faster protection tends to compromise relay system security and selectivity. There is a limit to the speed with which a relay can correctly respond due to the transients present in the power system itself.

Sensitivity of protection refers to the minimum operating quantities that must be available for the relays to detect an abnormal condition. While this factor is still important, most modern relays are using solid state or microprocessor technologies that are many times more sensitive than their electromechanical predecessors.

Certain problems, such as high-impedance ground faults, inherent system voltage unbalances, and high source-to-line impedance ratios (SIRs) still challenge the sensitivity of relays and should be considered in relay selection.

The line protection design may often fail to recognize one of the more important design factors simplicity. The multifunction and programmable capabilities of modern relays have created an abundance of special solutions to possible system problems.

The implementation of these solutions challenges the application engineer, those responsible for setting the relays, and operations and maintenance personnel. The problems caused by incorrect or incomplete implementation of overly complex protection may create more serious consequences than not providing special solutions.

The protection engineer should carefully weigh the consequences and probability of each problem to determine if it justifies using complex special solutions. Economic evaluations of protection options will continue to be necessary. Protection engineers have long pointed to the relatively low cost and high importance of relays compared with the equipment they protect.

However, it is fundamental to attempt to achieve the required protection at the lowest cost. In recent years, more importance has been placed on economic analysis that considers more than just the lowest initial cost. Installation and maintenance costs, as well as the cost of unreliable protection, are sometimes considered.

In addition, modern protection usually offers many features not previously available that may result in improvements in operations, restoration of the system, and post-fault analysis. The value of these improvements should be considered in a complete economic evaluation of alternatives.

Certain transmission system configurations and characteristics require protective relaying with communication systems to provide high-speed clearing for all faults within the zone of protection. Pilot relaying schemes are employed to provide this high-speed fault clearing.

These pilot relaying systems require the transmission of information during a fault between relays that are located in different substations to determine if the fault is internal or external to the zone of protection. This is accomplished using several different methods, ranging from direct hardwire communications to fiber optic communications systems.

Different protection schemes and communication channels have different degrees of reliability. Knowledge of these different communication options is necessary to determine the reliability of the protection scheme being considered. The network configuration and local system loading requirements may also affect the type of pilot protection scheme chosen.

The protection scheme required will often dictate the type of relaying communications that will be used. On the other hand, the relaying communications may limit the types of relay schemes that can be used. Obviously, the requirements of the relaying scheme must be considered, along with the types of communications available.

NON DIRECTIONAL OVERCURRENT RELAY SCHEMES FOR TRANSMISSION LINES

Overcurrent protection is the simplest and least expensive form of fault protection that can be placed on transmission lines. The operating principles depend only on current magnitude. The ac connections for three-phase and one ground time overcurrent (TOC) relays and instantaneous overcurrent (IOC) relays are shown in below.

Connections for overcurrent phase and ground relay

Phase currents or sequence currents can be used as the operating quantity. Phase overcurrent relays operate for all possible fault types, but require their pickup settings to be higher than the maximum expected normal or emergency load flow condition.


Negative and zero-sequence overcurrent relays do not operate for balanced loads or for three-phase faults, but can have pickup settings well below the expected load. Tripping may be instantaneous, delayed for a fixed time, or delayed for a time inversely proportional to the current magnitude.

Figure below shows some of the various shapes of time/current characteristics that may be used.

TYPICAL TOC CURVES

Time Dial 5

Multiples of pu

Time overcurrent curve shape comparison

Instantaneous tripping can be applied if the pickup point of the instantaneous unit can be set higher than the maximum contribution to faults outside the protected line. The percentage of a line that can be protected by an instantaneous overcurrent relay will vary with line length and source impedance.

To protect an entire nonradial line, time delays are generally required to achieve coordination with downstream protective devices.

Figure below shows how coordination is achieved between a relay with a time and instantaneous element (the primary relay), and an upstream (backup relay) with only a time element.

Coordination of time overcurrent relays

To ensure proper coordination, the pickup point of the instantaneous unit should be set higher than the maximum contribution to faults outside the protected line.

The pickup value of the time element should be set to prevent tripping for the maximum load current that can flow in either direction on the line. The time adjustment (i.e., dial) should generally be set to produce the fastest operating time that will not result in miscoordination with other protection behind or in front of the terminal.

The effect of varying the time adjustment is illustrated in Figure below for a typical time overcurrent relay.

Very Inverse

Effect of Time Dial

Varying time adjustment on overcurrent relay characteristic curves

Nondirectional overcurrent relay schemes find limited application on transmission lines. Because transmission lines usually have at least two sources of fault current, the nondirectional elements have to be coordinated with protective devices both in front of and behind the line terminal.

This makes the coordination of nondirectional relays more difficult, and sometimes impossible. In some applications, these relays may be applied only at the terminal with the higher fault current source.

CURRENT TRANSFORMERS POLARITY AND CONNECTIONS FOR RELAYING

Polarity

Polarity marks designate the relative instantaneous directions of currents. At the same instant that the primary current is entering the marked primary terminal, the corresponding secondary current is leaving the similarly marked secondary terminal, having undergone a magnitude change within the transformer (see Figure 1).  

Figure 1 - Current Transformer Polarity

The primary H1 and secondary X1 terminals are marked with white dots, or with a ± symbol, or with H1 and X 1. As illustrated in Figure 1, the marked secondary conductor can be considered a continuation of the marked primary line as far as instantaneous current flow is concerned.

Connections

CTs are usually connected on three-phase circuits in one of three ways, as follows:

a) Wye connection.

In the wye connection, a CT is placed in each phase with timeovercurrent relays (Device 51) placed in either two or three CT secondaries to detect phase faults. On grounded four-wire systems, a time-overcurrent relay (Device 51N) in the CT common wire known as a residually connected relay detects any ground fault or neutral load currents. If neutral load currents are not to be detected by the Device 51N relay as ground-fault currents, a fourth CT is placed in the neutral conductor to cancel the neutral load currents. Secondary currents are in phase with primary currents (see Figure 2).

Figure 2 - Wye connected CT

b)Vee connection.

A vee connection is basically a wye with one leg omitted, using only two CTs. Applied as shown in Figure 3, this connection detects three-phase and phase-to-phase faults. A zero-sequence CT (window or bushing) and a ground overcurrent relay (Device 50GS or Device 51GS) are required to detect ground-fault currents. All three-phase conductors and the neutral (if present) shall pass through the CT.

Figure 3 - Vee or open delta connected CT

c)Delta connection.

A delta connection uses three CTs with the secondaries connected in delta before the connections are made to the relays. The delta connection shown in Figure 4 is typically used for power transformer differential relay protection schemes where the power transformer has delta-wye-connected windings.

Figure 4 - Delta connected CT

The Cts on the delta side are connected in wye, and the CTs on the wye side are connected in delta. The delta connection is also used for overcurrent protection of grounding transformers where filtering out the third-harmonic currents is desirable.

When connected in delta, the current in the relays is equal to times the CT secondary current. This fact should be considered when selecting the primary ratings of CTs and the secondary device ratings of delta connected CTs

OVERCURRENT RELAY RATCHETING

Effects of autoreclosing on disk type overcurrent relays (ratcheting)

Electromechanical disk type time overcurrent relays respond to current above their pickup level in a time inversely proportional to the current level. When the current level is above the pickup, the disk begins to turn and continues to turn until the rotating contact meets the stationary contact to cause a breaker trip or until the current drops below the pickup level, as would occur if the fault were cleared by downstream protection.

Disk reset will occur when the current has dropped below the pickup level for a period of time. The disk resets to its original position at a relatively slow rate by the action of a coil spring.

This relatively slow reset action of the disk should be taken into consideration when autoreclosing is applied to any breaker or circuit recloser downstream of this breaker.

The most common application that requires special care is the circuit recloser operating to clear sections of a feeder downstream of a circuit breaker having disk type overcurrent relays applied. The circuit recloser can autoreclose the faulted section multiple times, resulting in several periods of fault current flow through both the circuit recloser and the upstream circuit breaker.

In a coordinated system, the circuit recloser trips the fault and removes the fault current flow before the disk type overcurrent relays reach their trip point. A minimum safety margin is normally provided to assure good coordination. At the point the overcurrent condition is removed, the disk has rotated some percentage of the amount required to provide a trip.

If the disk is not fully reset by the time the circuit recloser operates to re-energize the faulted section, the disk will not have as far to travel as during the original fault. This ratcheting effect could lead to a loss of coordination resulting in the unnecessary tripping of the circuit breaker.

Another example of ratcheting is an application in which two or more breakers having disk type overcurrent relays are in series. When both encounter an overcurrent condition, different time-dial settings or unequal currents due to load could cause the percentage of disk travel of the upstream relay to vary considerably.

Once again, if autoreclosing of the downstream breaker occurs before the upstream device is reset, a loss of coordination could occur.

Solutions for these loss of coordination events include use of larger safety margins to allow for partial reset of electromechanical relays, application of inverse time relays with fast resets on the upstream breakers, or longer dead times for autoreclosing.

Microprocessor or static relay designs may have an instantaneous reset of the timing function as well as other selective reset characteristics, which is normally considered in the coordination process.

CAPACITOR BANKS OVERCURRENT AND OVERLOAD PROTECTION

Capacitor units in filter banks may require additional duties due to harmonic contents. In these applications, higher voltage capacitor ratings and fuse current ratings may be required. Generally, the additional overloading requirements on component parameters should compensate for higher peak voltages and the increased losses imposed on the reactors and resistor assemblies.


The overcurrent and overload relay in each phase of the filter bank serves two desired protective functions. Fast tripping is initiated for high-level short-circuits near the circuit breaker terminal.

In case of lowmagnitude overcurrents, properly coordinated, time-delayed alarm and tripping signals are initiated due to the abnormal condition on the filter bank. Special emphasis is given to the response of the overcurrent protection (50/51 relay) to harmonic current distortion for some types of solid state electronic relays based on peak current measurements.

In effect, undesired filter bank tripping may occur from these relays as the electronic level detection is influenced by the harmonic phase angle relationships for low-order frequencies (second to fifth) along with the maximum current level detection of the relay.


Digital relays may be influenced by harmonic distortions if the predominant orders of harmonic oscillations are not predicted. The digital band-pass filter response provided in the relay may have a low attenuation factor at a given harmonic frequency and cause undesired tripping of the filter banks.

The expected reliability of the relay protection depends on the protection technology used, the design and manufacturing approaches, and the environment in which the relays are applied. To improve the availability of filter banks, appropriate data and experience related to harmonic distortion shall be considered in the selection of the protection scheme.


Figure below illustrates one possible primary protection scheme for a filter bank. A redundant protection scheme (not illustrated in the figure) may also be provided. The reactor and C2 are tuned to the fundamental frequency to minimize the losses in R at the fundamental frequency in this example.

Sample protection scheme for a filter bank

AUTOMATIC SYNCHRONIZING RELAYS BASIC TUTORIALS

An automatic synchronizing relay is used for synchronizing an incoming generator to a power system. Automatic synchronizing is applied to generating equipment where the station is unattended; where the element of human error should be ruled out in the start-up procedures of a generating unit; or where consistent, accurate, and rapid synchronization is preferred.

The relays used are multifunctional devices that sense the differences in phase angle, voltage magnitude, and frequency of the sources on both sides of an incoming generator breaker and initiate corrective signals to the prime mover and field in order to adjust the generator frequency and voltage until the systems are in synchronism.

Most automatic synchronizing relays can anticipate an advance angle at which to initiate breaker closing so that, when the circuit breaker is closed, the systems are as close to exact synchronism as possible. A synchroscope is used to monitor the synchronizing process.

From the time the relay initiates a close signal until the breaker’s contacts actually close, the needle travels a certain distance (measured in degrees) around the scope. The distance traveled can be determined based on the speed of rotation and how long it was permitted to rotate.

The scope’s needle rotates at a speed that is directly proportional to the slip frequency between the generator and the system. Therefore, given the circuit breaker’s closing time and the desired slip rate, the rotational distance traveled (or advance closing angle) can be determined.


When the generator is to be connected to the system, the appropriate synchronizing switch is selected and closed. The synchronizing equipment performs the following functions automatically:

a) A speed-matching relay element senses the frequency difference between the sources and adjusts the governor with raise or lower signals to control the speed of the incoming generator and thereby matches the frequency of the generator with the frequency of the running system bus.

b) A voltage-matching relay element compares the running system and incoming generator voltages and provides raise or lower signals to the excitation system of the incoming generator so that its voltage matches the running system voltage.

c) As the phase angle between the two systems approaches zero, the relay energizes the circuit breaker's closing circuit at an advance angle determined by the relay so that when the circuit breaker contacts close, the two systems are in synchronism. The synchronizing relay itself has at least two adjustable settings that should be made for correct performance.

One adjustment permits the relay to accommodate breaker closing time, for example, 0.05 s to 0.4 s, and one adjustment sets the maximum phase-angle advance, from 0° to 30-40°. The advance closing angle is calculated by the following expression:

θ = 360(st)

where
θ is advance angle (˚),
s is slip frequency (cycles/s),
t is breaker closing time (s).

For example, for systems coming into synchronism rapidly, that is, s = 0.5 cycles/s, the closing circuit should be energized well in advance of synchronism. If the circuit breaker has a 0.15 s closing time, the advance angle required would be 27°.

If the slip frequency is much lower, then the advance angle is much smaller. For a 0.1 cycle/s slip frequency, the closing angle is now 5.4°. Thus, precise control of the point of synchronism can be obtained.

Several different schemes for automatic synchronizing can be developed depending on economics, reliability, and operating system requirements. By using electromagnetic relays, several relays are required to perform all functions. Static relays provide all the functions in one unit.

ELECTROMECHANICAL AND STATIC RELAY OPERATING PRINCIPLES

Protective relays generally operate in response to one or more electrical quantities to open or close contacts or to trigger thyristors. (An exception is a thermal relay, which operates in response to temperature levels.) Relays are constructed using either electromechanical or static principles.

Electromechanical relay operating principle

Electromechanical relays have only two operating principles:
— Electromagnetic attraction
— Electromagnetic induction

Electromagnetic attraction relays operate by having either a plunger drawn by a solenoid or an armature drawn to a pole of an electromagnet. This type of relay operates from either an ac or a dc current or voltage source and is used for instantaneous or high-speed tripping.

Electromagnetic induction relays use the principle of the induction motor, where torque is developed by induction into a rotor. This principle is used in an electromechanical watthour meter, where the rotor is a disk.

The actuating force developed on the rotor is a result of the interaction of the electromagnetic fluxes applied and the flux produced by eddy currents that are induced in the rotor. Induction relays can only be used in ac applications, and the rotor is normally a disk or a cylinder.

Time-overcurrent, time-undervoltage, and time-overvoltage relays commonly are of the disk design, while cup (cylinder) structures are often found in high-speed overcurrent, directional, differential, and distance relays.

Static relay operating principle
Static relays are either analog or digital. Static analog relays were first introduced in the early 1960s and were typically designed to emulate the characteristics of their electromechanical counterparts. Soon, digital technology was implemented in relay design with characteristics available that were outside the capabilities of the electromechanical design.

Operation of the static design converts input signals to an appropriate magnitude for measurement within the relay, which is in direct proportion to the system signal. The measured value is then compared against a predetermined setting.

Timing and other characteristics are derived from either the analog circuit design or algorithms within a microprocessor.

TESTING OF BUS DIFFERENTIAL RELAYING

The testing of bus differential relays and associated systems requires special care and accuracy on the part of the tester. The consequences of an inadvertent trip, due to tester error or of a false trip due to incorrect or incomplete test practices, are usually severe in that numerous circuits can be affected.

Practices have been developed which considerably ease the problems facing the relay tester and improve quality and thoroughness. Specific practices are as follows.

Test Switches
Many utilities provide a test switch in each output circuit and in the coil of the lockout relay or other auxiliary devices used to control multiple breakers. These test switches are used to ensure that no inadvertent trip occurs when removing the relay from service or returning it to service.

Test switches are also of significant value when performing trip tests in that the breakers can be tripped and closed one at a time to verify the integrity of the relay output circuitry. Covers are usually provided which cannot be put in place until the test switches are returned to their normal position.

Permanent Test Facilities
Permanently installed test equipment has been designed to check some types of differential relay circuits while the power circuit is in operation. These facilities use indicating meters to monitor pre selected points in the relay circuit by means of a test selector switch. These types of test systems are described in the manufacturers’ literature.

Verification of Relay Input Sources
Many problems with bus differential relay systems can be attributed to improper connections of current transformers and associated circuitry. Consequently, it is important to verify the ratio and polarity of the current transformers and the connections to the relays.

Procedures for performing the above tests are well known throughout the industry. However, if not properly performed, failure to trip or false trips will result.

AUXILIARY TRIPPING RELAYS FOR BUS PROTECTION

Bus protection relays usually energize a multicontact auxiliary relay which has individual tripping contacts for each breaker connected to the bus.

Lockout Relays
A common practice is to use a lockout type tripping relay to prevent reenergizing the bus until an inspection is made.

It may also be desirable to interrupt the breaker closing circuits by separate lockout relay contacts connected in the closing circuit of each breaker to prevent breaker closing, even though the breaker would be immediately tripped by the unreset lockout relay tripping contacts.

One type of lockout tripping relay is spring actuated, with a latch released by a tripping solenoid. In one version of this relay a manually operated handle is used to reset the relay.

In another version, a motor performs this reset function so that the relay can be reset remotely.

A second type of lockout relay uses an electrical seal-in coil to lock itself in the operated position. The seal in coil is energized by one of the tripping contacts on the relay.

A reset pushbutton momentarily opens the energized seal-in coil to reset the relay. A third type of lockout relay has a mechanical latch that is reset electrically.

Nonlockout Relays
Nonlockout (self-reset) tripping relays are used in some installations to permit automatic reenergization of a bus. A self-reset relay automatically resets when its coil is deenergized (in the case of bus protection, this means when the fault is cleared).

It is often used at unattended locations where there is open bus work, no supervisory or remote control facilities are provided, and operator travel time is long. Hence, automatic reenergization of a bus will reduce outage time if successful.

Ratings and Connections
Bus tripping auxiliary relays are usually selected with underrated trip coils to obtain fast and positive operation. With a 130 V dc tripping supply a 24 V rated coil is frequently used.

With lockout type relays two b contacts of the relay are usually connected in series with the operating coil to interrupt the coil current after the relay operates. This sudden interruption of the coil current may produce a high transient voltage across the coil.

Diodes are sometimes used to minimize the effect of this transient voltage not only on this coil, but also on other portions of the control circuitry or other solid state components.

As with any auxiliary tripping relay, it may be necessary to use resistors in parallel with the relay coil to be sure that the target coils of the bus protection relays receive sufficient current to operate. If these resistors are used, they may eliminate the need for diodes to limit the aforementioned transient voltages.

CURRENT TRANSFORMER ACCURACY CLASSIFICATION FOR RELAYING

Since a current transformer has a magnetic core, it may not have a linear operating characteristic over the desired operating range of primary current. This results in a variation of ratio and possible variation of phase angle between primary and secondary currents for different values of primary current.

This phenomenon is called saturation. In addition to magnitude of ac current, factors that affect this saturation are the following.

Transient Current
The transient dc component of short circuit current is a major cause of current-transformer saturation and consequent misoperation of some bus differential systems. The maximum flux density in the current transformer core, attributable to the dc component of fault current, varies with the time current of the dc transient.

Hence, the L/R ratio of the system impedance which determines the fault current should strongly influence the type of bus protective relaying which is selected. Typically the dc time constants for the different circuit elements can vary from 0.01 s for lines to 0.3 s or more for generating plants.

The nearer a bus location is to a strong source of generation, the greater the L/R ratio and resulting dc component of fault current.

Impedance of Secondary Current Transformer Leads and Associated Relays, Meters, and Auxiliary Current Transformers 
Lead resistance, as well as current transformer winding resistance, contributes to core saturation. Therefore, length of secondary lead runs should be held to a minimum.

However, location of a breaker and its associated current transformer is determined by physical requirements. Hence, the planning stage must ensure that the type and rating of current transformer and its location with respect to the protected bus are comparable with the proposed bus protection scheme.

Where lead runs are excessive, an increase in wire size or use of parallel conductors are means to reduce lead resistance. Location of the differential relay junction points in the breaker yard rather than at the relay location is also practiced.

The preferred practice is to use current transformers dedicated to bus differential protection only. If possible, connection of meters, auxiliary current transformers, and other relays in differential type bus schemes should be avoided since these devices introduce additional burden into the current transformer circuit.

Current Transformer Accuracy Classification for Relaying
ANSI/IEEE C57.13-1978, Requirements for Instrument Transformers, establishes relaying accuracy classifications for relaying current transformers. Because relaying current transformers must operate at high overcurrent levels, ANSI classifications define minimum steady-state performance at those levels.

Performance is described by an identification system which consists of a letter and a number selected from the following: (C, T) (10, 20, 50, 100, 200, 400, 800). The first term describes performance in terms relative to construction.

The C classification covers bushing current transformers with uniformly distributed windings and any other current transformer in which leakage flux has negligible effect on ratio error. Ratio correction at any current can be adequately calculated by knowing the burden and the excitation characteristic.

The T classification covers most wound-type current transformers and any other current transformer in which leakage flux has an appreciable effect on ratio. Ratio correction must, therefore, be determined by test.

The C and T classification is applicable to all tap sections of a current transformer winding. The second term of the classification is the secondary terminal voltage rating.

It specifies the secondary voltage that can be delivered by the full winding at 20 times rated secondary current without exceeding 10% ratio correction. Furthermore, ratio correction is limited to 10% at any current from 10 to 20 times rated current at any lesser burden.


The ANSI secondary voltage rating applies only to the full winding. If other than the full winding is used, the voltage rating is reduced in approximate proportion to turns used.

As an example, relay accuracy Class C100 means that ratio correction can be calculated and that it will not exceed 10% at any current from I to 20 times rated secondary current if the burden does not exceed 1.0 W (1.0 W times 5 A times 20 times rated current equals 100 V).

GROUND FAULT PROTECTION OF POWER TRANSFORMERS

Faults in Δ-connected transformer windings
A residual relay, device 51N, as shown in Figure 8 and Figure 9, will detect ground faults within the Δ winding of the transformer and in the phase conductors between the CTs and the winding, when an external source of zero sequence current is available. Instantaneous overcurrent relays may be used, but sensitive settings will probably result in incorrect operations from dissimilar CT saturation and magnetizing inrush.

This can be avoided by using a short-time overcurrent relay with a sensitive setting. The scheme is particularly valuable in plants or systems where the transformers are remote from the circuit breakers. By using CTs at the circuit breaker, sensitive detection is obtained for cable, bus, Δ winding, and bushing faults.

A single window or doughnut CT supplying an instantaneous relay (as commonly used in motor protection) is secure, but is limited to cases of low and medium voltages where all three conductors can be fitted through the CT window.

Figure 8—Complete ground fault protection of a Δ-Y transformer using a residual overcurrent and differentially connected ground relay

Figure 9—Complete ground fault protection of a Δ-Y transformer using a residual overcurrent and directional relay


Faults in grounded Y-connected transformer windings
To successfully detect faults in grounded Y-connected transformer windings, the relay system should discriminate between faults internal and external to the protected zone. The ground differential relay, device
87G in Figure 8, typically an overcurrent relay, or the directional ground relay, device 67G, connected as in Figure 9, is satisfactory. Both relay schemes will operate correctly for any internal ground faults with the circuit breaker in the circuit to the grounded Y winding open or closed.

They will operate correctly with an external zero sequence current source, and they will not operate for external ground faults. The auxiliary CT is necessary if the phase and neutral CTs are of different ratio. Both schemes are particularly applicable where the ground fault current is limited and phase differential relays may not respond.

The device 67G operating coil or element current is zero for an external fault with CT ratios matched. Therefore, it is wise to select the auxiliary CT ratio to give positive nontrip bias to device 67G for an external ground fault (auxiliary CT secondary current slightly greater than the transformer neutral CT secondary current). Unequal CT action can produce residual error current during external phase faults. No transformer neutral current is produced and sensitive relays could misoperate.


Case ground
On a grounded neutral system, it is possible to isolate the transformer case from ground except for a single point. A CT and overcurrent relay at this grounding point would detect any internal ground fault or bushing flashover.

Although effective, several problems are encountered. The system should be tested periodically to determine that no accidental grounds have been added.

Incorrect operations can result from accidental grounds from power tools and transformer auxiliary equipment. Careful coordination between auxiliary equipment circuit breaker or fuse curves, arrester characteristics, and a time overcurrent trip relay can minimize this danger.

Impedance-grounded system
Transformer differential relays may not be sensitive enough to operate on ground faults where the transformer bank or system is grounded through an impedance. In these cases, it may be necessary to apply a sensitive time overcurrent relay in the transformer impedance-grounded neutral or a time overvoltage relay connected across the neutral impedance.

These relays should be coordinated with any feeder and line protection relays that they may overlap. It is possible to provide high-speed protection and to avoid the need for coordination by using sensitive product-type relays, which are connected to trip only for ground in the protected zone.

An overcurrent relay connected to a neutral CT is torque-controlled by the blocking contacts of a plunger-type instantaneous relay in the neutral of the main breaker CTs. Since the transformer differential relays may not operate for such ground faults within the differential zone, these ground fault relays must trip the source-side circuit breakers.

Ground relays also used for sensitive ground fault protection
The primary advantage of ground relays over phase relays is their sensitivity. In systems where the ground fault current is purposely limited, their use may be vital. Ground relays can normally be applied with sensitivities of 10% or less of full load current.

This compares very favorably with differential relays, whose pickup current may be from 20–60% of full load current under the most advantageous conditions. It is common practice in the United Kingdom and other countries influenced by the U.K. to protect all power transformers with the restricted earth relay.

The term restricted earth is an expression referring to a sensitive ground relay system that is designed to detect ground faults within a well-defined protective zone (similar to that in Figure 8)

TURBINE UNDER FREQUENCY PROTECTION RELAY SCHEMES AS PER IEEE C37.106-2003

The turbine underfrequency protection scheme may be accomplished by one or more relays. Digital or solid state relays are preferred for their accuracy over a broad frequency range. The required number of frequency setpoints and their associated time delays are dependent upon the characteristics of the turbine.

This relay function may be included in a multifunctional protection package. The first step in designing an underfrequency protection scheme is determining the turbine’s abnormal frequency operating characteristic.

Consultation with the manufacturer should provide the initial design parameters. Modifications to the turbine as well as the known condition from turbine inspections may result in changes to the either the resonant frequency or the allowable abnormal frequency operate time or to both.

From this information, the number of frequency levels that require action can be identified. It should be noted that extreme frequency variations may not require underfrequency relay action as other plant equipment will force the plant to trip.

Once the number of frequency steps is known, the time delay for each step must be determined. Because the allowable underfrequency operation time cannot be identified exactly, some margin should be included in the time delay.

This would allow tripping of the unit prior to damage, with the opportunity to inspect the turbine at the owner’s convenience during a future outage. This allows for application of underfrequency protection, even if the unit has been in operation for many years without having accumulated previous underfrequency operational data.

The time delay margins should consider the importance of the unit, the susceptibility of the system to an underfrequency event and operating agreements with local or regional power authorities. A range of 50–90% of the allowable time per expected event over the blading life is reasonable.

Settings of 50% should be considered if the turbine is in poor condition, there is a high possibility of an underfrequency event or if the unit is not system critical. If the unit is in good condition, an underfrequency event is unlikely, and the unit is critical to the system, a setting near 90% of the allowable underfrequency time should be considered.

It should be recognized that some underfrequency relay timers have an instantaneous reset once the frequency rises above the trip setting, while others accumulate the underfrequency operate time in a memory function (zero reset). The time delay setting should be a smaller percentage of the allowable time if the relay is of the instantaneous reset type, whereas the zero reset relay can be set at a greater percentage of the allowable time.

Figure below will be used to demonstrate an underfrequency relay setting. The example indicates the turbine is capable of continuous operation at frequencies above 58.5 Hz and is limited to a maximum of 10 minutes accumulated over the blading life at 56.0 Hz.

Example of turbine abnormal frequency limitations and settings

These are operating conditions with the turbine at load. The underfrequency relay trip point setting should be set just above 56.0 Hz to allow for relay margin. A setting of 56.2 Hz could be selected. A time delay setting of seven minutes could be used if the unit is in fair condition, not critical to the operation of the system, and it is acceptable to lose 70% of the fatigue life of the blading.

If the unit is in good condition and is critical to the system, a longer time delay of nine minutes could be used to allow the maximum opportunity for system recovery, prior to tripping the unit assuming these events are very rare so that 90% of the fatigue life can be expended on it. An alarm should be provided when the underfrequency relay begins to time out, providing operating personnel a warning of the impending underfrequency trip.

Many operators apply a single multilevel relay having four frequency set points. In many cases, one of the frequency set points will be used to alarm at a relatively high frequency (59.4 Hz for example) to indicate the inception of an abnormal frequency event, with the remaining three set points are at lower frequencies corresponding to the turbine characteristics.


If IEC 60034-3:1996 is applicable, time-frequency protection could be required by a manufacturer for the turbine generator. If such a situation was to develop, the more restrictive of the generator and turbine frequency requirements, over a frequency band, should be used in the determination of appropriate frequency settings for underfrequency relaying. The frequency capability of the generator, when applicable, must be considered in the development of the frequency relay protection scheme.

PROTECTIVE RELAY CURRENT TYPES - BASICS

Relay current
Two characteristics of power transformers combine to complicate detection of internal faults with current operated relays

a)The change in magnitude of current at the transformer terminals may be very small when a limited number of turns are shorted within the transformer.

b)When a transformer is energized, magnetizing inrush current that flows in one set of terminals may equal many times the transformer rating. These and other considerations require careful thought to obtain relay characteristics best-suited to the particular application.

Minimum internal faults
The most difficult transformer winding fault for which to provide protection is the fault that initially involves one turn. A turn-to-turn fault will result in a terminal current of much less than rated full-load current.

For example, as much as 10% of the winding may have to be shorted to cause full-load terminal current to flow. Therefore, a single turn-to-turn fault will result in an undetectable amount of current.

Maximum internal faults
There is no limit to the maximum internal fault current that can flow, other than the system capability, when the fault is a terminal fault or a fault external to the transformer but in the relay zone. The relay system should be capable of withstanding the secondary current of the CT on a short-time basis.

This may be a factor if the transformer is small relative to the system fault and if the CT ratio is chosen to match the transformer rating.

Through-faults
Fault current through a transformer is limited by the transformer and source impedance. While current through a transformer thus limited by its impedance can still cause incorrect relay operations or even transformer failure, CT saturation is less likely to occur than with unlimited currents.

The above favorable aspect may disappear if the transformer protective zone includes a bus area with two or more breakers on the same side of the transformer through which external fault current can flow with no relationship to the transformer rating. An example is a transformer connected to a section of a ring bus with the transformer protection including the ring bus section.

STATOR WINDING PROTECTION RELAYING

Deterioration of the electrical insulating system of stator windings is a common cause of reduced motor life and failure. This may result from numerous causes, such as subjecting the insulation to moisture, excessive dielectric stress, and mechanical or thermal damage.

The physical and dielectric properties of an insulation system deteriorate with age, and like other chemical activity, this process is accelerated by an elevation in temperature. A rule of thumb has been developed from tests and experience to indicate that the life of an insulation system is approximately halved for each 10 °C incremental increase of winding temperature, and approximately doubled for each 10 °C decrease (the range of 7 °C–12 °C is indicated for modern insulation systems). Thus, insulation life is related to the length of time the insulation is maintained at a given temperature.

In practice, winding failures resulting from dielectric breakdown are usually attributed to conditions such as impulse or switching surge voltage, moisture, penetration, or conducting contaminants. Mechanical stresses, such as vibration or distortion forces, can also cause winding failures.

These forces occur most often when starting the motor, or possibly during a transfer to another electrical source. Regardless of the reason associated with the failure, the effect of elevated temperature is to reduce the ability of the insulation to withstand electrical or mechanical abuse.

The temperature level at which an insulation system should be protected is subject to engineering judgment and applicable standards. (For limits established by the motor industry, see NEMA MG1-1998, Articles 12.41, 12.42, and 12.52. For induction motors, see NEMA MG1-1998, Article 20.40. For synchronous motors, see NEMA MG1-1998, Article 21.40.)

It should be noted that deriving increased output at the price of higher temperatures for any given motor means accepting a shorter life. However, when motors are used in essential or critical service, such as for fire pumps or boiler-feed pumps, it is often desirable that the operator be given time to correct an overload condition before a motor is stopped.

Such service may require the motor to run overloaded for prolonged periods, in situations where the overload does not exceed the breakdown torque rating of the motor. In these cases, the cost of reduced motor life due to the overload conditions must be weighed against the expense and damage that would result from a service interruption.


Motor overloading
Overloads can produce stator total hot spot temperatures in excess of the designed thermal limits of the winding insulation system. However, in all cases of operation that result in overtemperature, time is an important factor.

The heat storage capacity of an induction motor is relatively large. Slight overloading for short periods of time does not result in damaging temperature excursions, because the extra heat is stored in the mass of the conductor, core, and structural members. In contrast, for locked-rotor conditions, the rate of temperature increase is very rapid due to the large currents.

Since very little heat is transmitted (in this short time interval) from the conductors to the more massive parts of the motor, the thermal limits of the winding insulation may be reached within seconds.