Protective Relays

Protective relays are critical components in electrical power systems, designed to detect and respond to abnormal conditions such as faults and overloads. These devices are essential for ensuring the safety and reliability of electrical networks by isolating faulty sections, thereby preventing damage to equipment and maintaining system stability.

Low voltage Transformer
Electromechanical Relay
Low voltage Transformer
Digital Relay
Protective Relays
Types of Protective Relays

Protective relays can be categorized based on their function, operating principles, and applications. Here are some of the most common types:

Overcurrent Relays:
These relays detect when the current exceeds a predefined level and are commonly used in low and medium-voltage applications. They are essential for protecting circuits from short circuits and overload conditions.

Differential Relays:
These relays compare the current entering and leaving a protected zone. If the difference between these currents exceeds a threshold, the relay operates, indicating a fault within the zone, such as a short circuit in transformers or generators.

Distance Relays:
Used primarily in transmission line protection, distance relays measure the impedance of the line. A significant drop in impedance indicates a fault, prompting the relay to isolate the affected section.

Directional Relays:
These relays determine the direction of fault currents. They are crucial in complex systems where power can flow in multiple directions, ensuring that only the faulty section is isolated.

Ground Fault Relays:
Ground fault relays detect faults where current leaks to the ground, which can be dangerous and damaging to equipment. These are especially important in systems with solid or low resistance grounding.

Motor Protection Relays:
These are specialized relays designed to protect electric motors from conditions such as overload, phase imbalance, and undercurrent, ensuring the longevity and safety of motor-driven systems.

Protective Relay Applications

Protective relays are used across various segments of the electrical power system, including:

Generation:
Protecting generators from faults and abnormal operating conditions to ensure continuous and safe power generation.

Transmission:
Ensuring the stability of high-voltage transmission lines by isolating faults quickly to prevent cascading failures.

Distribution:
Safeguarding transformers, feeders, and other components in the distribution network to maintain reliable power supply to consumers.

Industrial Systems:
Protecting motors, drives, and other critical equipment in industrial settings, reducing downtime and preventing damage.

Commercial and Residential Buildings:
Ensuring safety by protecting electrical installations from overloads and short circuits.

Medium Voltage Switchgear

Voltage Level:
1 kV to 36 kV.

Components:
Vacuum circuit breakers, air-insulated switchgear (AIS), gas-insulated switchgear (GIS).

Applications:
Used in utility substations, industrial plants, and commercial buildings to control and protect medium-voltage power distribution.

Example:
Switchgear equipped with vacuum circuit breakers for industrial substations.

Eaton 12kV Switchgear

Switchgear Test Procedures

Visual and Mechanical Inspection:
  1. Verify the unit is clean and all shipping bracing, loose parts, and documentation shipped inside cubicles have been removed.
  2. Inspect physical and mechanical condition.
  3. Inspect anchorage, alignment, grounding, and required area clearances.
  4. Inspect insulators for evidence of physical damage or contaminated surfaces.
  5. Exercise all active components.
  6. Verify correct installation and operation.
    7. low voltage switchgear barrier
    low voltage switchgear barrier
  7. Verify appropriate lubrication on moving current-carrying parts and on moving and sliding surfaces.
  8. Verify operation and sequencing of interlocking systems.
  9. Verify that wiring connections are tight and that wiring is secure to prevent damage during routine operation of moving parts.
  10. Inspect mechanical indicating devices for correct operation.
  11. Perform visual and mechanical inspection of surge arresters
  12. Verify that filters are in place and vents are clear.
Perform visual and mechanical inspection of Instrument Transformers (CTs, VTs)
Perform visual and mechanical Control Power Transformers (CPT)
  1. Inspect for physical damage, cracked insulation, broken leads, tightness of connections, defective wiring, and overall general condition.
  2. Verify that primary and secondary fuse or circuit breaker ratings match drawings.
  3. Verify correct functioning of drawout disconnecting contacts, grounding contacts, and interlocks.
Electrical Tests :
  1. Perform insulation-resistance tests on each bus section, phase-to-phase and phase-to-ground, for one minute in accordance with
    2. NETA Table 100.1
  2. Perform a on each bus section, each phase-to-ground with phases not under test grounded, in accordance with manufacturer’s published data. If manufacturer has no recommendation for this test, it shall be in accordance with The test voltage shall be applied for one minute.
    3. NETA Table 100.2
  3. Perform insulation-resistance tests on control wiring with respect to ground. Applied potential shall be 500 volts dc for 300-volt rated cable and 1000 volts dc for 600-volt rated cable. Test duration shall be one minute. For units with solid-state components or control devices that can not tolerate the applied voltage, follow the manufacturer’s recommendation. (optional)
  4. Perform electrical tests on instrument transformers
  5. Perform ground-resistance tests
  6. Test
    7. Metering
  7. Control Power Transformers
    1. Perform insulation-resistance tests. Perform measurements from winding-to-winding and each winding-to-ground. Test voltages shall be in accordance with Table 100.1 unless otherwise specified by the manufacturer.
    2. Perform a turns-ratio test on all tap positions
    3. Perform secondary wiring integrity test. Disconnect transformer at secondary terminals and connect secondary wiring to a rated secondary voltage source. Verify correct potential at all devices.
    4. Verify correct secondary voltage by energizing the primary winding with system voltage. Measure secondary voltage with the secondary wiring disconnected.
    5. Verify correct function of control transfer relays located in the switchgear with multiple control power sources.
  8. Voltage Transformers
    1. Perform secondary wiring integrity test. Verify correct potential at all devices.
    2. Verify secondary voltages by energizing the primary winding with system voltage.
  9. Perform current-injection tests on the entire current circuit in each section of switchgear.
    1. Perform current tests by secondary injection with magnitudes such that a minimum current of 1.0 ampere flows in the secondary circuit. Verify correct magnitude of current at each device in the circuit.
    2. Perform current tests by primary injection with magnitudes such that a minimum of 1.0 ampere flows in the secondary circuit. Verify correct magnitude of current at each device in the circuit. (optional)
  10. Perform system function tests in accordance with ANSI/NETA ECS.
  11. Verify operation of cubicle switchgear/switchboard
    12. Heater
  12. Perform phasing checks on double-ended or dual-source switchgear to insure correct bus phasing from each source.
  13. Perform electrical tests of surge arresters.
MISC Reference Material
Logic Gates
Logic Gates
Logic Gates
SEL Relays

Time Overcurrent Operating Times (51)








Percent Error Calculator

\( \Large\frac{(X_{Meas}-X_{Calc})}{X_{Calc}} \times 100 \)

SEL Time Overcurrent Equations (51 Function)

Internal Breaker mechanism
Internal Breaker mechanism
Internal Breaker mechanism

Metering Calculator

Input Values

VA
Angle
VB
Angle
VC
Angle
IA
Angle
IB
Angle
IC
Angle
     
I1
I2

Phase Power

Watts:
Vars:
VA:
Watts:
Vars:
VA:
Watts:
Vars:
VA:

Total Power

Watts:
Vars:
VA:
Phase Rotation

Input Values

ABC Rotation

Va = VMAG∠0
Vb = VMAG∠-120
Vc = VMAG∠120

Ia = IMAG∠0
Ib = IMAG∠-120
Ic = IMAG∠120
PHROT: ABC

ACB Rotation

Va = 67∠0
Vb = 67∠-120
Vc = 67∠120

Ia = 2.5∠0
Ib = 2.5∠-120
Ic = 2.5∠120
PHROT: ACB

Delta Configured PT

ABC Rotation

Va (VAB) = 67∠30
Vb = 0∠0
Vc (VBC) = 67∠90

Ia = 2.5∠0
Ib = 2.5∠-120
Ic = 2.5∠120
PHROT: ABC

ACB Rotation

Va = 67∠0
Vb = 67∠-120
Vc = 67∠120

Ia = 2.5∠0
Ib = 2.5∠-120
Ic = 2.5∠120
PHROT: ACB

Example Settings:
PT configuration: WYE, INOM: 5, VNOM: 120, CTR: 240, PTR:100

Total Watts 3P = 3 * 2.5 * 67 * 0.899 * CTR * (PTR/1000)
3P = 10.85MW

Total Vars 3Q = 3 * 2.5 * 67 * 0.438 * CTR * (PTR/1000)
3Q = 5.28 MVARS

WYE Configured PT

ABC Rotation

Va = 67∠0
Vb = 67∠-120
Vc = 67∠120

Ia = 2.5∠0
Ib = 2.5∠-120
Ic = 2.5∠120
PHROT: ABC

ACB Rotation

Va = 67∠0
Vb = 67∠-120
Vc = 67∠120

Ia = 2.5∠0
Ib = 2.5∠-120
Ic = 2.5∠120
PHROT: ACB

Example Settings:
PT configuration: WYE, INOM: 5, VNOM: 120, CTR: 240, PTR:100

Total Watts 3P = 3 * 2.5 * 67 * 0.899 * CTR * (PTR/1000)
3P = 10.85MW

Total Vars 3Q = 3 * 2.5 * 67 * 0.438 * CTR * (PTR/1000)
3Q = 5.28 MVARS

Terminal Commands

=>> SET -n- -m- -s- TERSE

where: G, R, or P = (parameter “n” is not entered for the Group settings).

m = group (1 or 2) or port (1, 2, 3, or F). The relay selects the active group or port if “-m-” is not specified.

s = the name of the specific setting you wish to jump to and begin setting. If “-s-” is not entered, the relay starts at the first setting.

TERSE = instructs the relay to skip the SHOWSET display after the last setting. Use this parameter to speed up the SET command. If you wish to review the settings before saving, do not use the TERSE option.

Password

ACC Access to level 1 commands:
password: OTTER
2AC Access to level 2 commands:
password: TAIL
PAS Show or set passwords
BAC Enter CB access level

Metering Data

MET Display meter data
MET D Display demand and peak
MET RD Reset demand values
MET RP Reset peak values

Adjust Setting Values

SET n Enter group settings
SET G Enter global settings
SET L Set logic (append group #)
SET PSet port (append port #)
SET REdit reporting settings
SET T Edit text settings
COP m n Copy setting group m to n
CON nControl remote bit RBn

Pulse Output Contacts

PUL n k Pulse Output n for k seconds

Show Data

TAR Show target values
SHO n Show settings for group n
SHO C Show calibration settings
SHO G Show global settings
SHO LShow logic (append group #)
SHO P Show port (append port #)
SHO R Show reporting settings
SHO T Show text settings
GRO Display active setting group
GRO n Change the group variable to n
STA Show self-test status

Event Recorder Data

EVE Show event record
SER Show rows of event recorder
SER CClears the Sequential Events
TRI Trigger an event

Clock

DAT Show or set date
IRI Force synchronize clock
TIM Show or set time

Latch Bits

Latch control switches (latch bits are the outputs of these switches) replace traditional latching devices. Traditional latching devices maintain output contact state. The SEL-700G latch control switch also retains state even when power to the device is lost. If the latch control switch is set to a programmable output contact and power to the device is lost, the state of the latch control switch is stored in nonvolatile memory, but the device de-energizes the output contact. When power to the device is restored, the programmable output contact goes back to the state of the latch control switch after device initialization. Traditional latching device output contact states are changed by pulsing the latching device inputs (see Figure 4.141). Pulse the set input to close (set) the latching device output contact. Pulse the reset input to open (reset) the latching device output contact. The external contacts wired to the latching device inputs are often from remote control equipment (for example, SCADA, RTU).

Internal Breaker mechanism
Internal Breaker mechanism
SV Logic Variables(Variables/Timers)

Timers Reset When ower Lost or Settings Changed
If the device loses power or the settings change, the SELOGIC control equation variables/timers reset. Relay Word bits SVn and SVnT (n = 01–32) reset to logical 0 after power restoration or a settings change. Figure 4.145 shows an effective seal-in logic circuit, created by the use of Relay Word bit SV07 (SELOGIC control equation variable SV07) in SELOGIC control equation SV07:

Internal Breaker mechanism

SV/Timers Settings
The SEL-700G includes 32 SELOGIC variables. Table 4.67 shows the pickup, dropout, equation settings, and brief descriptions for SV01–SV12. The factory-default settings for these variables should address most applications. Review the default settings and make any changes necessary to suit your application. The remaining SELOGIC variables are not enabled (see Table 4.62), but they are available for any special needs.

\( I_{NOM} = [\Large \frac{\frac{ \Large MVA \times 1000}{ \Large 1.73 \times kV}}{CTR} ] \)

where:
MVA = generator rated output, MVA
kV = generator rated phase-to-phase voltage, kV
CTR = phase current transformer ratio to one

The relay directional power, negative-sequence overcurrent, and differential elements use the INOM setting.

Input Values
Vnom
Inom
MTA
40Z1P
40XD1
40Z1D
40Z2P
40XD2
40Z2D
Output Values
Zone 1
Angle Voltage Current Impedance
270

0.45 is an arbittrary pick up point
taken at 45% or nominal Voltage

\[V_{T}=V_{nom}*0.45 \]
\[I_{T}=\frac{V_{T}}{D40Z1 -40X1D} \]

Delta:

\[V_{A}= \frac{ V_{T} }{ \sqrt{3} } \]

WYE:

\[V_{A}= \frac{ V_{T} }{ 1 } \]
\[V_{A}=(V_{T} < 0), V_{A}=(V_{T} < 0), V_{A}=(V_{T} < 240) \]
TTR-test-diagram

Nominal Values

  1. Vnom: 118.9V
  2. Inom: 3.9A
  3. MTA: 270

Zone 1 Settings

  1. 40Z1P: 16
  2. 40XD1: 1.6
  3. 40ZD1: 0.1

Zone 2 Settings

  1. 40Z2P: 16
  2. 40XD2: 1.6
  3. 40ZD2: 0.1

Synch Function

A synchronism-check relay verifies that the generator frequency, voltage magnitude, and phase angle match the system frequency, voltage magnitude, and phase angle before allowing the generator breaker to be closed.

Internal Breaker mechanism
Internal Breaker mechanism

Input Voltages

VS voltage
Voltage Source input to measure system voltage. this input is usually connected to the secondary of a phase-to-ground or phase-to-phase connected VT on the system or bus side of the generator circuit breaker

VP voltage
This is usually a phase-to-ground or phase-to-phase connected VT on the generator bus

Voltage Ratio Correction Factor
Word bit : 25RCFX
The 25RCFX setting compensates magnitude differences between the synchronism-check voltage and the generator voltage. Unmatched voltage transformer or step-up transformer ratios can introduce magnitude differences. Use the voltage ratio correction factor setting 25RCFX to compensate nominal magnitude of the phase voltage (selected by the SYNCPX setting) to match the nominal magnitude of the synchronism-check voltage VS.

Voltage Window

Internal Breaker mechanism
Internal Breaker mechanism
V-Window High

Relay Setting:
25VHI (volts)
Word Bit :
59VP, 59VS (Boolean)

V-Window Low

Relay Setting:
25VHI (volts)
Word Bit :
59VP, 59VS (Boolean)

Voltage Diff

Relay Setting:
25VHI (%)
Word Bit :
VDIF (Boolean)

The 25VLO and 25VHI settings define the acceptable system (VS) voltage magnitude window prior to closing the generator breaker. 25VHI must be a higher voltage value than 25VLO. The system and generator voltages must both be greater than 25VLO and less than 25VHI for the synchronismcheck outputs to operate.

Testing
Testing the 25VHI, 25VHI, 25VDIF pick up value is performed by monitoring the 59VP and 59VS bits will assert, or equal boolean value of 1, when your VS and VP voltages are less than the 25VHI, and higher than the 25LO voltage setting values.

VDIF-X/Y pick up test will assert, or equal boolean value of 1, when your VS and VP voltages are with in 3% of each other

Maximum and Minimum Slip Frequency

Max Slip

Relay Setting:
25SHI (Hz)
Word Bit :
SFX (Boolean)

Min Slip

Relay Setting:
25SLO (Hz)
Word Bit :
SFX (Boolean)

These settings define the acceptable slip frequency between the system and the generator prior to closing the generator breaker. 25SHI must be greater than 25SLO.

Internal Breaker mechanism

Synch Blocking
Word bit : BSYNCHX
Default Equation : = NOT 3POX
BSYNCHX SELOGIC control equation should be set so that the function is blocked when the generator main circuit breaker is closed (NOT 3POX).

control equation result equals logical 1. The function is allowed to operate when the BSYNCHX SELOGIC control equation result equals logical 0. Typically, the BSYNCHX SELOGIC control equation should be set so that the function is blocked when the generator main circuit breaker is closed (NOT 3POX). You can add other supervisory conditions if necessary for your application.

Closing Angle Window

Internal Breaker mechanism
Internal Breaker mechanism
Leading Angle

Relay Setting:
25ANG1X (Degrees)
Word Bit :
25AX1 (Boolean)

Lagging Angle

Relay Setting:
25ANG2X (degrees)
Word Bit :
25AX2 (Boolean)

The setting defines an acceptable generator breaker closing angle. The relay asserts the 25AX1 Relay Word bit when the generator voltage is within 25ANG1X degrees of the system voltage if the other supervisory conditions also are met. When the breaker close time setting, TCLOSDX, is nonzero, the relay accounts for the breaker time and present slip frequency to adjust the phase angles where 25AX1 is asserted.

Word bit : 25C
The relay asserts the 25C Relay Word bit for 1/4 cycle to initiate a close. The relay asserts the 25C Relay Word bit to initiate a close when the compensated angle difference equals the CANGLE setting. 25C assertion is timed so that, if the slip remains constant and the breaker closes in TCLOSDX ms, the breaker main contacts close the instant the angle different is equal to CANGLE.

If the relay uses the 25C Relay Word bit to initiate a closure, and the breaker has not closed when the phase angle difference between the generator and system reaches the CFANGLE setting, the relay asserts the BKRCF breaker close failure Relay Word bit. This Relay Word bit typically would be used to close a relay output contact to energize the bus lockout relay. The bus lockout relay would trip all breakers connected to the bus, protecting the generator from the out-of-synchronism close.

CLOSE FAIL INIT
Word bit : CFI
Default Equation : CFI = CLOSEX
The setting defines an acceptable generator breaker closing angle. The relay asserts the 25AX1 Relay Word bit when the generator voltage is within 25ANG1X degrees of the system voltage if the other supervisory conditions also are met. When the breaker close time setting, TCLOSDX, is nonzero, the relay accounts for the breaker time and present slip frequency to adjust the phase angles where 25AX1 is asserted.

The CFI SELOGIC control setting can be used to program breaker close failinitiate conditions. By default, it is programmed to the CLOSEX Relay Word bit and can be programmed to other similar conditions to initiate a close fail.

3POX
The generator is considered running if Relay Word bit 3POX = 0.

Internal Breaker mechanism
Relay Instruction Manuals
Relay Application and Testing Documents

TDURD Minimum Trip Time This timer establishes the minimum time duration for which the TRIP Relay Word bit asserts. This is a rising-edge initiated timer. Trips initiated by the TR Relay Word bit (includes OPEN command from front-panel and serial ports) are maintained for at least the duration of the minimum trip duration time (TDURD) setting.

3POX-Y Pole Open Logic pole open logic for breaker 52X and/or 52Y,

3POX-Y Loss-of-Potential (LOP) Protection Relay Word bit LOPX or LOPY (loss-of-potential) when it detects a loss of either the X or Y-side relay ac voltage input, such as that caused by blown potential fuses or by the operation of molded-case circuit breakers. Because accurate relaying potentials are necessary for certain protection elements (undervoltage 27 elements, for example), you can use the LOP function to supervise these protection elements.

REMTRIP The REMTRIP SELOGIC control equation is intended to define a remote trip condition. For example, the following settings will trip the breaker by input IN303 via REMTRIP.

3POX-Y Loss-of-Potential (LOP) Protection Relay Word bit LOPX or LOPY (loss-of-potential) when it detects a loss of either the X or Y-side relay ac voltage input, such as that caused by blown potential fuses or by the operation of molded-case circuit breakers. Because accurate relaying potentials are necessary for certain protection elements (undervoltage 27 elements, for example), you can use the LOP function to supervise these protection elements.

CL Close Equation Each of the two close logic equations has an associated unlatch close SELOGIC control equation. Once the CLOSE bit is asserted, it is sealed-in until any of the following conditions are true:

Unlatch Close SELOGIC control equation setting ULCLX (or ULCLY) asserts to logical 1.

Relay Word bit 52AX (or 52AY) asserts to logical 1.

Close failure Relay Word bit asserts to logical 1.

52Am and 52Bm (m = X or Y) The relay uses the 52AX Relay Word bit as the status of the breaker in conjunction with the protection elements and the trip and close logic. The default 52Bm setting is NOT 52Am. The factory-default setting assumes no auxiliary contact connection (i.e., 52AX := 0 and 52AY := 0).

Close Failure Logic Each of the two close logic equations includes a close failure detection with an associated delay setting CFDX and CFDY. Set the close failure delay (setting CFD) equal to the highest breaker close time plus a safety margin. If the breaker fails to close, the Relay Word CFX (or CFY) asserts for 1/4 cycle. Use the CF bit as necessary.

Close Failure Logic Each of the two close logic equations includes a close failure detection with an associated delay setting CFDX and CFDY. Set the close failure delay (setting CFD) equal to the highest breaker close time plus a safety margin. If the breaker fails to close, the Relay Word CFX (or CFY) asserts for 1/4 cycle. Use the CF bit as necessary.

GE Relays

Time Overcurrent Operating Times (51)








Percent Error Calculator

\( \Large\frac{(X_{Meas}-X_{Calc})}{X_{Calc}} \times 100 \)

GE Time Overcurrent Equations (51 Function)

Internal Breaker mechanism
Internal Breaker mechanism
Internal Breaker mechanism

Setting is a % of Rated MW
Reverse Power Trip Level: 0.15 of Rated MW

GEN. PARAMETERS Generator Rated MVA 2.500 MVA
Generator Rated Power Factor 0.80
Generator Voltage Phase-Phase 4160 V
Generator Nominal Frequency 60 Hz
Generator Phase Sequence ABC

Given:
CURRENT SENSING

Phase CT Primary 400 A

VOLTAGE SENSING VT Connection Type
Transformer Ratio 35 :1

MW = MVA Rating * power factor Rating
MW_pick up= Pickup_setpoint * MW
I_pick up= MW_pick up/(Volts *1.732)
Op I_pu = I_pick up/ CTR

MW = 2500MVA * 0.8= 2000MW
MW_pick up= 0.15 * 2000kW = 300kW
I_pick up= 300kW/(4.16kV *1.732) =72A
Op I_pu = 72A/ 80 = 0.52

Trip Current = 0.52A

Current Sensing
Phase CT Primary 400 A
Phase CT Secondary 5 A

Voltage Sensing
VT Connection Type
Transformer Ratio 35 :1

Gen. Parameters:
Generator Rated MVA 2.500 MVA
Generator Rated Power Factor 0.80
Generator Voltage Phase-Phase 4160 V
Generator Nominal Frequency 60 Hz
Generator Phase Sequence ABC

Negative Sequence Settings:
Neg. Sequence O/C Trip Pickup: 19 % FLA
Neg. Sequence O/C Constant k: 10
Neg. Sequence O/C Max. Time: 60 s
Neg. Sequence O/C Reset Rate: 300.0 s

Setting is a % of FLA
Reverse Power Trip Level: 19% of FLA (secondary)

IA
Angle
IB
Angle
IC
Angle
Gen FLA
I2
% I Neg. Seq

\( Gen \; FLA =\frac{ MVA}{ \sqrt{3} \times V_{pp} }\)

\( I_{Neg \; Seq} = \frac{1}{3} (I_{a} + a^2I_{b} + aI_{c}) \)

\( I_{pickup} = 3 * I_{FLA\; (sec)} * \frac{Neg.Seq-Set}{100} \)

NORM_VOLTS = Generator_Voltage_Phase_Phase / Transformer_Ratio / SQR(3)
TEST_VOLTS = (NORM_VOLTS * Inadvertent_Energize_U_V_Pickup) *.1

Negative-Sequence Inverse Time Curves

\( K = (I_{2})^{2} \times T \)

K = constant from generator manufacturer depending on size and design;
I2 = negative sequence current as a percentage of generator rated FLA as measured at the output CTs;
T = time in seconds when I2 > pickup (minimum 250 ms, maximum defined by setpoint).

Internal Breaker mechanism

Current Sensing
Phase CT Primary 400 A
Phase CT Secondary 5 A

Voltage Sensing
VT Connection Type
Transformer Ratio 35 :1

Gen. Parameters:
Generator Rated MVA 2.500 MVA
Generator Rated Power Factor 0.80
Generator Voltage Phase-Phase 4160 V
Generator Nominal Frequency 60 Hz
Generator Phase Sequence ABC

Negative Sequence Settings:
Neg. Sequence O/C Trip Pickup: 19 % FLA
Neg. Sequence O/C Constant k: 10
Neg. Sequence O/C Max. Time: 60 s
Neg. Sequence O/C Reset Rate: 300.0 s

Setting is a % of FLA
Reverse Power Trip Level: 19% of FLA (secondary)

CT Sec.
87 PU
SLP1
SLP2
IX
Angle
IY
Angle
SLP1 PU
SLP2 PU
Internal Breaker mechanism
MISC Reference Material
Logic Gates
Logic Gates
Logic Gates
Relay Instruction Manuals
Relay Application and Testing Documents
NETA Test Procedure

NETA ATS-2017

7.9.1 Protective Relays, Electromechanical and Solid-State

A. Visual and Mechanical Inspection:
  1. Compare equipment nameplate data with drawings and specifications.
  2. Inspect relays and cases for physical damage. Remove shipping restraint material.
  3. Verify the unit is clean.
  4. Inspect the unit.
  5. A. Relay Case
    1. Tighten case connections.
    2. Inspect cover for correct gasket seal.
    3. Inspect shorting hardware, connection paddles, and knife switches.
    4. Remove any foreign material from the case.
    5. Verify target reset.
    6. Clean cover glass.
  6. B. Relay
    1. Inspect relay for foreign material, particularly in disk slots of the damping and electromagnets.
    2. Verify disk clearance. Verify contact clearance and spring bias.
    3. Inspect spiral spring convolutions.
    4. Inspect disk and contacts for freedom of movement and correct travel.
    5. Verify tightness of mounting hardware and connections.
    6. Burnish contacts.
    7. Inspect bearings and pivots.
  7. Verify that all settings are in accordance with coordination study or setting sheet supplied by owner.
B. Electrical Tests:
  1. Perform an insulation-resistance test on each circuit-to-frame. Procedures for performing insulation-resistance tests on solid-state relays shall be determined from the relay manufacturer’s published data.
  2. Test targets and indicators.
    1. Determine pickup and dropout of electromechanical targets.
    2. Verify operation of all light-emitting diode indicators.
    3. Set contrast for liquid-crystal display readouts.
  1. Protection Elements
  2. Timing Relay (2/62)
    1. Determine time delay.
    2. Verify operation of instantaneous contacts.
  3. Distance Relay (21)
    1. Determine maximum reach.
    2. Determine maximum torque angle and directional characteristic.
    3. Determine offset.
    4. Plot impedance circle.
  4. Volts/Hertz Relay (24)
    1. Determine pickup frequency at rated voltage.
    2. Determine pickup frequency at a second voltage level.
    3. Determine time delay.
  5. Sync Check Relay (25)
    1. Determine closing zone at rated voltage.
    2. Determine maximum voltage differential that permits closing at zero degrees.
    3. Determine live line, live bus, dead line, and dead bus set points.
    4. Determine time delay.
    5. Determine advanced closing angle.
    6. Verify dead bus/live line, dead line/live bus and dead bus/dead line control functions.
  6. Undervoltage Relay (27)
    1. Determine dropout voltage.
    2. Determine time delay.
    3. Determine time delay at a second point on the timing curve for inverse time relays.
  7. Directional Power Relay (32)
    1. Determine minimum pickup at maximum torque angle.
    2. Determine tripping zone.
    3. Determine maximum torque angle.
    4. Determine time delay.
    5. Verify time delay at a second point on the timing curve for inverse time relays.
    6. Plot the operating characteristic.
  8. Loss of Field (Impedance) Relay (40)
    1. Determine maximum reach.
    2. Determine maximum torque angle.
    3. Determine offset.
    4. Plot impedance circle.
  9. Current Balance Relay (46)
    1. Determine pickup of each unit.
    2. Determine percent slope.
    3. Determine time delay.
  10. Negative Sequence Current Relay (46N)
    1. Determine negative sequence alarm level.
    2. Determine negative sequence minimum trip level.
    3. Determine maximum time delay.
    4. Verify two points on the (I2)2t curve.
  11. Phase Sequence or Phase Balance Voltage Relay (47)
    1. Determine positive sequence voltage to close the normally open contact.
    2. Determine positive sequence voltage to open the normally closed contact (undervoltage trip).
    3. Verify negative sequence trip.
    4. Determine time delay to close the normally open contact with sudden application of 120 percent of pickup.
    5. Determine time delay to close the normally closed contact upon removal of voltage when previously set to rated system voltage.
  12. Thermal Replica Relay (49R)
    1. Determine time delay at 300 percent of setting.
    2. Determine a second point on the operating curve.
    3. Determine pickup.
  13. Temperature (RTD) Relay(49T)
    1. Determine trip resistance.
    2. Determine reset resistance.
  14. Instantaneous Overcurrent Relay (50)
    1. Determine pickup.
    2. Determine dropout.
    3. Determine time delay.
  15. Breaker Failure (50BF)
    1. Determine current supervision pickup.
    2. Determine time delays.
    3. Test all inputs and outputs.
  16. Time Overcurrent (51)
    1. Determine minimum pickup.
    2. Determine time delay at two points on the time current curve.
  17. Power Factor Relay (55)
    1. Determine tripping angle.
    2. Determine time delay.
  18. Overvoltage Relay (59)
    1. Determine overvoltage pickup.
    2. Determine time delay to close the contact with sudden application of 120 percent of pickup.
  19. Voltage Balance Relay (60)
    1. Determine voltage difference to close the contacts with one source at rated
    2. Plot the operating curve for the relay.
  20. Transformer Sudden Pressure Relay (63)
    1. Determine rate-of-rise or the pickup level of suddenly applied pressure in accordance with manufacturer’s published data.
    2. Verify operation of the 63 FPX seal-in circuit.
    3. Verify trip circuit to remote operating device.
  21. Ground Detector Relay (64)
    1. Determine maximum impedance to ground causing relay pickup.
  22. Directional Overcurrent Relay (67)
    1. Determine directional unit minimum pickup at maximum torque angle.
    2. Determine tripping zone.
    3. Determine tripping zone.
    4. Determine maximum torque angle.
    5. Plot operating characteristics.
    6. Determine overcurrent unit pickup.
    7. Determine overcurrent unit time delay at two points on the time current curve.
  23. Reclosing Relay (79)
    1. Determine time delay for each programmed reclosing interval.
    2. Verify lockout for unsuccessful reclosing.
    3. Determine reset time.
    4. Determine close pulse duration.
    5. Verify instantaneous overcurrent lockout.
  24. Frequency Relay (81)
    1. Verify frequency set points.
    2. Determine time delay.
    3. Determine undervoltage cutoff.
  25. Pilot Wire Monitor (85)
    1. Determine overcurrent pickup.
    2. Determine undercurrent pickup.
    3. Determine pilot wire ground pickup level.
  26. Differential (87)
    1. Determine operating unit pickup.
    2. Determine the operation of each restraint unit.
    3. Determine slope.
    4. Determine harmonic restraint.
    5. Determine instantaneous pickup.
    6. Plot operating characteristics for each restraint.
  1. Control Verification/Functional Tests
    1. Verify that each of the relay contacts performs its intended function in the control scheme including breaker trip tests, close inhibit tests, 86 lockout tests, and alarm functions.
C. Test Values – Visual and Mechanical
Relay Case
  1. Case connections shall be torqued in accordance with manufacturer’s published data.
  2. Cover gasket shall be intact and able to prevent foreign matter from entering the case.
  3. Cover glass, connection paddles, and/or knife switches shall be clean.
  4. Case shall be free of foreign material.
  5. The target reset shall be operational.
Relay
  1. Relay shall be free of foreign material.
  2. Relay disc clearance, contact clearance, and spring bias shall operate in accordance with manufacturer’s published data.
  3. Relay spiral spring shall be concentric.
  4. Relay discs and contacts shall have freedom of movement and correct travel distance in accordance with manufacturer’s published data.
  5. Mounting hardware and connections shall be tightened to the manufacturer’s recommended torque values.
  6. Contacts shall be clean and make good contact with each other
  7. Bearings and pivots shall have clean and fluid movement.
Relay settings shall match the coordination study or setting sheet supplied by owner.
D. Test Values – Electrical
  1. Insulation-resistance values shall be in accordance with manufacturer’s published data. Values of insulation resistance less than the manufacturer’s recommendations shall be investigated.
  2. Targets and Indicators
    1. Pickup and dropout of electromechanical targets shall be in accordance with manufacturer’s published data.
    2. Light-emitting diodes shall illuminate.
  3. Operation of protection elements for devices listed in Section 7.9.1.B, one through 25, shall be calibrated using manufacturer’s recommended tolerances unless critical test points are specified by the setting engineer.
  4. Control Verification
    1. Control verification outputs and protection schemes shall operate as per the design. Results shall be within the manufacturer’s published tolerances.
    2. When critical test points are specified, the relay shall be calibrated to those points even though other test points may be out of tolerance.

NETA ATS-2017

7.9.2 Protective Relays, Microprocessor-Based

A. Visual and Mechanical Inspection:
  1. Record model number, style number, serial number, firmware revision, software revision, and rated control voltage.
  2. Verify operation of light-emitting diodes, display, and targets.
  3. Record passwords for all access levels.
  4. Clean the front panel and remove foreign material from the case.
  5. Check tightness of connections.
  6. Verify that the frame is grounded in accordance with manufacturer’s instructions.
  7. Set the relay in accordance with the engineered setting file and coordination study.
  8. Download settings and logic from the relay and compare the settings to those specified in the coordination study or setting sheet supplied by owner.
  9. Connect backup battery.
  10. Set clock if not controlled externally and verify relay displays the correct date and time.
  11. Check with setting engineer for applicable firmware updates and product recalls.
  12. Inspect, clean, and verify operation of shorting devices.
B. Electrical Tests:
  1. Perform insulation-resistance tests from each circuit to the grounded frame in accordance with manufacturer’s published data.
  2. Apply voltage or current to all analog inputs and verify correct registration of the relay meter functions.
  3. Verify SCADA metering values at remote terminals.
  4. Protection Elements
    1. Check functional operation of each element used in the protection scheme as described for electromechanical and solid-state relays in 7.9.1.B.3. When not otherwise specified, use manufacturer’s recommended tolerances.
  5. Control Verification
    1. Check operation of all active digital inputs.
    2. Check all output contacts or SCRs, preferably by operating the controlled device such as circuit breaker, auxiliary relay, or alarm.
    3. Check all internal logic functions used in the protection scheme.
    4. For pilot schemes, perform a loop-back test to check the receive and transmit communication circuits.
    5. Upon completion of testing, reset all min/max records and fault counters. Delete sequence-of-events records and all event records.
    6. Verify trip and close coil monitoring functions.
    7. Verify setting change alarm to SCADA.
    8. Verify relay SCADA communication and indications such as protection operate, protection fail, communication fail, fault recorder trigger.
    9. Verify all communication links are operational.
C. Test Values – Visual and Mechanical
  1. Light-emitting diodes, displays, and targets should illuminate.
  2. Relay should be clean and operational.
  3. Settings and logic should agree with the most recent engineered setting files.
  4. Verify relay displays the correct date and time.
D. Test Values – Electrical
  1. Insulation-resistance values should be in accordance with manufacturer’s published data. Values of insulation resistance less than manufacturer’s recommendations should be investigated.
  2. Voltage and current analog readings should be in accordance with manufacturer’s published tolerances.
  3. SCADA readings should be within the manufacturer’s published tolerances.
  4. Operation of protection elements should be operational and within manufacturer’s recommended tolerances.
  5. Control verification inputs, outputs, and protection schemes should operate as per the design. Results should be within the manufacturer’s published tolerances.

NETA ATS-2019

7.9.2 Protective Relays, Microprocessor-Based

A. Visual and Mechanical Inspection:
B. Electrical Tests:
C. Test Values – Visual and Mechanical
D. Test Values – Electrical

NETA ATS-2019

7.9.2 Protective Relays, Microprocessor-Based

A. Visual and Mechanical Inspection:
B. Electrical Tests:
C. Test Values – Visual and Mechanical
D. Test Values – Electrical
Neta Table 100.5
Neta Table 100.2
Neta Table 100.5
Neta Table 100.5