Protective Device NumbersProtective relays are commonly referred to by standard device numbers. For example, a time overcurrent

relay is designated a 51 device, while an instantaneous overcurrent is a 50 device. Multifunction relays

have combinations of device numbers. A 27/59 device, for example, is a combination under/over voltage

relay. Letters can be added to clarify application (87T for transformer differential, 59G for ground

overvoltage).

1 – Master Element

2 – Time Delay Starting or Closing Relay

3 – Checking or Interlocking Relay

4 – Master Contactor

5 – Stopping Device

6 – Starting Circuit Breaker

7 – Rate of Change Relay

8 – Control Power Disconnecting Device

9 – Reversing Device

10 – Unit Sequence Switch

11 – Multi-function Device

12 – Overspeed Device

13 – Synchronous-speed Device

14 – Underspeed Device

15 – Speed – or Frequency, Matching Device

16 – Data Communications Device

17 – Shunting or Discharge Switch

18 – Accelerating or Decelerating Device

19 – Starting to Running Transition Contactor

20 – Electrically Operated Valve

21 – Distance Relay

22 – Equalizer Circuit Breaker

23 – Temperature Control Device

24 – Volts Per Hertz Relay

25 – Synchronizing or Synchronism-Check Device

26 – Apparatus Thermal Device

27 – Undervoltage Relay

28 – Flame detector

29 – Isolating Contactor or Switch

30 – Annunciator Relay

31 – Separate Excitation Device

32 – Directional Power Relay

33 – Position Switch

34 – Master Sequence Device

35 – Brush-Operating or Slip-Ring Short-Circuiting Device

36 – Polarity or Polarizing Voltage Devices

37 – Undercurrent or Underpower Relay

38 – Bearing Protective Device

39 – Mechanical Condition Monitor

40 – Field (over/under excitation) Relay

41 – Field Circuit Breaker

42 – Running Circuit Breaker

43 – Manual Transfer or Selector Device

44 – Unit Sequence Starting Relay

45 – Abnormal Atmospheric Condition Monitor

46 – Reverse-phase or Phase-Balance Current Relay

47 – Phase-Sequence or Phase-Balance Voltage Relay

48 – Incomplete Sequence Relay

49 – Machine or Transformer, Thermal Relay

50 – Instantaneous Overcurrent Relay

51 – AC Inverse Time Overcurrent Relay

52 – AC Circuit Breaker

53 – Exciter or DC Generator Relay

54 – Turning Gear Engaging Device

55 – Power Factor Relay

56 – Field Application Relay

57 – Short-Circuiting or Grounding Device

58 – Rectification Failure Relay

59 – Overvoltage Relay

60 – Voltage or Current Balance Relay

61 – Density Switch or Sensor

62 – Time-Delay Stopping or Opening Relay

63 – Pressure Switch

64 – Ground Detector Relay

65 – Governor

66 – Notching or Jogging Device

67 – AC Directional Overcurrent Relay

68 – Blocking or "Out-of-Step" Relay

69 – Permissive Control Device

70 – Rheostat

71 – Liquid Level Switch

72 – DC Circuit Breaker

73 – Load-Resistor Contactor

74 – Alarm Relay

75 – Position Changing Mechanism

76 – DC Overcurrent Relay

77 – Telemetering Device

78 – Phase-Angle Measuring Relay

79 – AC Reclosing Relay

80 – Flow Switch

81 – Frequency Relay

82 – DC Reclosing Relay

83 – Automatic Selective Control or Transfer Relay

84 – Operating Mechanism

85 – Communications,Carrier or Pilot-Wire Relay

86 – Lockout Relay

87 – Differential Protective Relay

88 – Auxiliary Motor or Motor Generator

89 – Line Switch

90 – Regulating Device

91 – Voltage Directional Relay

92 – Voltage and Power Directional Relay

93 – Field Changing Contactor

94 – Tripping or Trip-Free Relay

95 to 99 – For specific applications where other numbers are not suitable

* for a full definition of each function, please refer to the ANSI/IEEE C37.2 standard

Prefixes and SuffixesLetters and numbers may be used as prefixes or suffixes to device function numbers to provide a more

specific definition of the function. Prefixes and suffixes should, however, be used only when they

accomplish a useful purpose.

Auxiliary devices

C - Closing relay/contactor

CL - Auxiliary relay, closed

CS - Control switch

D - "Down" position switch relay

L- Lowering relay

O - Opening relay/contactor 

OP - Auxiliary relay, open

PB - Push button 

R  - Raising relay 

U - "UP" position switch relay 

X  - Auxiliary relay 

Y - Auxiliary relay 

Main device

A - Alarm/auxiliary power 

AC - Alternating current 

AN - Anode 

B - Battery, blower, bus 

BK - Brake 

BL - Block (valve) 

BP - Bypass 

BT - Bus tie

C - Capacitor, condenser,

compensator, carrier current, case,

compressor 

CA - Cathode 

Z - Auxiliary relay

 

Actuating quantities

A -Air/amperes/alternating

C - Current

D - Direct/discharge

E - Electrolyte

F - Frequency/flow/fault

GP - Gas pressure

H - Explosive/harmonics

I0 - Zero sequence current

I-, I2 - Negative sequence current

I+, I1 - Positive sequence current

J - Differential

L - Level/liquid

P - Power/pressure

PF - Power factor

Q - Oil

S - Speed/suction/smoke

T - Temperature

V - Voltage/volts/vacuum

VAR -Reactive power

VB - Vibration

W - ater/watts

 

Other suffix letters

A - Accelerating, automatic

B - Blocking, backup

BF - Breaker failure

C - Close, cold

D - Decelerating, detonate, down,

disengaged

E - Emergency, engaged

F - Failure, forward

GP - General purpose

H - Hot, high

HIZ - High impedance fault

HR - Hand reset

HS  - High speed

CH - Check (valve) 

D - Discharge (valve) 

DC - Direct current 

E - Exciter 

F - Feeder, field, filament, filter, fan

G - Generator/ground

H - Heater/housing

L - Line, logic

M - Motor, metering

MOC - Mechanism operated contact

N - Network, neutral

P - Pump, phase comparison

R - Reactor, rectifier, room

S - Synchronizing, secondary,

strainer, sump ,suction (valve)

T -Transformer, thyratron

TH - Transformer (high-voltage side)

TL - Transformer (low-voltage side)

TM - Telemeter

TOC - Truck-operated contacts

TT - Transformer (tertiary-voltage

side)

U - Unit

 

Main device parts

BK - Brake

C - Coil, condenser, capacitor

CC - Closing coil, closing contactor

HC - Holding coil

M - Operating motor

MF - Fly-ball motor

ML - Load-limit motor

MS - Speed adjusting or synchronizing

motor

OC - Opening contactor

S - Solenoid

SI - Seal-in

T - Target

TC  Trip coil

V - Valve

L - Left, local, low, lower, leading

M - Manual

O - Open, over

OFF - Off

ON - On

P - Polarizing

R - Right, raise, reclosing, receiving,

remote, reverse

S - Sending, swing

SHS - Semi-high speed

T - Test, trip, trailing

TDC - Time-delay closing contact

TDDO - Time delayed relay coil drop-out

TDO - Time-delay opening contact

TDPU  - Time delayed relay coil pickup

THD  - Total harmonic distortion

U - Up, under

 

Reference positions of devices

Adjusting means - Low or down

position

Clutch  - Disengaged position

Contactor  - De-energized position

Contactor (latched-in type) - Main

contacts open

Density switch  - Standard reference

Disconnecting switch  - Main contacts

open

Flow detector  - Lowest flow

Gate  - Closed position

Level detector  - Lowest level

Load-break switch  - Main contacts

open

Power circuit breaker - Main contacts

open

Power electrodes - Maximum gap

position

Pressure switch - Lowest pressure

Reclosure - Main contactor open

Relay  - De-energized position

Relay (latched-in type)

Rheostat  - Maximum resistance

position

Speed switch - Lowest speed

Tap changer  - Center tap

Temperature relay - Lowest

temperature

Turning gear - Disengaged position

Vacuum switch - Lowest pressure that

is highest vacuum

Valve  - Closed position

Vibration detector - Minimum

vibration

ANSI IEC ComparisonANSI IEC 60617 Description

21FL FLOC Fault locator

21G Z< Underimpedance

24 U/f> Overexcitation

25 SYNC Synchronisation check

27 U< Undervoltage

32 P→ Directional power relay 

   32P, P→, - active power 

   32Q, Q→ - reactive powerpower

37 I< Non-directional undercurrent

40 X< Underexcitation

46 I2> Negative-phase sequence

47 U2> Phase-sequence voltage protection

48, 14, 66 Is²t,n< Start-up supervision for motors

49F Ith> Thermal protection for cables

49M/49G/49T Three-phase thermal protection for machines 

   M - motor, G - generators, T - transformer

50N/51N I0> Non-directional earth-fault

51 I> Non-directional overcurrent 

   51C, I> - shunt capacitors 

   51V, I(U)> - voltage dependant

59 U> Overvoltage 

   59N, U0> - residual overvoltage

67 I>→ Directional overcurrent 

   67N, I0>→ - directional earth-fault

68 I2> Transformer/motor inrush current

79 0→1 Auto-reclosure

81 f Frequency relay 

   81N, f< - underfrquency 

   81O, f> - overfrequency

87 ΔI> Differential protection 

   87G, ΔI> - generator 

   87M, ΔI> - motor 

   87T, ΔI> - transformer 

   87N, ΔI0> - restricted earth fault

Notes:  

      1. for high set and instantaneous tripping, '>' can be replaced with '>>' or '>>'  

    2. '3' can be placed before designations to indicate three phase, i.e. 3I<- See more at: http://myelectrical.com/notes/entryid/148/ansi-ieee-protective-device-numbering#sthash.pqTpwukA.dpuf

Posted by ecsanyi on Wednesday, April 14, 2010 at 10:23 pm | Technical Articles | Categories | Submit Article

ANSI/IEC Relay Symbols55,700 views

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.

Posted by ecsanyi on Monday, September 14, 2009 at 11:29 pm | Technical Articles | Categories | Submit Article

Protection relays – important informations14,574 views

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

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

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

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

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.

Izvor: www.ecmweb.com

Posted by ecsanyi on Sunday, September 13, 2009 at 4:13 pm | Technical Articles | Categories | Submit Article

ANSI standards for protection devices51,424 views

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 Recloser

ANSI 50/51 – Phase overcurrent ANSI 79 – Reclose the circuit breaker after tripping

ANSI 50N/51N or 50G/51G – Earth fault or sensitive earth fault

Directional current protection

ANSI 50BF – Breaker failure ANSI 67 – Directional phase overcurrent

ANSI 46 -Negative sequence / unbalance ANSI 67N/67NC – Directional earth fault

ANSI 49RMS – Thermal overload ANSI 67N/67NC type 1

Directional power protection functions ANSI 67N/67NC type 2

ANSI 32P – Directional active overpower ANSI 67N/67NC type 3

ANSI 32Q/40 – Directional reactive overpower

Machine protection functions

Voltage protection functions ANSI 37 – Phase undercurrent

ANSI 27D – Positive sequence undervoltage ANSI 48/51LR/14 – Locked rotor / excessive

starting time

ANSI 27R – Remanent undervoltage ANSI 66 – Starts per hour

ANSI 27 – Phase-to-phase undervoltage ANSI 50V/51V – Voltage-restrained overcurrent

ANSI 59 – Phase-to-phase overvoltageANSI 26/63 – Thermostat, Buchholz, gas, pressure,

temperature detection

ANSI 59N – Neutral voltage displacement ANSI 38/49T – Temperature monitoring by RTD

ANSI 47 – Negative sequence voltage Frequency 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.

ANSI index ↑

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

ANSI index ↑

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.

ANSI index ↑

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

ANSI index ↑

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

ANSI index ↑

Recloser

ANSI 79

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.

ANSI index ↑

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.

ANSI index ↑

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

ANSI index ↑

ANSI 67N/67NC type 1

Directional earth fault protection for impedant, isolated or compensated neutralsystems, based on the projection of

measured residual current.

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

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

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

ANSI 26/63 – Thermostat/Buchholz

Protection of transformers against temperature rise and internal faults via logic inputs linked to devices integrated in

the transformer.

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

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.

ANSI index ↑

ANSI 59N – Neutral voltage displacement

Detection of insulation faults by measuring residual voltage in isolated neutral systems.

ANSI index ↑

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.

ANSI index ↑

Frequency protection functions

ANSI 81H – Overfrequency

Detection of abnormally high frequency compared to the rated frequency, to monitor power supply quality.

ANSI index ↑

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.

ANSI index ↑

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.

Disconnection

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.