FUNDAMENTALS OF NON-DIRECTIONAL OVERCURRENT RELAYS (ANSI/IEEE 50/51)

 Author: BSEE Hugo E Reyes (Universidad del Zulia - Venezuela)

ABSTRACT

This paper describes the most important principles of Non-directional Overcurrent Protective Relays (50/51), this type of protective device is generally used to protect radial power lines. An Overcurrent Relay (OCR) needs current information coming from current transformers (CTs) to detect short-circuit currents (faults) or intolerable current conditions in the protected element, once the fault has been detected the overcurrent relay makes the decision of tripping (to open) the circuit breaker (52) associated in order to clear the fault.

Key words: Non-directional Overcurrent Relay, Instantaneous Overcurrent Element, Inverse Time Overcurrent Element, Definite-Time Overcurrent Element, Pickup Current, Dial Time.

INTRODUCTION

The overcurrent relay (OCR) is the most used protective device in industrial and utility distribution system, it is the simplest relay in concept to use, the OCR was developed to some extent emulate the characteristic of fuse.

The OCR must not to trip during normal conditions but must to trip when it detect short-circuits in the protected element. 

There are operating conditions related to the operation of the power system which are abnormal, but these are not faults either so the OCR must not to trip under these conditions.

Examples of abnormal conditions are: 

•           Starting currents of induction motors,
•           Inrush currents of transformers,
•         Cold load restoration (i.e. reenergizing circuits after an outage),
•          Maximum short-time overloads, and
•          Conditions of power swing.

There is an intolerable condition as a sudden unbalance current such as open phases that can damage the rotor of motors and generators, under this abnormal condition the overcurrent relay must to trip as fast as possible. Other intolerable conditions are: reversed phase rotation, abnormal frequency, overvoltage, undervoltage, etc.

THUS, THE OVERCURRENT RELAY AND IN FACT ALL TYPE OF PROTECTIVE RELAYS MUST BE ABLE TO DISCRIMINATE BETWEEN NORMAL OPERATING CONDITIONS, ABNORMAL CONDITIONS, INTOLERABLE CURRENT CONDITIONS AND SHORT-CIRCUIT FAULTS.

RELAY IEEE C37.2 DEVICE NUMBERS

The IEEE C37.2 defines the function numbers and acronyms for devices and functions that are used in electrical substations, generating stations and every power system.

Applied to protective relays some device numbers are:

21: Distance Relay

24: Volts per Hertz Relay

27: Undervoltage Relay

32: Directional Power Relay

46: Reverse-Phase or Phase Balance Current Relay

50: Instantaneous Overcurrent Relays

51: AC Inverse Time Overcurrent Relay

52: AC Circuit Breaker

59: Overvoltage Relay

67: AC Directional Overcurrent Relay

86: lockout Relay

87: Differential Protective Relay

OVERCURRENT PROTECTION SCHEME

A typical non-directional overcurrent protection scheme is shown in figure 1.

Fig. 1 Typical Non-directional OCR Protection Scheme.

This protection scheme consists of a set of current transformers (CTs), an overcurrent relay and its associated circuit breaker and DC power supply (commonly 125 VDC). Overcurrent relays receive a current magnitude from CTs and when that current is above a predefined threshold they issue a trip signal to open an associated circuit breaker

In the figure 2 is shown a typical DC tripping circuit.

Fig. 2 Simplified DC Tripping Scheme of an OCR.

The contacts are shown in their de-energized position. The normally open (NO) 52a circuit breaker (CB) contact is closed when the CB is closed. Relay operation for a fault implies a closing of any Normally Open (NO) relay contacts (51-1/2/3/N). This operation stablishes a current through CB Trip Coil (52-TC) disconnecting the protected element. When the CB trips, the 52a contact open to interrupt the tripping current.

We can see in the figure 2 that each overcurrent phase element (51-1/51-2/51-3) measures only one phase current and also we have a residual overcurrent element (51-N), this residual connection allow the neutral element to measure the sum of the phase currents, which is equivalent to the residual current 3.I₀ (where I₀ is the zero sequence current), so this scheme need four electromechanical relays. Nowadays, numerical relays allow the implementation of this scheme in one relay.

SYSTEM PROTECTION OBJECTIVES

Protection systems should have several protection objectives or properties, the most important objectives are:

•           Sensitivity
•           Selectivity
•          Speed of operation
•           Reliability and Dependability
•         Security
•           Simplicity
•           Economy

Sensitivity: is the ability of the protective system to detect and operate under the presence of the smallest faults within the protected elements.

Selectivity:  is also known as relay coordination or protection coordination, is the ability of the protective system to clear a fault as fast as possible within the protected element by tripping only those circuit breakers whose operation is required in order to isolate the fault. Protection coordination means that primary protection eliminates faults as fast as possible while the backup protection operates only if primary protection fails.

Fig. 3 Example of Selectivity

Speed of operation: is the ability of the protective system to operate in a short time after any fault inception. Relaying system operation time includes relay and circuit breaker operation time. Typically, the operation time is given in cycles according to the power system frequency (50 or 60 Hertz).

Example: one (1) cycle is equal to 16.67 milliseconds (ms) at 60 Hz and 20 ms at 50 Hz. An instantaneous relay (ANSI 50) is a relay with no intentional time delay while a high speed relay operates is less than 3 cycles (50 ms) at 60 Hz. Nowadays, the instantaneous element of the numerical relays can operates in about 1 cycle. On the other hand, typical circuit breaker operation time are from 2 cycles to 8 cycles.

Example: if an instantaneous relay operates a 1 cycle (16.67 ms) and its associated circuit breaker at 3 cycles (50 ms) the fault clearing time would be 4 cycles (66.67 ms).

Reliability: is a measure of the degree of certainty that a relay system will perform correctly. A reliable relay system is one that trips when required (dependability) but does not trip when no required. Reliability is dependent on incorrect design/settings, incorrect installation/testing and deterioration in service. However, it is found that simple relay systems are more reliable. System which depend on local information tend to be more reliable and dependable than those than depend upon the information at the remote end.

Dependability: is the certainty of correct operation in response to system troubles. Dependability includes the reliable operation of the relay system operating when it is supposed to and selectively of the relay system operating to isolate the minimum amount of the system necessary to provide continuity of service.

Security: is the ability to avoid misoperations between faults. Every relay system has to be designed to either operate or not operate selectively with other systems.

Simplicity: is very important to keep a relay system as simple as possible. Therefore, it is important to make sure that the protection system is only as complex as required to meet the power system protection requirements.

Economy:  a low-cost relaying system is not necessarily the most economical solution, is important to define the level of protection versus the protection cost according to the economic loss that the protection system may prevent.

ZONES OF PROTECTION

Various zones of protection are shown in Figure 4. It can be seen that the adjacent zone overlap. The protection in each zone should overlap that in the adjacent zone. The location of the current transformers (CTs) supplying the relay system defines the edge of the protective zone.

                Fig. 4 Typical System and Its Zones of Protection.

The power system is divided into protective zones for:

•           Generators
•           Transformers
•           Buses
•           Transmission y sub-transmission power lines
•        Motors

Protection zones are classified as primary and/or backup. The primary protective relays are the first line of defense against system faults and operate first to isolate the fault. Typically, primary protection operation should be as fast as possible, preferably instantaneous (1 cycle to 3 cycles), if the fault is not isolated after some time delay, backup protection clears the faulted equipment by re-tripping the primary circuit breakers or by tripping circuit breakers in adjacent zones. When adjacent zones are tripped by backup protection, more of the power system is removed from service. The Backup protection should also preferably be located at a place different from where the primary protection is located.

NON-DIRECTIONAL OVERCURRENT RELAY BASIS

A non-directional overcurrent relay (OCR) has a single input in the form of AC current coming from a CT’s set. The output of the OCR is a normally open (NO) contact, which changes over to closed state when the relay trips due to a short-circuit fault. In Figure 5 is shown a block diagram of a simple OCR.

                                        Fig. 5 Typical Block Diagram of an Overcurrent Relay

As we can see in Figure 5, the non-directional overcurrent relay has two setting:

•           Time Dial Setting (TD)
•           Pickup Setting (TAP or 51P1P)

The Time Dial setting (TD) decides the operating times of the overcurrent relay while the Pickup Current ( TAP or 51P1P) decides the current required for the relay to pick-up (and trip).

The name “TAP” comes from the electromechanical overcurrent relays. In these relays we have to insert a Tap Screw in a Tap Block Bridge (see Figure 6), also the Main Coil of the OCR has Taps that allow adjusting of the Numbers of Turns. We can adjust the Pickup Current (51P1P) electrically by changing Coil Taps. The same terminology continues to be used in the modern relays.

                        Fig. 6 Operating Coil of an Electromechanical Relay.

The multiple of pick-up or multiplier (M) is defined as follows:

M = I_secondary/I_pickup                                                                                    (Eq. 1)

M =  (I_primary/CTR) / I_pickup

Where:

CTR: is the CT Ratio

The value of Multiple of Pickup (M) tells us about the severity of the current as seen by the relay. If M < 1 means that normal current is flowing. At M > 1, the relay is supposed to Pick Up (Trip). Higher values of M indicate how serious the short-circuit fault is.

Example:

Let us consider a primary fault of 2.5 kA, a CTR equal to 40 (200/5 A), and a relay pickup current of 3.5 A (Tap), then the multiple of pickup would be:

M = (2 500/40)/ 3.5 = 17.85

When a fault clears and the relay current drops below the pickup current then the overcurrent relay resets to a normal state. The time for the relay to completely reset is called Reset Time.

Most of the electromechanical overcurrent relays will not start to reset until the current drops below about 60% of the pickup current but in digital overcurrent relays is typically 95%.

OPERATING TIME CHARACTERISTIC OF OVERCURRENT RELAYS

According to operating time characteristic the OCRs are classified into:

•          INSTANTANEOUS OVERCURRENT RELAYS ( 50)
•     TIME-DELAYED OVERCURRENT RELAYS (51) (Define Time and Inverse Time)

       INSTANTANEOUS OVERCURRENT RELAYS (50)

These relay have no intentional time delay, the terms instantaneous and high-speed are frequently used interchangeable. The operating time of an instantaneous relay is of the order of one cycle or less. Such a relay has only the pickup current setting and does not have time setting. These relays are typically used in high-set primary overcurrent protection schemes.

                Fig. 7 Instantaneous Time-Current Curve

TIME-DELAYED OVERCURRENT RELAYS (51)

These relays are classified into:

-          DEFINITE TIME OVERCURRENT RELAY

-          INVERSE TIME OVERCURRENT RELAY

 

DEFINITE TIME OVERCURRENT RELAY

These relays can be adjusted to trip at a definite amount of time, after it pickups. Thus, it has a time-setting adjustment and also a pickup current adjustment. These relays are typically used for short power lines application and when coordination is not a problem.

Fig. 8 Definite Time Current Curve

INVERSE TIME OVERCURRENT RELAY (51)

The characteristic is inverse in the initial part, which tends to a definite minimum operating time as the current becomes very high. The reason for the operating time becoming definite minimum at high values of current, is that in the electromechanical relays the magnetic flux saturates at high values of current and the relay operating torque, which is proportional to the square of the flux, does not increase substantially after the saturation sets in. The resulting time-current characteristic is inverse: the operating time diminishes when current increases. Inverse Time Overcurrent Relays have a Pickup Current Setting  and a Time Dial Setting (TD).

Time-current characteristics of inverse time overcurrent relays are usually divided into families. Thus, each family contains a number of curves with a certain degree of inverseness. Per each curve of family, there are different pickup currents and curves to satisfy a variety of coordination requirements.

Inverse Time Overcurrent Characteristic are divided in:

•           DEFINITE TIME (DT CO-6)
•           MODERATELY INVERSE (MI CO-7)
•           INVERSE (I CO-8)
•           VERY INVERSE (VI CO-9)
•           EXTREMELY INVERSE (EI CO-11)

These time-current characteristics are shown in Figure 9.

Fig. 9 Time-Current Curve Shape Comparison 

Note: these curves belong to a conventional Westinghouse type CO relays (electromechanical).

These time-current characteristic in Figure 9 are selected so that all relays operate in 0.2 seconds at 20 times the Tap setting (M).

There is no a unique way of selecting the ideal curve shape for a specific application, except to make preliminary setting calculations. However, some general comments can be made:

- Use a comparable shape within a system segment for easier coordination.

- Use a Define Time element (CO-6) when coordination is not a problem and for short line application.

- Use an Extremely Inverse Time element (CO-11) when fuses are involved.

- The Inverse Time Element (CO-8) provides faster clearing time than the Very Inverse Time Element (CO-9) for low current faults, so is suitable in long lines where the available fault current is much less at the end of the line than at the local end. It does not provide much margin for cold load pickup.

Also, the flatter curves DT (CO-6) and VI (CO-7) are suitable when:

-          There are no coordination requirements with other types of protection devices farther out in the system.

-          The variation in current for faults at the near and far ends of the protected circuit is too small.

-          Instantaneous trip units give good coverage.

The Figure 10 shows a families of curves for a Moderately Inverse (MI CO-7) Relay. The number on the curves are the corresponding Time Dial Setting (TD) values. By increasing the time dial setting (TD) the relay increase the operating time.

Fig. 10 Typical Time Curves of The Type CO-7 Relay (51).

These Time current curves are plotted in terms of the multiple of pickup (M) and Time Dial Setting (TD). For M equal or greater than 1 the elements picks up, and for M< 1 it resets.

INVERSE TIME CHARACTERISTIC EQUATIONS FOR OVERCURRENT RELAYS (51)

The US STD IEEE C37.112 provides equations that define Time-Current Characteristics for both the Operating Time (To) and the Reset Time (Tr) of Inverse Time Overcurrent Elements.

The Operating Time Equation defines a family of Time-Current Curves, with each curve determined by the TD Setting.

To = TD .{  A / (M^p -1)+B}     , M ≥ 1                                                                                  (Eq. 2)

Where:

To: is the operating time in seconds (s).

TD: is the time dial.

M: is the Multiple of Tap (M = (I_primary/CTR) / I_pickup)

Constants A, B and P: they define different families of time-current characteristics.

In Table 1 are shown the constants values according to the IEEE curve shapes.

IEEE CURVE SHAPE	A	B	P
Extremely Inverse	28.20	0.1217	2.00
Very Inverse	19.61	0.4910	2.00
Moderately Inverse	0.0515	0.1140	0.02
US Inverse	5.95	0.1800	2.00

Table 1 Constants for IEEE Standard Characteristics in Equation 2

The Reset Time (Tr) in Equation 3 describes a family of reset time characteristics. The time dial setting (TD) determines the curve, and constant C is the reset time (Tr) for M = 0 and TD = 1.

Tr =TD. { C/(1-M^2 )}        , M < 1                                                                                   (Eq. 3)

On the other hand, for European applications the Std IEC 60255-151 provides an equation (Eq. 4) for the operating time of Inverse-Time Overcurrent Element, the equation does not include parameter B, which provides definite time behavior to the curve for large currents.

 To=TD.(  A/(M^p-1))         , M ≥ 1                                                                                     (Eq. 4)                

 In Table 2 are shown the constants values according to the IEC curve shapes.

IEC CURVE SHAPE	A	P
Extremely Inverse	80.00	2.00
Very Inverse	13.50	1.00
Standard Inverse	0.14	0.02
Long Time Inverse	120.00	1.00

Table 2 Constants for IEC Standard Characteristics in Equation 4
 

 SELECTING PICKUP CURRENT OF INVERSE TIME OVERCURRENT RELAYS (51)

The overcurrent relay (OCR) should allow normal load and also a certain degree of overload to be supplied. Also, is important to determine the maximum possible load or Short Time Maximum Load (STML) for each circuit, this STML is the reference value that should be used for setting the pickup current. At the same time the OCR should be sensitive enough to respond to the smallest fault.

The pickup value (Tap) of the Phase OCR should be at least 2 times the normal maximum load and never less than 1.5 times. If the STML is greater than the normal maximum load, then the Tap can be selected greater than 1.25 the STML.

The Figure 11 shows a single line diagram (SLD) of a radial system, there is an overcurrent device 2 (OCR-2) providing primary protection to the power line, between Bus 1 and Bus 2, and also a backup protection to an overcurrent device 1 (OCR-1). The OCR-2 must detects short-circuit faults beyond the downstream OCR-1, the backup protection is executed if the OCR-1 fails to operate in its primary zone. Hence, the goal is to select the pickup current of the OCR-2.

                    Fig. 11 Single Line Diagram (SLD) of a Radial Power System.

The pickup current for a phase overcurrent relay OCR-2 must to be set at a value greater than the maximum load current (I_ML) and lower than the minimum fault current in its circuit (I_FMIN), so:

I_{ML <} I_{PICKUP-51P1P-2} < I_FMIN-2

Where,

I_FMIN-2 = I_FMAX-1

Usually, the Pickup Current Element (51P1P) can be selected as:

I_{PICKUP-51P1P-2} = 125% _* I_ML

Note:

For default, some overcurrent relays have an increased pickup current value. For example: 1.1 times greater than the pickup current.

On the other hand, knowing the Relay’s Time Dial, the Inverse Time Curve, and also the maximum short-circuit current available we can calculate the operating time (To) by using the specific equation.

SELECTING PICKUP CURRENT OF INSTANTANEOUS OVERCURRENT RELAYS (50)

The Figure 12 shows a single line diagram (SLD) of a radial system, there is an overcurrent device 2 (OCR-2) providing primary protection to the power line between Bus 1 and Bus 2, and also a backup protection to an overcurrent device 1 (OCR-1).

Figure 12 SLD and Coordination Curves of OCR-1 and OCR-2.

When inverse time overcurrent relays are being used and In order to make a correct coordination between relays OCR-1 and OCR-2 shown in Figure 12, it is important to consider that the OCR-2 element must have enough time delay to serve as the backup protection of the downstream device OCR-1. Also, this time delay would be present for faults between both overcurrent relays, where the device OCR-2 is the primary protection in its zone. It can be seen from Figure 12 that as the fault location moves toward the source, the fault currents become larger. 

Thus, the instantaneous current pickup of the OCR-2 (I_PK-2) have to be greater than the maximum current fault at the next downstream device zone (OCR-1). Typically, an instantaneous pickup current setting for the backup protection device OCR-2, is 125% the maximum current fault (I_{F1_MAX}) of the next downstream overcurrent relay (OCR-1).

Then, the instantaneous pickup current for relay 2 is:

I_PK-50P1P-2 = 1.25 * I_{F1_MAX}

DIGITAL OVERCURRENT RELAYS

Digital overcurrent relays are microprocessor-based relays, they have the same settings as electromechanical relays, but digital relays can do a lot of things that traditional relays cannot do, such as:

a) Allow selection of different standard inverse-time curves;

b)  Includes instantaneous, definite-time, and inverse-time overcurrent elements in a single relay;

c) Includes phase, negative-sequence, and zero-sequence overcurrent elements in a single device;

d) Beside of protection functions they also provides metering, logic control and monitoring functions.

e) IEC 61850 communications.

COORDINATION OF INVERSE TIME OVERCURRENT RELAYS (51)

The Figure 13 shows a single radial system with two overcurrent relays (51) that we called OCR-1 and OCR-2. The Figure 13 as well shows the relationship between the operating time curve of the primary relay (OCR-1), and that of the backup relay (OCR-2).  

In order to ensure selectivity the primary relay curve (OCR-1) is located to the left and below of the backup relay curve (OCR-2) with enough time margin that is essential for maintaining selectively between both relays. Hence this time margin is referred to as the coordinating time interval (CTI).  

    

Figure 13 Coordination Process of Two Pair of OCR (51)

According with Time-Current Curve in Figure 13, we have:

T2 = T1 + CTI

The CTI must considerer the circuit breaker (CB) time operation, the primary time over-travel time (just for electromechanical relays), relay tolerances and a safety factor.

Typical CTI that are commonly used are:

• For Relay to Relay application should be in the range of 0.20 to 0.50 seconds.
•  For electromechanical relays, the minimum time margin for a 5 cycle (0.083s) circuit breaker is typically 0.30 seconds.
•  For digital relays the CTI margin for a 5 cycle circuit breaker is typically 0.25 seconds.
•  Electromechanical relay and fuse coordination requires a minimum time margin of 0.22 seconds between curves.
•  Fuse and fuse coordination requires that the total clearing time of the downline fuse curve be less than 75% of the minimum melt time of the up-line fuse curve.
•   Fuse and relay coordination requires a minimum time margin of 0.30 seconds between curves.

The coordination process has to be started from the relay which is at the tail end of the radial system (OCR-1),  this is because this relay is not constrained by selectivity problems. These coordination criterion is applied for all short-circuit faults at the zone of relay OCR-1

Furthermore, the operating time of an overcurrent relay must be faster than the equipment damage time (example: damage curve of a power transformer: I².t curve) and slower than any normal transient behavior than may occur on the system (starting currents of induction motors, Inrush currents of transformers, Cold load restorations, etc.).

When the primary and backup relays has the same type of inverse-time curves, the minimum separation between them occurs at the maximum short circuit fault. On the other hand, if the curves are of different types, the minimum separation between curves may occurs at any short circuit current value. Then we need to check coordination for every fault current interval.

SUMMARY

-          The Non-directional Overcurrent Relay (50/51) is the most simple, cheap, and used protective device in radial systems, it was developed to some extent emulate the characteristic of fuses.

-          An Overcurrent relay and in fact all kind of protective relay must be able to discriminate between normal operating conditions, abnormal conditions, intolerable current conditions and short-circuit faults.

-          Power systems protection must consider primary and backup protection.

-          Non-directional overcurrent relays has two setting:

o   Time Dial Setting (TD):

o   Pickup Setting (TAP or 51P1P)

The Time Dial setting (TD) decides the operating times of the overcurrent relay while the Pickup Current ( TAP or 51P1P) decides the current required for the relay to pick-up (trip). 

The multiple of pickup (M) is also called Multiple of Tap. The name “Tap” comes from the electromechanical overcurrent relays.

The value of Multiple of Pickup (M) tells us about the severity of the current as seen by the relay. If M < 1 means that normal current is flowing. At M > 1, the relay is supposed to Pick Up (Trip). Higher values of M indicate how serious the short-circuit fault is.

-          According to operating time characteristic the OCRs are classified into:

o   INSTANTANEOUS OVERCURRENT RELAYS ( 50)

o TIME-DELAYED OVERCURRENT RELAYS (51) (Define Time and Inverse Time OCRs)

 

-          Inverse Time Overcurrent Characteristic are divided in:

o   DEFINITE TIME (DT CO-6)

o   MODERATELY INVERSE (MI CO-7)

o   INVERSE (I CO-8)

o   VERY INVERSE (VI CO-9)

o   EXTREMELY INVERSE (EI CO-11)

 

-          There is no a unique way of selecting the ideal curve shape for a specific application. However, some general comments can be made:

o    Use a comparable shape within a system segment for easier coordination.

o   Use a Define Time element (CO-6) when coordination is not a problem and for short line application.

o    Use an Extremely Inverse Time element (CO-11) when fuses are involved.

o   The Inverse Time Element (CO-8) provides faster clearing time than the Very Inverse Time Element (CO-9) for low current faults, so is suitable in long lines where the available fault current is much less at the end of the line than at the local end. It does not provide much margin for cold load pickup.

 

-          The pickup current for an overcurrent relay must to be set at a value greater than the maximum load current (I_ML) and lower than the minimum fault current in its circuit (I_FMIN), so:

I_{ML <} I_PICKUP < I_FMIN

-          The instantaneous current pickup of a backup overcurrent relay (I_PK-2) has to be greater than the maximum current fault at the next downstream overcurrent relay. Typically, an instantaneous pickup current setting for the backup protection device, is 125% the maximum current fault (I_{F1_MAX}) of the next downstream overcurrent relay.

o   Then, the instantaneous pickup current setting are:

 I_PK-1 = I_{F1_MAX}

 I_PK-2 = 1.25 * I_PK-1

-          The coordination of a pair inverse time overcurrent relays has to be started from the relay which is at the tail end of the radial system, this is because this relay is not constrained by selectivity problems.

 

REFERENCES

1.      -  IEEE STD C37.2-2008. IEEE STANDARD FOR ELECTRICAL POWER SYSTEM DEVICE FUNCTION NUMBERS, ACRONYMS, AND CONTACT DESIGNATIONS.

2.       FUNDAMENTALS OF POWER SYSTEM PROTECTION – SECOND EDITION, Y.G. PAITHANKAR, S.R. BHIDE

3.       PROTECTIVE RELAYING PRINCIPLES AND APPLICATIONS - THIRD EDITION. J. LEWIS BLACKBURN, THOMAS J. DOMIN.

4.       PROTECTIVE RELAYING THEORY AND APPLICATIONS – SECOND EDITION. WALTER A. ELMORE