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Arc-resistant low voltage switchgear

Arc-resistant low voltage switchgear

For years, electrical equipment has been designed to withstand and deal with the issue of bolted faults, where the current spikes to a dangerously high level but is safely interrupted by the protective devices contained in the equipment (breakers, fuses and relays). However, these devices typically do not detect and interrupt dangerous internal arcing faults, which have a lower current level, but can generate a far more dangerous scenario for operating personnel.

Arc faults can be caused by a breakdown of insulation materials, objects coming into close proximity with the energized bus assembly, even entry of rodents or other animals into the equipment. The thermal energy created by these events can get as high as 35,000ºF, melting materials and clothing from several feet away. Also consider that the arc blast produced by a lineup of 480 Vac switchgear rated at 85 kA can be equivalent to 20.7 lbs of TNT!


So, what is the solution?

Eaton’s solution: arc-resistant low voltage switchgear

Eaton introduces the addition of an ANSI Type 2 arc-resistant low voltage switchgear offering to its current product line. This is the latest release in arc-safe equipment from Eaton’s Electrical Sector. The arc-resistant low voltage switchgear protects operating and maintenance personnel from dangerous arcing faults
by redirecting or channeling the arc energy out the top of the switchgear, regardless of the origination location of the arc.

Eaton’s arc-resistant low voltage switchgear has been successfully tested to ANSI C37.20.7 at KEMA-Powertest, and has been ULT witnessed and certified.

Standard features
  • Ratings:
    • Up to 100 kA short circuit at 508 Vac maximum and up to 85 kA short circuit at 635 Vac maximum
    • Up to 10 kA horizontal main bus continuous current
    • Up to 5 kA vertical bus continuous current
    • MagnumE DS power circuit breaker frame ratings between 800A and 6000A
  • ANSI Type 2 arc-resistant design protects the operator around the entire perimeter of the equipment
  • Floor-to-ceiling height of 10 feet required whether exhausting into a room or through an arc plenum
  • Strengthened one-piece breaker door and latches
  • Dynamic flap system on rear ventilation openings that remain open under normal operating conditions, but close during an arcing event to prevent dangerous gasses from escaping
  • Patented bellows design allowing drawout of breaker into the disconnected position with the door closed, while simultaneously protecting the operator from any dangerous gasses during an arc event
  • Patented venting system that directs arc gasses out the top of the enclosure, regardless of the arc origination location
  • Up to four-high breaker configuration with no additional layout restrictions
  • Strengthened side and rear panels with standard split rear covers for cable access
  • NEMAT 1 enclosure, with either top or bottom cable or bus duct entry
  • Cable compartment floor plates


Optional features
  • Zone selective interlocking protection
  • ANSI Type 2B arc-resistant design protects the operator even with the low voltage instrument compartment door open
  • Arcflash Reduction Maintenance SystemE
  • Safety shutters
  • One-piece hinged and bolted rear panel
  • Insulated bus
  • Vented bus/cable compartment barrier
  • Cable compartment segregation barrier



  • Superior protection against arcs in breaker, bus or cable compartments
  • No increase in footprint over regular Magnum DS switchgear
  • Closed door racking
  • UL 1558 and UL 891
  • ANSI C37.20.1, ANSI C37.13, ANSI C37.51 and ANSI C37.20.7
  • CSAT standard—CSA C22.2 No. 31-04
  • Third-party (UL/CSA) witness tested
  • Seismic certification 2006-IBC

Testing procedures were completed per ANSI C37.20.7 standards with arcs initiated in:

  • Breaker compartment
  • Vertical and horizontal bus
  • Cable termination compartments

Additionally, the tested arc duration was up to the full 0.5 seconds recommended by ANSI C37.20.7, with no dependence on the tripping speed of an upstream breaker.

Related articles

There are two methods for indicating protection relay functions in common use. One is given in ANSI Standard C37-2, and uses a numbering system for various functions. The functions are supplemented by letters where amplification of the function is required. The other is given in IEC 60617, and uses graphical symbols. To assist the Protection Engineer in converting from one system to the other, a select list of ANSI device numbers and their IEC equivalents is given in Figure A2.1.

ANSI/IEC Relay Symbols


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Siemens technical publication | Loss Of Vacuum

Siemens technical publication | Loss Of Vacuum

If a vacuum interrupter should lose vacuum, several operating situations should be considered:

1. With contacts open
2. When closing
3. When closed and operating normally
4. When opening and interrupting normal current
5. When opening and interrupting a fault.

Cases 1, 2 and 3 are relatively straightforward. Generally, the system sees no impact from loss of vacuum in such a situation. Cases 4 and 5, however, require further discussion. Suppose there is a feeder circuit breaker with a vacuum interrupter on phase 3 that has lost vacuum. If the load being served by the failed interrupter is a deltaconnected (ungrounded) load, a switching operation would not result in a failure. Essentially, nothing would happen. The two good phases (phase 1 and phase 2, in this example) would be able to clear the circuit, and current in the failed interrupter (phase 3) would cease.

The alternative case of a grounded load is a different situation. In this case, interruption in the two good phases (phase 1 and phase 2) would not cause current to stop flowing in phase 3, and the arc would continue to exist in phase 3. With nothing to stop it, this current would continue until some backup protection operated. The result, of course, would be destruction of the interrupter.

Since the predominant usage of circuit breakers in the 5-15 kV range is on grounded circuits, we investigated the impact of a failed interrupter some years ago in the test lab. We intentionally caused an interrupter to lose vacuum by opening the tube to the atmosphere. We then subjected the circuit breaker to a full short circuit interruption. As predicted,
the “flat” interrupter did not successfully clear the affected phase, and the “flat” interrupter was destroyed. The laboratory backup breaker cleared the fault. Following the test, the circuit breaker was removed from the switchgear cell. It was very sooty, but mechanically intact. The soot was cleaned from the circuit breaker and the switchgear cell, the faulty interrupter was replaced, and the circuit breaker was re-inserted in the cell. Further short circuit interruption tests were conducted the same day on the circuit breaker.

Field experience in the years since that test was conducted supports the information gained in the laboratory experiment. One of our customers, a large chemical operation, encountered separate failures (one with an air magnetic circuit breaker and one with a vacuum circuit breaker) on a particular circuit configuration. Two different installations, in different countries, were involved. They shared a common circuit configuration and failure mode. The circuit configuration, a tie circuit in which the sources on each side of the circuit
breaker were not in synchronism, imposed approximately double rated voltage across the contact gap, which caused the circuit breaker to fail. Since these failures resulted from application in violation of the guidelines of the ANSI standards, and greatly in excess of the design ratings of the circuit breakers, they are not indicative of a design
problem with the equipment.

However, the damage that resulted from the failures is of interest. In the case of the air magnetic circuit breaker, the unit housing the failed circuit breaker was destroyed, and the adjacent switchgear units on either side were damaged extensively, requiring significant rebuilding. The air magnetic circuit breaker was a total loss. In the case of the vacuum circuit breaker, the failure was considerably less violent. The vacuum interrupters were replaced, and the arc by-products (soot) cleaned from both the circuit breaker and the compartment. The unit was put back into service. Our test experience in the laboratory, where we routinely explore the limits of interrupter performance, also supports these results.

More recently, several tests were performed in our high-power test laboratory to compare the results of attempted interruptions with “leaky” vacuum interrupters. A small hole (approximately 1/8” diameter) was drilled in the interrupter housing, to simulate a vacuum interrupter that had lost vacuum.

The results of these tests were very interesting:

  1. One pole of a vacuum circuit breaker was subjected to an attempted interruption of 1310 A (rated continuous current = 1250 A). The current was allowed to flow in the “failed” interrupter for 2.06 seconds, at which point the laboratory breaker interrupted. No parts of the “failed” circuit breaker or the interrupter flew off, nor did the circuit breaker explode. The paint on the exterior of the interrupter arcing chamber peeled off. The remainder of the circuit breaker was undamaged.
  2. A second pole of the same vacuum circuit breaker was subjected to an attempted interruption of 25 kA (rated interrupting current = 25 kA), for an arc-duration of 0.60 seconds, with the laboratory breaker interrupting the current at that time. The arc burned a hole in the side of the arc chamber. The circuit breaker did not explode, nor did parts of the circuit breaker fly off. Glowing particles were ejected from the hole in the arcing chamber. None of the mechanical components or other interrupters were damaged. Essentially, all damage was confined to the failed interrupter.

Our experience suggests rather strongly that the effects of a vacuum interrupter failure on the equipment are very minor, compared to the impact of failures with alternative interruption technologies. But the real question is not what the results of a failure might be, but rather, what is the likelihood of a failure? The failure rate of Siemens vacuum interrupters is so low that loss of vacuum is no longer a significant concern. In the early 1960s with early vacuum interrupters, it was a big problem. A vacuum interrupter is constructed with all connections between dissimilar materials made by brazing or welding. No organic materials are used. In the early years, many hand-production techniques were used, especially when borosilicate glass was used for the insulating envelope, as it could not tolerate high temperatures. Today, machine welding and batch induction furnace brazing are employed with extremely tight process control. The only moving part inside the interrupter is the copper contact, which is connected to the interrupter end plate with a welded stainless steel bellows. Since the bellows is welded to both the contact and the interrupter end plate, the failure rate of this moving connection is extremely low. This accounts for the
extremely high reliability of Siemens vacuum interrupters today.

In fact, the MTTF (mean time to failure) of Siemens power vacuum interrupters has now reached 24,000 years (as of October 1991). Questions raised by customers regarding loss of vacuum were legitimate concerns in the 1960s, when the use of vacuum interrupters for power applications was in its infancy. At that time, vacuum interrupters suffered from frequent leaks, and surges were a problem. There was only one firm that offered vacuum circuit breakers then, and reports suggest that they had many problems. We entered the vacuum circuit breaker market in 1974, using Allis-Chalmers’ technology and copper-bismuth contact materials. In the early 1980′s, after becoming part of the worldwide Siemens organization, we were able to convert our vacuum designs to use Siemens vacuum interrupters, which had been introduced in Europe in the mid-1970s. Thus, when we adopted the Siemens vacuum interrupters in the U.S., they already had a very well established field performance record.

The principle conceptual differences in the modern Siemens vacuum interrupters from the early 1960s designs lies in contact material and process control. Surge phenomena are more difficult to deal with when copper-bismuth contacts are used than with today’s chromecopper contacts. Similarly, leaks were harder to control with vacuum interrupters built largely by hand than with today’s units. Today, great attention is paid to process control and elimination of the human factor (variability) in manufacture. The result is that the Siemens vacuum interrupters today can be expected to have a long service life and to impose dielectric stress on load equipment that is not significantly different from the stresses associated with traditional air magnetic or oil circuit breakers.


Published by: SIEMENS AG


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Adjustment Of Protection Relays Parameters

Adjustment Of Protection Relays Parameters

The successful operation of an MV distribution system depends on the proper selection and setting of switchgear relays.

Protective relays are arguably the least understood component of medium voltage (MV) circuit protection. In fact, somebelieve that MV circuit breakers operate by themselves, without direct initiation by protective relays. Others think that the operation and coordination of protective relays is much too complicated to understand. Let’s get into the details and eliminate these misbeliefs.

Background information

The IEEE Standard Dictionary defines a circuit breaker as follows:

A device designed to open and close a circuit by nonautomatic means, and to open the circuit automatically on a predetermined overload of current without injury to itself when properly applied within its rating.

By this definition, MV breakers are not true circuit breakers, since they do not open automatically on overcurrent. They are electrically operated power-switching devices, not operating until directed by some external device to open or close. This is true whether the unit is an air, oil, vacuum, or [SF.sub.6] circuit breaker. Sensors and relays are used to detect the overcurrent or other abnormal or unacceptable condition and to signal the switching mechanism to operate. The MV circuit breakers are the brute-force switches while the sensors and relays are the brains that direct their functioning.

The sensors can be current transformers (CTs), potential transformers (PTs), temperature or pressure instruments, float switches, tachometers, or any device or combination of devices that will respond to the condition or event being monitored. In switchgear application, the most common sensors are CTs to measure current and PTs to measure voltage. The relays measure sensor output and cause the breaker to operate to protect the system when preset limits are exceeded, hence the name “protective relays.” The availability of a variety of sensors, relays, and circuit breakers permits the design of complete protection systems as simple or as complex as necessary, desirable, and economically feasible.

Electromechanical relays

Electromechanical relay

Electromechanical relay

For many years, protective relays have been electromechanical devices, built like fine watches, with great precision and often with jeweled bearings. They have earned a well-deserved reputation for accuracy, dependability, and reliability. There are two basic types of operating mechanisms: the electromagnetic-attraction relay and the electromagnetic-induction relay.

Magnetic attraction relays. Magnetic-attraction relays, have either a solenoid that pulls in a plunger, or one or more electromagnets that attract a hinged armature. When the magnetic force is sufficient to overcome the restraining spring, the movable element begins to travel, and continues until the contact(s) close or the magnetic force is removed. The pickup point is the current or voltage at which the plunger or armature begins to move and, in a switchgear relay, the pickup value can be set very precisely.

These relays are usually instantaneous in action, with no intentional time delay, closing as soon after pickup as the mechanical motion permits. Time delay can be added to this type of relay by means of a bellows, dashpot, or a clockwork escapement mechanism. However, timing accuracy is considerably less precise than that of induction-type relays, and these relays are seldom used with time delay in switchgear applications.

Attraction-type relays can operate with either AC or DC on the coils; therefore, relays using this principle are affected by the DC component of an asymmetrical fault and must be set to allow for this.

Induction relays. Induction relays, are available in many variations to provide accurate pickup and time-current responses for a wide range of simple or complex system conditions. Induction relays are basically induction motors. The moving element, or rotor, is usually a metal disk, although it sometimes may be a metal cylinder or cup. The stator is one or more electromagnets with current or potential coils that induce currents in the disk, causing it to rotate. The disk motion is restrained by a spring until the rotational forces are sufficient to turn the disk and bring its moving contact against the stationary contact, thus closing the circuit the relay is controlling. The greater the fault being sensed, the greater the current in the coils, and the faster the disk rotates.

A calibrated adjustment, called the time dial, sets the spacing between the moving and stationary contacts to vary the operating time of the relay from fast (contacts only slightly open) to slow (contacts nearly a full disk revolution apart). Reset action begins when the rotational force is removed, either by closing the relay contact that trips a breaker or by otherwise removing the malfunction that the relay is sensing. The restraining spring resets the disk to its original position. The time required to reset depends on the type of relay and the time-dial setting (contact spacing).

With multiple magnetic coils, several conditions of voltage and current can be sensed simultaneously. Their signals can be additive or subtractive in actuating the disk. For example, a current-differential relay has two current coils with opposing action. If the two currents are equal, regardless of magnitude, the disk does not move. If the difference between the two currents exceeds the pickup setting, the disk rotates slowly for a small difference and faster for a greater difference. The relay contacts close when the difference continues for the length of time determined by the relay characteristics and settings. Using multiple coils, directional relays can sense direction of current or power flow, as well as magnitude. Since the movement of the disk is created by induced magnetic fields from AC magnets, induction relays are almost completely unresponsive to the DC component of an asymmetrical fault.

Most switchgear-type relays are enclosed in a semiflush-mounting drawout case. Relays usually are installed on the door of the switchgear cubicle. Sensor and control wiring are brought to connections on the case. The relay is inserted into the case and connected by means of small switches or abridging plug, depending on the manufacturer. It can be disconnected and withdrawn from the case without disturbing the wiring. When the relay is disconnected, the CT connections in the case are automatically shorted to short circuit the CT secondary winding and protect the CT from overvoltages and damage.

Many relays are equipped with a connection for a test cable. This permits using a test set to check the relay calibration. The front cover of the relay is transparent, can be removed for access to the mechanism, and has provisions for wire and lead seals to prevent tampering by unauthorized personnel.

Solid-state relays

Solid state relay

Solid state relay

Recently, solid-state electronic relays have become more popular. These relays can perform all the functions that can be performed by electromechanical relays and, because of the versatility of electronic circuitry and microprocessors, can provide many functions not previously available. In general, solid-state relays are smaller and more compact than their mechanical equivalents. For example, a 3-phase solid-state overcurrent relay can be used in place of three single-phase mechanical overcurrent relays, yet is smaller than one of them.

The precision of electronic relays is greater than that of mechanical relays, allowing closer system coordination. In addition, because there is no mechanical motion and the electronic circuitry is very stable, they retain their calibration accuracy for a long time. Reset times can be extremely short if desired because there is no mechanical motion.

Electronic relays require less power to operate than their mechanical equivalents, producing a smaller load burden on the CTs and PTs that supply them. Because solid-state relays have a minimum of moving parts, they can be made very resistant to seismic forces and are therefore especially well suited for areas susceptible to earthquake activity.

In their early versions, some solid-state relays were sensitive to the severe electrical environment of industrial applications. They were prone to failure, especially from high transient voltages caused by lightning or utility and on-site switching. However, today’s relays have been designed to withstand these transients and other rugged application conditions, and this type of failure has essentially been eliminated. Solid-state relays have gained a strong and rapidly growing position in the marketplace as experience proves their accuracy, dependability, versatility, and reliability.

The information that follows applies to electromechanical and solid-state relays, although one functions mechanically and the other electronically. Significant differences will be pointed out.

Relay types

There are literally hundreds of different types of relays. The catalog of one manufacturer of electromechanical relays lists 264 relays for switchgear and system protection and control functions. For complex systems with many voltage levels and interconnections over great distances, such as utility transmission and distribution, relaying is an art to which some engineers devote their entire careers. For more simple industrial and commercial distribution, relay protection can be less elaborate, although proper selection and application are still very important.

The most commonly used relays and devices are listed HERE in the Table by their American National Standards Institute (ANSI) device-function number and description. These standard numbers are used in one-line and connection diagrams to designate the relays or other devices, saving space and text.

Where a relay combines two functions, the function numbers for both are shown. The most frequently used relay is the overcurrent relay, combining both instantaneous and inverse-time tripping functions. This is designated device 50/51. As another example, device 27/59 would be a combined undervoltage and overvoltage relay. The complete ANSI standard lists 99 device numbers, a few of which are reserved for future use.

Relays can be classified by their operating-time characteristics. Instantaneous relays are those with no intentional time delay. Some can operate in one-half cycle or less; others may take as long as six cycles. Relays that operate in three cycles or less are called high-speed relays.

Time-delay relays can be definite-time or inverse-time types. Definite-time relays have a preset time delay that is not dependent on the magnitude of the actuating signal (current, voltage, or whatever else is being sensed) once the pickup value is exceeded. The actual preset time delay is usually adjustable.

Inverse-time relays, such as overcurrent or differential relays, have operating times that do depend on the value of actuating signal. The time delay is long for small signals and becomes progressively shorter as the value of the signal increases. The operating time is inversely proportional to the magnitude of the event being monitored.

Overcurrent relays

Sepam protection relay

Sepam protection relay

In switchgear application, an overcurrent relay usually is used on each phase of each circuit breaker and often one additional overcurrent relay is used for ground-fault protection. Conventional practice is to use one instantaneous short-circuit element and one inverse-time overcurrent element (ANSI 50/51) for each phase.

In the standard electromechanical relay, both elements for one phase are combined in one relay case. The instantaneous element is a clapper or solenoid type and the inverse-time element is an induction-disk type.

In some solid-state relays, three instantaneous and three inverse-time elements can be combined in a single relay case smaller than that of one induction-disk relay.

Overcurrent relays respond only to current magnitude, not to direction of current flow or to voltage. Most relays are designed to operate from the output of a standard ratio-type CT, with 5A secondary current at rated primary current. A solid-state relay needs no additional power supply, obtaining the power for its electronic circuitry from the output of the CT supplying the relay.

On the instantaneous element, only the pickup point can be set, which is the value of current at which the instantaneous element will act, with no intentional time delay, to close the trip circuit of the circuit breaker. The actual time required will decrease slightly as the magnitude of the current increases, from about 0.02 sec maximum to about 0.006 sec minimum, as seen from the instantaneous curve. This time will vary with relays of different ratings or manufacturers and also will vary between electromechanical and solid-state relays.

Time delays can be selected over a wide range for almost any conceivable requirement. Time-delay selection starts with the choice of relay. There are three time classifications: standard, medium, and long time delay. Within each classification, there are three classes of inverse-time curve slopes: inverse (least steep), very inverse (steeper), and extremely inverse (steepest). The time classification and curve slopes are characteristic of the relay selected, although for some solid-state relays these may be adjustable to some degree. For each set of curves determined by the relay selection, the actual response is adjustable by means of the time dial.

On the inverse-time element, there are two settings. First the pickup point is set. This is the value of current at which the timing process begins as the disk begins to rotate on an electromechanical relay or the electronic circuit begins to time out on a solid-state relay.

Next the time-dial setting is selected. This adjusts the time-delay curve between minimum and maximum curves for the particular relay. A given relay will have only one set of curves, either inverse, very inverse, or extremely inverse, adjustable through the full time-dial range. Note that the current is given in multiples of pickup setting.

Each element, instantaneous or time delay, has a flag that indicates when that element has operated. This flag must be reset manually after relay operation.

Setting the pickup point

The standard overcurrent relay is designed to operate from a ratio-type CT with a standard 5A secondary output. The output of the standard CT is 5A at the rated nameplate primary current, and the output is proportional to the primary current over a wide range. For example, a 100/5 ratio CT would have a 5A output when the primary current (the current being sensed and measured) is 100A. This primary-to-secondary ratio of 20-to-1 is constant so that for a primary current of 10A, the secondary current would 0.5A; for 20A primary, 1.0A secondary; for 50A primary, 2.5A secondary; etc. For 1000A primary, the secondary current is 50A, and similarly for all values of current up to the maximum that the CT will handle before it saturates and becomes nonlinear.

The first step in setting the relay is selecting the CT so that the pickup can be set for the desired primary current value. The primary current rating should be such that a primary current of 110 to 125% of the expected maximum load will produce the rated 5A secondary current. The maximum available primary fault current should not produce more than 100A secondary current to avoid saturation and excess heating. It may not be possible to fulfill these requirements exactly, but they are useful guidelines. As a result, some compromise may be necessary.

On the 50/51 overcurrent relay, the time-overcurrent-element (device 51) setting is made by means of a plug or screw inserted into the proper hole in a receptacle with a number of holes marked in CT secondary amperes, by an adjustable calibrated lever or by some similar method. This selects one secondary current tap (the total number of taps depends on the relay) on the pickup coil. The primary current range of the settings is determined by the ratio of the CT selected.

For example, assume that the CT has a ratio of 50/5A. Typical taps will be 4, 5, 6, 7, 8, 10, 12, and 16A. The pickup settings would range from a primary current of 40A (the 4A tap) to 160A (the 16A tap). If a 60A pickup is desired, the 6A tap is selected. If a pickup of more than 160A or less than 40A is required, it would be necessary to select a CT with a different ratio or, in some cases, a different relay with higher or lower tap settings.

Various types of relays are available with pickup coils rated as low as 1.5A and as high as 40A. Common coil ranges are 0.5 to 2A, for low-current pickup such as ground-fault sensing; 1.5 to 6A medium range; or 4 to 16A, the range usually chosen for overcurrent protection. CTs are available having a wide range of primary ratings, with standard 5A secondaries or with other secondary ratings, tapped secondaries, or multiple secondaries.

A usable combination of CT ratio and pickup coil can be found for almost any desired primary pickup current and relay setting.

The instantaneous trip (device 50) setting is also adjustable. The setting is in pickup amperes, completely independent of the pickup setting of the inverse-time element or, on some solid-state relays, in multiples of the inverse-time pickup point. For example, one electromechanical relay is adjustable from 2 to 48A pickup; a solid-state relay is adjustable from 2 to 12 times the setting of the inverse-time pickup tap. On most electromechanical relays, the adjusting means is a tap plug similar to that for the inverse-time element. With the tap plug, it is possible to select a gross current range. An uncalibrated screw adjustment provides final pickup setting. This requires using a test set to inject calibration current into the coil if the setting is to be precise. On solid-state relays, the adjustment may be a calibrated switch that can be set with a screwdriver.

Setting the time dial

For any given tap or pickup setting, the relay has a whole family of time-current curves. The desired curve is selected by rotating a dial or moving a lever. The time dial or lever is calibrated in arbitrary numbers, between minimum and maximum values, as shown on curves published by the relay manufacturer. At a time-dial setting of zero, the relay contacts are closed. As the time dial setting is increased, the contact opening becomes greater, increasing relay operating time. Settings may be made between calibration points, if desired, and the applicable curve can be interpolated between the printed curves.

The pickup points and time-dial settings are selected so that the relay can perform its desired protective function. For an overcurrent relay, the goal is that when a fault occurs on the system, the relay nearest the fault should operate. The time settings on upstream relays should delay their operation until the proper overcurrent device has cleared the fault. A selectivity study, plotting the time-current characteristics of every device in that part of the system being examined, is required. With the wide selection of relays available and the flexibility of settings for each relay, selective coordination is possible for most systems.

Selecting and setting other than overcurrent relays are done in similar fashion. Details will vary, depending on the type of relay, its function in the system, and the relay manufacturer.

Relay operation

An electromechanical relay will pick up and start to close its contacts when the current reaches the pickup value. At the inverse-time pickup current, the operating forces are very low and timing accuracy is poor. The relay timing is accurate at about 1.5 times pickup or more, and this is where the time-current curves start. This fact must be considered when selecting and setting the relay.

When the relay contacts close, they can bounce, opening slightly and creating an arc that will burn and erode the contact surfaces. To prevent this, overcurrent relays have an integral auxiliary relay with a seal-in contact in parallel with the timing relay contacts that closes immediately when the relay contacts touch. This prevents arcing if the relay contacts bounce. This auxiliary relay also activates the mechanical flag that indicates that the relay has operated.

When the circuit breaker being controlled by the relay opens, the relay coil is deenergized by an auxiliary contact on the breaker. This protects the relay contacts, which are rated to make currents up to 30A but should not break the inductive current of the breaker tripping circuit, to prevent arcing wear. The disk is then returned to its initial position by the spring. The relay is reset. Reset time is the time required to return the contacts fully to their original position. Contacts part about 0.1 sec (six cycles) after the coil is deenergized. The total reset time varies with the relay type and the time-dial setting. For a maximum time-dial setting (contacts fully open), typical reset times might be 6 sec for an inverse-time relay and up to 60 sec for a very inverse or extremely inverse relay. At lower time-dial settings, contact opening distance is less, therefore reset time is lower.

A solid-state relay is not dependent on mechanical forces or moving contacts for its operation but performs its functions electronically. Therefore, the timing can be very accurate even for currents as low as the pickup value. There is no mechanical contact bounce or arcing, and reset times can be extremely short.

CT and PT selection
MV current transformer

MV current transformer

In selecting instrument transformers for relaying and metering, a number of factors must be considered; transformer ratio, burden, accuracy class, and ability to withstand available fault currents.

CT ratio. CT guidelines mentioned earlier are to have rated secondary output at 110 to 125% of expected load and no more than 100A secondary current at maximum primary fault current. Where more than one CT ratio may be required, CTs with tapped secondary windings or multi-winding secondaries are available.

CT burden. CT burden is the maximum secondary load permitted, expressed in voltamperes (VA) or ohms impedance, to ensure accuracy. ANSI standards list burdens of 2.5 to 45VA at 90% power factor (PF) for metering CTs, and 25 to 200VA at 50% PF for relaying CTs.

CT accuracy class. ANSI accuracy class standards are [+ or -] 0.3, 0.6, or 1.2%. Ratio errors occur because of [I.sup.2]R heating losses. Phase-angle errors occur because of magnetizing core losses.

CTs are marked with a dot or other polarity identification on primary and secondary windings so that at the instant current is entering the marked primary terminal it is leaving the marked secondary terminal. Polarity is not required for overcurrent sensing but is important for differential relaying and many other relaying functions.

PT ratio. PT ratio selection is relatively simple. The PT should have a ratio so that, at the rated primary voltage, the secondary output is 120V. At voltages more than 10% above the rated primary voltage, the PT will be subject to core saturation, producing voltage errors and excess heating.

PT burden. PTs are available for burdens from 12.5VA at 10% PF to as high as 400VA at 85% PF.

PT accuracy. Accuracy classes are ANSI standard [+ or -] 0.3, 0.6, or 1.2%. PT primary circuits, and where feasible PT secondary circuits as well, should be fused.

CTs and PTs should have adequate capacity for the burden to be served and sufficient accuracy for the functions they are to perform. However, more burden or accuracy than necessary will merely increase the cost of the metering transformers. Solid-state relays usually impose lower burdens than electromechanical relays.



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ANSI Standards For Medium Voltage protection

ANSI Functions For Protection Devices

In the design of electrical power systems, the ANSI Standard Device Numbers denote what features a protective device supports (such as a relay or circuit breaker). These types of devices protect electrical systems and components from damage when an unwanted event occurs, such as an electrical fault.

ANSI numbers are used to identify the functions of meduim voltage microprocessor devices.

ANSI facilitates the development of American National Standards (ANS) by accrediting the procedures of standards developing organizations (SDOs). These groups work cooperatively to develop voluntary national consensus standards. Accreditation by ANSI signifies that the procedures used by the standards body in connection with the development of American National Standards meet the Institute’s essential requirements for openness, balance, consensus and due process.

ANSI standards (protection) – index
Current protection functions
ANSI 50/51 – Phase overcurrentANSI 79 – Reclose the circuit breaker after tripping
ANSI 50N/51N or 50G/51G – Earth fault or sensitive earth faultDirectional current protection
ANSI 50BF – Breaker failureANSI 67 – Directional phase overcurrent
ANSI 46 -Negative sequence / unbalanceANSI 67N/67NC – Directional earth fault
ANSI 49RMS – Thermal overloadANSI 67N/67NC type 1
Directional power protection functionsANSI 67N/67NC type 2
ANSI 32P – Directional active overpowerANSI 67N/67NC type 3
ANSI 32Q/40 – Directional reactive overpowerMachine protection functions
Voltage protection functionsANSI 37 – Phase undercurrent
ANSI 27D – Positive sequence undervoltageANSI 48/51LR/14 – Locked rotor / excessive starting time
ANSI 27R – Remanent undervoltageANSI 66 – Starts per hour
ANSI 27 – Phase-to-phase undervoltageANSI 50V/51V – Voltage-restrained overcurrent
ANSI 59 – Phase-to-phase overvoltageANSI 26/63 – Thermostat, Buchholz, gas, pressure, temperature detection
ANSI 59N – Neutral voltage displacementANSI 38/49T – Temperature monitoring by RTD
ANSI 47 – Negative sequence voltageFrequency protection functions
ANSI 81H – Overfrequency
ANSI 81L – Underfrequency
ANSI 81R – Rate of change of frequency (ROCOF)

Current protection functions

ANSI 50/51 – Phase overcurrent

Three-phase protection against overloads and phase-to-phase short-circuits.
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ANSI 50N/51N or 50G/51G – Earth fault

Earth fault protection based on measured or calculated residual current values:

  • ANSI 50N/51N: residual current calculated or measured by 3 phase current sensors
  • ANSI 50G/51G: residual current measured directly by a specific sensor

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ANSI 50BF – Breaker failure

If a breaker fails to be triggered by a tripping order, as detected by the non-extinction of the fault current, this backup protection sends a tripping order to the upstream or adjacent breakers.
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ANSI 46 – Negative sequence / unbalance

Protection against phase unbalance, detected by the measurement of negative sequence current:

  • sensitive protection to detect 2-phase faults at the ends of long lines
  • protection of equipment against temperature build-up, caused by an unbalanced power supply, phase inversion or loss of phase, and against phase current unbalance

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ANSI 49RMS – Thermal overload

Protection against thermal damage caused by overloads on machines (transformers, motors or generators).
The thermal capacity used is calculated according to a mathematical model which takes into account:

  • current RMS values
  • ambient temperature
  • negative sequence current, a cause of motor rotor temperature rise

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Automation device used to limit down time after tripping due to transient or semipermanent faults on overhead lines. The recloser orders automatic reclosing of the breaking device after the time delay required to restore the insulation has elapsed. Recloser operation is easy to adapt for different operating modes by parameter setting.
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Directional current protection

ANSI 67N/67NC type 1
ANSI 67 – Directional phase overcurrent

Phase-to-phase short-circuit protection, with selective tripping according to fault current direction. It comprises a phase overcurrent function associated with direction detection, and picks up if the phase overcurrent function in the chosen direction (line or busbar) is activated for at least one of the 3 phases.
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ANSI 67N/67NC – Directional earth fault

Earth fault protection, with selective tripping according to fault current direction.
3 types of operation:

  • type 1: the protection function uses the projection of the I0 vector
  • type 2: the protection function uses the I0 vector magnitude with half-plane tripping zone
  • type 3: the protection function uses the I0 vector magnitude with angular sector tripping zone

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ANSI 67N/67NC type 1

Directional earth fault protection for impedant, isolated or compensated neutralsystems, based on the projection of measured residual current.
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ANSI 67N/67NC type 2

Directional overcurrent protection for impedance and solidly earthed systems, based on measured or calculated residual current. It comprises an earth fault function associated with direction detection, and picks up if the earth fault function in the chosen direction (line or busbar) is activated.
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ANSI 67N/67NC type 3

Directional overcurrent protection for distribution networks in which the neutral earthing system varies according to the operating mode, based on measured residual current. It comprises an earth fault function associated with direction detection (angular sector tripping zone defined by 2 adjustable angles), and picks up if the earth fault function in the chosen direction (line or busbar) is activated.
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Directional power protection functions

ANSI 32P – Directional active overpower

Two-way protection based on calculated active power, for the following applications:

  • active overpower protection to detect overloads and allow load shedding
  • reverse active power protection:
    • against generators running like motors when the generators consume active power
    • against motors running like generators when the motors supply active power

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ANSI 32Q/40 – Directional reactive overpower

Two-way protection based on calculated reactive power to detect field loss on synchronous machines:

  • reactive overpower protection for motors which consume more reactive power with field loss
  • reverse reactive overpower protection for generators which consume reactive power with field loss.

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Machine protection functions

ANSI 37 – Phase undercurrent

Protection of pumps against the consequences of a loss of priming by the detection of motor no-load operation.
It is sensitive to a minimum of current in phase 1, remains stable during breaker tripping and may be inhibited by a logic input.
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ANSI 48/51LR/14 – Locked rotor / excessive starting time

Protection of motors against overheating caused by:

  • excessive motor starting time due to overloads (e.g. conveyor) or insufficient supply voltage.
    The reacceleration of a motor that is not shut down, indicated by a logic input, may be considered as starting.
  • locked rotor due to motor load (e.g. crusher):
    • in normal operation, after a normal start
    • directly upon starting, before the detection of excessive starting time, with detection of locked rotor by a zero speed detector connected to a logic input, or by the underspeed function.

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ANSI 66 – Starts per hour

Protection against motor overheating caused by:

  • too frequent starts: motor energizing is inhibited when the maximum allowable number of starts is reached, after counting of:
    • starts per hour (or adjustable period)
    • consecutive motor hot or cold starts (reacceleration of a motor that is not shut down, indicated by a logic input, may be counted as a start)
  • starts too close together in time: motor re-energizing after a shutdown is only allowed after an adjustable waiting time.

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ANSI 50V/51V – Voltage-restrained overcurrent

Phase-to-phase short-circuit protection, for generators. The current tripping set point is voltage-adjusted in order to be sensitive to faults close to the generator which cause voltage drops and lowers the short-circuit current.
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ANSI 26/63 – Thermostat/Buchholz

Protection of transformers against temperature rise and internal faults via logic inputs linked to devices integrated in the transformer.
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ANSI 38/49T – Temperature monitoring

Protection that detects abnormal temperature build-up by measuring the temperature inside equipment fitted with sensors:

  • transformer: protection of primary and secondary windings
  • motor and generator: protection of stator windings and bearings.

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Voltage protection functions

ANSI 27D – Positive sequence undervoltage

Protection of motors against faulty operation due to insufficient or unbalanced network voltage, and detection of reverse rotation direction.
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ANSI 27R – Remanent undervoltage

Protection used to check that remanent voltage sustained by rotating machines has been cleared before allowing the busbar supplying the machines to be re-energized, to avoid electrical and mechanical transients.
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ANSI 27 – Undervoltage

Protection of motors against voltage sags or detection of abnormally low network voltage to trigger automatic load shedding or source transfer.
Works with phase-to-phase voltage.
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ANSI 59 – Overvoltage

Detection of abnormally high network voltage or checking for sufficient voltage to enable source transfer. Works with phase-to-phase or phase-to-neutral voltage, each voltage being monitored separately.
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ANSI 59N – Neutral voltage displacement

Detection of insulation faults by measuring residual voltage in isolated neutral systems.
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ANSI 47 – Negative sequence overvoltage

Protection against phase unbalance resulting from phase inversion, unbalanced supply or distant fault, detected by the measurement of negative sequence voltage.
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Frequency protection functions

ANSI 81H – Overfrequency

Detection of abnormally high frequency compared to the rated frequency, to monitor power supply quality.
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ANSI 81L – Underfrequency

Detection of abnormally low frequency compared to the rated frequency, to monitor power supply quality. The protection may be used for overall tripping or load shedding. Protection stability is ensured in the event of the loss of the main source and presence of remanent voltage by a restraint in the event of a continuous decrease of the frequency, which is activated by parameter setting.
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ANSI 81R – Rate of change of frequency

Protection function used for fast disconnection of a generator or load shedding control. Based on the calculation of the frequency variation, it is insensitive to transient voltage disturbances and therefore more stable than a phase-shift protection function.

In installations with autonomous production means connected to a utility, the “rate of change of frequency” protection function is used to detect loss of the main system in view of opening the incoming circuit breaker to:

  • protect the generators from a reconnection without checking synchronization
  • avoid supplying loads outside the installation.

Load shedding
The “rate of change of frequency” protection function is used for load shedding in combination with the underfrequency protection to:

  • either accelerate shedding in the event of a large overload
  • or inhibit shedding following a sudden drop in frequency due to a problem that should not be solved by shedding.

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Related book: Relay selection guide

Link: Register

Autor: Edvard Csanyi, CsanyiGroup


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